ML092510256
| ML092510256 | |
| Person / Time | |
|---|---|
| Site: | Vogtle  |
| Issue date: | 04/30/2009 |
| From: | Westinghouse |
| To: | Office of Nuclear Reactor Regulation |
| References | |
| WCAP-17071-NP, Rev 0 | |
| Download: ML092510256 (25) | |
Text
Attachment 3 Corrected Pages for WCAP-17071-NP (Non-Proprietary)
Corrected Pages for WCAP-17071-NP (Non-Proprietary)
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 hi and h2 was defined in Equation (1-1):
F= (h2 -h,)FHE +
ddfhrP dh
.,nI (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,
ýt
=
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 hi and h2:
a,c,e K
1 (1-2)
Where the other parameters in Equation (1-2) are the same as in Equation (1-1) and
]ac"c A detailed explanation of the WCAP-17071-NP April 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 hi and h2 was defined in Equation (1-1):
(1-1) where:
F HE 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, f.l 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 hi and h2:
a,c,e
[
]
(1-2)
Where the other parameters in Equation (1-2) are the same as in Equation (1-1) and [
]a,c,c A detailed explanation of the April 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:
h, F, =,u 7d Pdh
/71 (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,uK, the resistance per unit length, multiplied by L, or by integrating the incremental resistance, dR =/.K dL over the length L, i.e.,
R = K (L2 -LI)=,4 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 = a0 + alPc (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, K = ea-+aP, (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-17071-NP April 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:
h, F; = Jurd JPdh (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, Pc, 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 j.LK, the resistance per unit length, multiplied by L, or by integrating the incremental resistance, dR = j.LK dL over the length L, i.e.,
R = ;1K (L2 - LI ) = f1 l' K dL
["
(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.,
(1-5) where the coefficients, ao and a 1 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-1707l-NP April 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).
a,c,e Pressure is not applied to the Applying pressure to the (see Section 6.2.2.2.4).
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 a,c,]..
(see Section 6.2.5).
2250 (NOP conditions).
(e eto
)
WCAP-17071-NP April 2009 Revision 0 1-13 Table 1-1 List of Conservatisms in the H* Structural and Leakage Analysis (Continued)
Assumption! Approach A[
]a,c,e Pressure is not applied to the
[
]a,c,e The radius dependent stiffness analysis ignores the presence of the [
]a,c,e The tubesheet bore dilation [
Ja,c,e 2250 (NOP conditions).
WCAP-17071-NP Why Conservative?
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).
Applying pressure to the [
a,c,e (see Section 6.2.2.2.4).
Including these structures in the analysis would reduce the tube sheet displacement and limit the local deformation of the tubesheet hole ID (see Section 6.2.4.4).
Thermal expansions under operating loads were [
]",c,e (see Section 6.2.5).
April 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 the bounding Model F plant (Millstone Unit 3) 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.
IAOperating Condition kp
(
(Ppri-Area (in)
EnLoadCap Factor of H*Designcap (Note 1)
(lbs.)
Safety Load (Lbs.)
Normal Op. (maximum)
Faulted (FLB)
Faulted (SLB)
Faulted (Locked Rotor)
Faulted (Control Rod Ejection)
Notes:
- 1.
Tubesheet Bore Cross-Sectional Area =
]a,c,c 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 faulted condition end cap loads will not vary from plant to plant among the Model F population for the postulated FLB for 3-and 4-loop plants because the specified transient for both is the same. The value for end cap load for a 3-loop plant is different than the value for a 4-loop plant for a postulated SLB event and is also provided above. The values vary only slightly for the locked rotor event and control rod ejection event from plant to plant (see Table 5-6).
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 FLB/SLB transient. For plants that have a locked rotor 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.
a,c,e WCAP-17071-NP April 2009 Revision 0 5-3 5.3 CALCULATION OF APPLIED END CAP LOADS The tube pull out loads l (also called end cap loads) to be resisted during normal operating (NOP) and faulted conditions for the bounding Model F plant (Millstone Unit 3) 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.
dP (psi) (P pri-Area (in2)
End Cap Factor of H* Design Operating Condition Load End Cap Psce)
(Note 1)
(lbs.)
Safety Load (Lbs.)
r-Normal Op. (maximum)
Faulted (FLB)
)
Faulted (SLB)
Faulted (Locked Rotor)
Faulted (Control Rod Ejection)
Notes:
- 1.
Tubesheet Bore Cross-Sectional Area =1 t,e,e 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 tube sheet bore mean diameter is assumed.
The faulted condition end cap loads will not vary from plant to plant among the Model F population for the postulated FLB for 3-and 4-1oop plants because the specified transient for both is the same. The value for end cap load for a 3-100p plant is different than the value for a 4-100p plant for a postulated SLB event and is also provided above. The values vary only slightly for the locked rotor event and control rod ejection event from plant to plant (see Table 5-6).
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 FLB/SLB transient. For plants that have a locked rotor I 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-17071-NP April 2009 Revision 0 a,c,e
5-4 with stuck open PORV transient included as part of the licensing basis, this event is bounded by the FLB/SLB event because the peak pressure during this transient is significantly less than that of the SLB/FLB transient.
WCAP-17071-NP April 2009 Revision 0 5-4 with stuck open PORV transient included as part of the licensing basis, this event is bounded by the FLB/SLB event because the peak pressure during this transient is significantly less than that of the SLB/FLB transient.
WCAP-17071-NP April 2009 Revision 0
5-5 Table 5-7 Operating Conditions - Model F H* Plant Plant Parameter and Units Salem Millstone [ Seabrook Vogtle Wolf Creek (5)
Vandellos 11(6)
Unit 1(1)
Unit 3(2)
Unit 1(3)
Units 1 and 2(4)
Power -
NSSS MWt 3471 3666 3678 3653 3579 2954 NSSS Primary Pressre psia 2250 2250 2250 2250 2250 2250 Pressure Secondary Psia (Low a,c,c Pressure Tavg/High Tavg)
Reactor
'F (Low Vessel Outlet Tavg/High Temperature Tavg)
SG Primary-to-Secondary Psid (Low Pressure Tavg/High Differential Tavg)
(psid)
I I
I
()
PCWG-2635, Revision 1, Salem Units 1 and 2 (PSE/PNJ): Approval of Category IV (for Implementation) and IVP (for Limited Implementation) PCWG Parameters to Support 1.4% Uprate, 2/8/05.
(2)
PCWG-06-9, Millstone Unit 3 (NEU): Approval of Category II (for Contract) PCWG Parameters to Support a 7% Stretch Power Uprate (SPU) Program, 4/25/06.
(3)
PCWG-08-68, Seabrook Unit 1 (NAH): Approval of Category IV PCWG Parameters to Support a 7.4% Uprate Program, 11/7/08.
(4)
PCWG-05-49, Vogtle Units 1 and 2 (GAE/GBE): Approval of Category III (for Contract) PCWG Parameters to Support a 2%
Measurement Uncertainty Recapture (MUR) Uprate, 11/ 18/05.
(5)
PCWG-2417, Wolf Creek Unit 1 (SAP): Approval of Category IVP Parameters to Support a Best Estimate Flow for Reactor Coolant Pump (RCP) Replacement, 6/17/99.
(6)
PCWG-06-15, Revision 1, Vandellos Unit II (EAS): Approval of Category IVP PCWG Parameters to Support a Tavg Range Program, 6/15/06.
WCAP-17071-NP April 2009 Revision 0 5-5 Table 5-7 Operating Conditions - Model F H* Plant Plant Parameter and Units Salem Millstone Seabrook Vogtle WolfCreek (5)
Vandellos n(6)
Unit 1 (I)
Unit 3(2)
Unit 1 (3)
Units 1 and i4)
Power -
MWt 3471 3666 3678 3653 3579 2954 NSSS Primary pSla 2250 2250 Pressure 2250 2250 2250 2250 Psia (Low r-a,C,C Secondary Tay/High Pressure Tayg)
Reactor of (Low Vesse! Outlet Tay/High Temperature Tayg)
SG Primary-to-Secondary Psid (Low Pressure Tay/High Differential Tayg)
(psi41 (I)
PCWG-2635, Revision 1, Salem Units 1 and 2 (PSE/PNJ): Approval of Category IV (for Implementation) and IVP (for Limited Implementation) PCWG Parameters to Support 1.4% Uprate, 2/8/05.
(2)
PCWG-06-9, Millstone Unit 3 (NEU): Approval of Category II (for Contract) PCWG Parameters to Support a 7% Stretch Power Uprate (SPU) Program, 4/25/06.
(3)
PCWG-08-68, Seabrook Unit 1 (NAH): Approval of Category IV PCWG Parameters to Support a 7.4% Uprate Program, 11/7/08.
(4)
PCWG-05-49, Vogtle Units 1 and 2 (GAE/GBE): Approval of Category III (for Contract) PCWG Parameters to Support a 2%
Measurement Uncertainty Recapture (MUR) Uprate, 11118/05.
(5)
PCWG-2417, WolfCreek Unit 1 (SAP): Approval of Category IVP Parameters to Support a Best Estimate Flow for Reactor Coolant Pump (RCP) Replacement, 611 7/99.
(6)
PCWG-06-15, Revision 1, Vandellos Unit II (EAS): Approval of Category IVP PCWG Parameters to Support a Tayg Range Program, 6/15/06.
WCAP-17071-NP April 2009 Revision 0
5-6 Table 5-8 Steam Line Break Conditions Parameters and Units a,c,e Peak Primary-Secondary Pressure (psig)
Primary Fluid Temperature (°F) (HL and CL)
]
Secondary Fluid Temperature ('F) (HL and CL)
II
() Three-loop plant, all other Model F H* plants are 4-loop plants.
HlL - Hot Leg CL - Cold Leg WCAP-17071-NP April 2009 Revision 0 5-6.
Table 5-8 Steam Line Break Conditions Salem Unit 1 Millstone Seabrook Parameters and Units Unit 3 Unit 1 Peak Primary-Secondary Pressure (psig)
Primary Fluid Temperature (OF) (HL and CL)
Secondary Fluid Temperature (OF) (HL and CL)
(1)
Three-loop plant, all other Model F H* plants are 4-loop plants.
HL-Hot Leg CL-Cold Leg WCAP-l707l-NP Vogtle Units WolfCreek land 2 Vandellos n(l)
April 2009 Revision 0 a,c,e 1
5-7 Table 5-9 Feedwater Line Break Conditions 3 Parameters and Units Salem Unit 1 Millstone Unit Seabrook Vogtle Units Wolf Creek Vandellos II 3
Unit I I and 2 Peak Primary-Secondary Pressure (psig)
F ac, Primary Fluid Temperature (°F)(I) (HL/CL)
Secondary Fluid Temperature (OF)(') (HL and CL)
Primary Fluid Temperature ('F)(2) (HL/CL)
Secondary Fluid Temperature (°F)( 2) (HL and CL)
I (1)
Low Tavg (2)
High Ta,,vg (3)
The pressures and temperatures included in this table for a postulated FLB are used for the structural analysis and are based on the SG design specification transient. The pressure and temperatures used for the leakage analysis for FLB are identified in Section 9.0 of this report.
HL - Hot Leg CL - Cold Leg WCAP-17071 -NP April 2009 Revision 0 5-7 Table 5-9 Feedwater Line Break Conditions3 Parameters and Units Salem Unit 1 Millstone Unit Seabrook V ogtle Units WolfCreek Vandellos II 3
Unit 1 1 and 2 Peak Primary-Secondary Pressure (psig)
Primary Fluid Temperature (OFi l ) (HLlCL)
Secondary Fluid Temperature (oF)(I) (HL and CL)
Primary Fluid Temperature (OFP) (HLlCL)
Secondary Fluid Temperature (OFP) (HL and CL)
(I)
Low Tavg (2)
High Tavg (3)
The pressures and temperatures included in this table for a postulated FLB are used for the structural analysis and are based on the SG design specification transient. The pressure and temperatures used for the leakage analysis for FLB are identified in Section 9.0 of this report.
HL-Hot Leg CL - Cold Leg WCAP-17071-NP April 2009 Revision 0 a,c,c
5-8 Table 5-10 Locked Rotor Event Conditions Salem Unit I Millstone Seabrook Vogtle Units 1 Wolf Creek Vandellos II Par m et rs a d
~ ntsU nit 3 U nit I and 2 Peak Primary-Secondary Pressure (psig)
Primary Fluid Temperature (OF)(1)
(HL/CL)
Secondary Fluid Temperature (°F)(' (HL and CL)
Primary Fluid Temperature (°F)( 2) (HL/CL)
Secondary Fluid Temperature (°F)(2) (HL and CL)
(1)
Low Tavg (2)
HighTavg HL - Hot Leg CL - Cold Leg ace WCAP-17071-NP April 2009 Revision 0 5-8 Parameters and Units Peak Primary-Second1\\!Y Pressure (psig)
Primary Fluid Temperature (OFP) (HLlCL)
Secondary Fluid Temperature (OF)(I) (HL and CL)_
Primary Fluid Temperature (OFP) (HLlCL)
Secondary Fluid Temperature (OF)(2) (HL and CL)_
(I)
Low Tavg (2)
HighTavg HL-Hot Leg CL-Cold Leg WCAP-1707l-NP Table 5-10 Locked Rotor Event Conditions Salem Unit 1 Millstone Seabrook Unit 3 Unit 1
~
~
Vogtle Units 1 WolfCreek and 2 Vandellos II April 2009 Revision 0 a,c,e
5-9 Table 5-11 Control Rod Ejection Parameters and Units Salem Unit 1 Millstone Seabrook r Vogtle Units Wolf Cre Unit 3 Unit 1 l and 2 ek Vandellos II Peak Primary-Secondary Pressure (psig)
Primary Fluid Temperature (°F)(1) (HL/CL)
Secondary Fluid Temperature (°F)(1) (HL and CL)
Primary Fluid Temperature (°F)(2) (HL/CL)
Secondary Fluid Temperature (°F)(2) (HL and CL)
(1)
Low Tavg (2)
High Tavg HL - Hot Leg CL - Cold Leg a,c,e WCAP-17071-NP April 2009 Revision 0 Parameters and Units Peak Primary-Secondary Pressure (psig)
Primary Fluid Temperature (OFi l ) (HLlCL)
Secondary Fluid Temperature (OFil ) (HL and CL)
Primary Fluid Temperature (OFi2) (HLlCL)
Secondary Fluid Temperature (OFP) (HL and CL)
(I)
Low Tavg (2)
High Tavg HL-HotLeg CL-ColdLeg WCAP-17071-NP Table 5-11 Control Rod Ejection Salem Unit 1 Millstone Seabrook Unit 3 Unit 1 r--
Vogtle Units WolfCreek 1 and 2 5-9 Vandellos II April 2009 Revision 0 a,c,e
5-10 Table 5-12 Design End Cap Loads for Normal Operating Plant Conditions, Locked Rotor and Control Rod Ejection for Model F 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)
(lbf)
(lbf)
Salem Unit 1 a,c,e Millstone Unit 2 Seabrook Vogtle Units 1 and 2 Wolf Creek Vandellos II WCAP-17071-NP April 2009 Revision 0 5-10 Table 5-12 Design End Cap Loads for Normal Operating Plant Conditions, Locked Rotor and Control Rod Ejection for Model F Plants Low Tavg Plant End Cap Load w(Safety Factor (lbf) r-Salem Unit I Millstone Unit 2 Seabrook Vogtle Units 1 and 2 WolfCreek Vandellos II L...-
WCAP-17071-NP High Tavg End Cap Load Locked Rotor w(Safety Factor End Cap Load (lbf)
(lbf)
Control Rod Ejection End Cap Load (lbf) a,c,e April 2009 Revision 0
6-10 Therefore, hnomina! = [
]... inch (i.e., [
]a.c.. and Tj = [
]a,,,, 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* /E P
V E1 1/E
=
Vd
=
E*/E
=
V L
Elastic modulus of solid E
material a,c,e where the subscripts p and d refer to the pitch and diagonal 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) for 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 and Figure 6-3 are screen shots of the three-dimensional solid model of the Model F SG. Figure 6-4 shows the entire 3D model mesh.
WCAP-17071-NP April 2009 Revision 0 6-10 Therefore, hnominal = (
)",e,e inch (i.e., (
)",e,c and 11 = (
]a,e,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 E* / E p
E* / E d
E* / E v
E Value Elastic modulus of solid material a,c,e where the subscripts p and d refer to the pitch and diagonal 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: I) 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) for 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 and Figure 6-3 are screen shots of the three-dimensional solid model of the Model F SG. Figure 6-4 shows the entire 3D model mesh.
WCAP-17071-NP April 2009 Revision 0
6-18 a,c,e K
with the elasticity coefficients calculated as:
Li El I
a,c,eI I
a,c,e I
a,c,e LI I
ace and a,c,e I
I I
a,c,e and LI
]
a,c,e where The variables in the equation are:
=
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 pitch direction, G =
Effective shear modulus for transverse shear loading, Ed
=
Effective shear modulus for in-plane loading in the diagonal direction, Vd
=
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 rRz
=
Transverse shear stress,
[D] =
Elasticity coefficient matrix required to define the anisotropy of the material.
WCAP-17071-NP April 2009 Revision 0 6-18 with the elasticity coefficients calculated as:
[
[
[
[
[
where The variables in the equation are:
a,c,e J
l
]
a,c,e a,c,e
]
and [
]
]
a,c,e
[
and E P Effective elastic modulus for in-plane loading in the pitch direction, E:
Effective elastic modulus for loading in the thickness direction, v;
Effective Poisson's ratio for in-plane loading in the thickness direction, G;
Effective shear modulus for in-plane loading in the pitch direction, Gz*
Effective shear modulus for transverse shear loading, If; Effective shear modulus for in-plane loading in the diagonal direction, a,c,e a,c,e a,c,e
]
a,c,e 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 TRZ Transverse shear stress,
[D]
Elasticity coefficient matrix required to define the anisotropy of the material.
WCAP-17071-NP April 2009 Revision 0
6-21 Table 6-6 Summary of H* Millstone Unit 3 Analysis Mean Input Properties Plant Name Millstone Unit 3 Plant Alpha NEU Plant Analysis Type Hot Leg SG Type F
Input Value Unit Reference Accident and Normal Temperature Inputs NOP Thot
__--]
a,c,e oF PCWG-06-9 NOP TIow OF PCWG-06-9 SLB TS AT OF 1.3F SLB CH AT OF 1.3F Shell AT OF PCWG-06-9 FLB Primary AT Hi OF 1.3F FLB Primary AT Low OF 1.3F SLB Primary AT OF 1.3F SLB Secondary AT OF 1.3F Secondary Shell AT Hi OF 1.3F Secondary Shell AT Low OF 1.3F Cold Leg AT OF PCWG-06-9 Hot Standby Temperature OF PCWG-06-9 Operating Pressure Input Faulted SLB Primary Pressure a,.,
psig 1.3F Faulted FLB Primary Pressure psig 1.3F Normal Primary Pressure 2235.0 psig PCWG-06-9 Cold Leg AP a,C,e psig PCWG-06-9 NOP Secondary Pressure -
psig PCWG-06-9 Low NOP Secondary Pressure - Hi psi_
PCWG-06-9 Faulted FLB Secondary psig 1.3F Pressure Faulted SLB Secondary psig 1.3F Pressure WCAP-17071-NP April 2009 Revision 0 6-21 Table 6-6 Summary ofH* Millstone Unit 3 Analysis Mean Input Properties Plant Name Millstone Unit 3 Plant Alpha NEU Plant Analysis Type Hot Leg SG Type F
Input Value Unit Accident and Normal Temperature Inputs NOP Thol a,c,e of NOP T\\ow of SLB TS ~T of SLBCH~T of Shell ~T OF FLB Primary ~ T Hi of FLB Primary ~ T Low of SLB Primary~ T of SLB Secondary ~ T OF Secondary Shell ~ T Hi OF Secondary Shell ~ T Low of Cold Leg ~T of Hot Standby Temperature of Operating Pressure Input Faulted SLB Primary Pressure I
l 3,C,C psig Faulted FLB Primary Pressure L
~
psig Normal Primary Pressure 2235.0 psig Cold Leg ~P a,c,e psig NOP Secondary Pressure -
pSlg Low NOP Secondary Pressure - Hi psig Faulted FLB Secondary pSlg Pressure Faulted SLB Secondary pSlg Pressure WCAP-17071-NP Reference PCWG-06-9 PCWG-06-9 1.3F 1.3F PCWG-06-9 1.3F 1.3F 1.3F 1.3F 1.3F 1.3F PCWG-06-9 PCWG-06-9 1.3F 1.3F PCWG-06-9 PCWG-06-9 PCWG-06-9 PCWG-06-9 1.3F 1.3F April 2009 Revision 0
6-22 Table 6-7 List of SG Models and H* Plants With Tubesheet Support Ring Structures General Plant Alpha SG Model TS Support Ring?
Arrangement Drawing a,c,c Braidwood -2 CDE D5 c
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
1 104J86 Sub 9 Surry-I VPA***
51F 1105J29 Sub 3 Surry - 2 VIR***
51F 1105J29 Sub 3 Turkey Point-4 FLA***
44F 1105145 Sub 3 Millstone - 3 NEU F
1182J08 Sub 8 Comanche Peak - 2 TCX D5 1182J16 Sub 1 Vandellos - 2 EAS F
1182J34 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 - I GAE F
1184J31 Sub 13 Vogtle - 2 GBE F
1184J32 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.
WCAP-17071-NP April 2009 Revision 0 6-22 Table 6-7 List of SG Models and H* Plants With Tubesheet Support Ring Structures Plant Alpha SG Model Braidwood - 2 CDE D5 Byron-2 CBE D5 SAP - Use Callaway (SCP)
Wolf Creek - 2 SG Drawings F
PSE - Use Seabrook -2 (NCH) SG Salem-I Drawings F
Surry ~ 1 VPA***
51F Surry - 2 VIR***
51F Turkey Point - 4 FLA***
44F Millstone - 3 NEU F
Comanche Peak - 2 TCX D5 Vandellos - 2 EAS F
Seabrook-I NAH F
Turkey Point - 3 FPL**
44F Catawba-2 DDP D5 Vogtle - I GAE F
Vogtle - 2 GBE F
Point Beach - I WEP**
44F Robinson-2 CPL**
44F Indian Point - 2 IPG 44F Model 44 F - These original SGs have been replaced.
Mode151F - These original SGs have been replaced.
WCAP-17071-NP TS Support Ring?
a,c,c General Arrangement Drawin2 1103 J99 Sub 3 1103J99 Sub 3 1I04J54 Sub 2 1104J86 Sub 9 II05J29 Sub 3 1105129 Sub 3 1105J45 Sub 3 1182J08 Sub 8 1182Jl6 Sub I 1182134 Sub I 1182139 Sub 3 1183101 Sub 2 1183J88 Sub 2 1184131 Sub 13 1184132 Subl 1184132 Sub I 6129E52 Sub 3 6136EI6 Sub 2 April 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 ace 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 Tavg Pressures and Temperatures for 4-Loop Model F Normal Operating, Low T.,,
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 6-10 Generic NOP High T.vg Pressures and Temperatures for 4-Loop Model F Normal Operating, High Tavu 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 WCAP-17071-NP April 2009 Revision 0 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 a,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 O~erating, Low T.v~
Secondary Surface Temperature a,c,c 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.vg Pressures and Temperatures for 4-Loop Model F Normal Operating, High T,vl!
Secondary Surface Temperature a,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 6-29 WCAP-1707l-NP April 2009 Revision 0
6-30 Table 6-11 Generic SLB Pressures and Temperatures for 4-Loop Model F Main Steam Line Break Secondary Surface Temperature a.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 6-12 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 i
Reference Temperature
[II 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 a,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 WCAP-17071-NP April 2009 Revision 0 6-30 Table 6-11 Generic SLB Pressures and Temperatures for 4-Loop Model F Main Steam Line Break Secondary Surface Temperature a,c,C Primary Surface Temperature Cold Leg Hot Leg Primary Pressure Cold Leg Hot Leg Seconda~ 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 aLe 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 a,c,c Primary Surface Temperature Cold Leg Hot Leg Primary Pressure Cold Leg Hot Leg Secondary Pressure End Cap Pressure Structural Thermal Condition Reference Temperature WCAP-17071-NP April 2009 Revision 0
9-24 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 (Dead Locked Rotor (Active Control Rod Ejection Line Break Loop)
Loop)
SG Type SG Hot SG Cold SG Hot SG Cold SG Hot SG Cold SG Hot SG Cold Leg Leg (OF)
Leg (OF)
Leg (°F)
Leg (OF)
Leg (OF)
Leg (OF)
Leg (°F)
(OF)
Model F a,c,c 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-17071-NP April 2009 WCAP-17071-NP April 2009 Revision 0 9-24 Table 9-1 Reactor Coolant System Temperature Increase Above Normal Operating Temperature Associated With Design Basis Accidents (References 9-12 and 9-13)
SG Type Model F Model D5 Model44F Model51F WCAP-17071-NP Steam LinelFeedwater Locked Rotor (Dead Locked Rotor (Active Control Rod Ejection Line Break Loop)
Loop)
SGRot SG Cold SGRot SG Cold SGRot SG Cold SGRot SG Cold Leg Leg (OF)
Leg CF)
Leg (OF)
Leg (OF)
Leg (OF)
Leg (OF)
Leg CF)
(OF) r--
a,c,c
- Best estimate values for temperature during FLB/SLB are used as discussed in Section 9.2.3.1.
April 2009 Revision 0
9-25 Table 9-2 Reactor Coolant Systems Peak Pressures During Design Basis Accidents (References 9-12 and 9-13)
SG Type Steam Line Break Feedwater Line Locked Rotor Control Rod Ejection (psia)
Break (psia)
(psia)
(psia)
Model D5 a,c,c Model F Model 44F Model 51F WCAP-17071-NP April 2009 Revision 0 WCAP-17071-NP Table 9-2 Reactor Coolant Systems Peak Pressures During Design Basis Accidents (References 9-12 and 9-13)
SGType Steam Line Break Feedwater Line Locked Rotor Control Rod Ejection (psia)
Break (psia)
(psia)
(psia)
ModelD5 a,c,c ModelF Model44F Model51F 9-25 April 2009 Revision 0
9-26 Table 9-3 Model F Room Temperature Leak Rate Test Data I
F 9
Test No.
EP-31080 I EP-30860 I EP-30860 I EP-29799 I EP-31330 I EP-31320 I EP-31300 Collar Bore P
]a,c,c Dia. (in.)
Test Pressure Leak Rate (drops per minute - dpm)
Differential (psi) 1000 Fa...
1910 2650 3110 AP Ratio Leak Rate Ratio (normalized to initial AP)
Average LR Ratio I
a,c,c 1
1.91 2.65 3.11 WCAP-17071-NP April 2009 Revision 0 9-26 Test No.
[
Dia. (in.)
Test Pressure Differential (psi) 1000 r-1910 2650 3110 M Ratio 1
1.91 2.65 3.11 WCAP-1707l-NP Table 9-3 Model F Room Temperature Leak Rate Test Data EP-30860 EP-30860 EP-29799 EP-31330 EP-31320 Leak Rate (drops per minute - dpm)
Leak Rate Ratio (normalized to initial ~P)
EP-31300 Ja,c,c a,c,c Average LR Ratio a,c,c April 2009 Revision 0
9-27 Table 9-4 Model F Elevated Temperature Leak Rate Test Data i
F 9'
9' F
0 0
0 0
0 0
00 00 0
0 0
0 0
00 00 00 Test No.
C, C:ý CIO 0o r'--
t'N 00q 00q r',
e¢)
m, Oz.,
Collar Bore Dia. (in.)
[
Test Pressure Differential (psi)
Leak Rate (drops per minute -dpm) 1910 2650{
a,c,e a,c,e 3110 AP Ratio Leak Rate Ratio (normalized to initial AP)
Average LR Ratio a,c,e 1.39 1.63 WCAP-17071-NP April 2009 Revision 0 Table 9-4 Model F Elevated Temperature Leak Rate Test Data 0
0 0
0
~
~
0 0
00 00
'-0
'-0
~
~
0 0
0 0
00 00 r-r-
oo 00 Test No.
0 0
~
~
N N
M M
M M
N N
M M
1 1
1 1
1 0..
1 1
0...
0...
0...
0...
0...
0...
0...
W W
W W
W W
W W
Collar Bore Dia. (in.)
[
Test Pressure Differential (psi)
Leak Rate (drops per minute -dpm) 1910 2650*
3110 tlP Ratio Leak Rate Ratio (normalized to initial tlP)
I 1.39 1.63 WCAP-17071-NP 0
0 0
0 M
M M
M 1
1 0...
0...
W W
]
9-27 a,c,c a,c,e Average LR Ratio a,c,e April 2009 Revision 0
9-28 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 Byron Unit 2 and 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 D5 4
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 Reference 9-21.
WCAP-17071-NP April 2009 WCAP-17071-NP April 2009 Revision 0 9-28 Table 9-5 H* Plants Operating Conditions Summary (\\)
Number Temperature Temperature Temperature Temperature Plant Name SG Type of Hot Leg (F)
Cold Leg (F)
Hot Leg (F)
Cold Leg (F)
Loops High Tavg High Tavg Low Tavg Low Tavg r-Byron Unit 2 and D5 4
Braidwood Unit 2 Salem Unit 1 F
4 Robinson Unit 2 44F 3
V ogtle Unit 1 and 2 F
4 Millstone Unit 3 F
4 Catawba Unit 2 D5 4
Comanche Peak D5 4
Unit 2 Vandellos Unit 2 F
3 Seabrook Unit 1 F
4 Turkey Point Units 44F 3
3 and 4 WolfCreek 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 Reference 9-21.
WCAP-17071-NP Pressure Differential Across the Tubesheet (psi)
High Tavg Pressure Differential Across the Tubesheet (psi)
Low Tavg a,c,c April 2009 Revision 0
9-29 Table 9-6 H* Plant Maximum Pressure Differentials During Transients that Model Primary-to-Secondary Leakage (1)
FLB/SLB Pressure Locked Rotor Pressure Control Rod Ejection Normal Operating Pressure Differential (psi)
Differential (psi)
Pressure Differential (psi)
Differential High Tavg (psi)
Byron Unit 2 anda,c, Braidwood Unit 2 Salem Unit I Robinson Unit 2 Vogtle Unit I and 2 Millstone Unit 3 Catawba Unit 2 Comanche Peak Unit 2 Vandellos Unit 2 Seabrook Unit 1 Turkey Point Units 3 and 4 Wolf Creek Surry Units 1 and 2 Indian Point Unit 2 Point Beach Unit 1 (1) The source of all pressure differentials is Reference 21.
WCAP-17071-NP April 2009 Revision 0 9-29 Table 9-6 H* Plant Maximum Pressure Differentials During Transients that Model Primary-to-Secondary Leakage (\\)
Plant Name FLB/SLB Pressure Differential (psi) r-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 1 Turkey Point Units 3 and 4 WolfCreek Surry Units 1 and 2 Indian Point Unit 2 Point Beach Unit 1 (1) The source of allpressure differentials is Reference 21.
WCAP-17071-NP Locked Rotor Pressure Control Rod Ejection Differential (psi)
Pressure Differential (psi)
~
Normal Operating Pressure Differential High T avg (psi) a,c,c April 2009 Revision 0
9-30 Table 9-7 Final H* Leakage Analysis Leak Rate Factors Transient SLB/FLB Locked Rotor Control Rod Ejection FLB-SLB/FLB VRT Leak vR3 Leak Adjusted SLB/NOP VR3 @
Leak Rate LR/NOP Rate Adjusted CRE/NOP Rate CRE LRF Plant Name AP Ratio 2672 psia(
AP Ratio Factor LR LRF1 AP Ratio 3030 Factor (High TaPl)'
Factor(LRF) 2711 psia (LRF) psia (LRF) a,c,e Byron Unit 2 and 1.93 Braidwood Unit 2 Salem Unit 1 1.79 Robinson Unit 2 1.82 Vogtle Unit I 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 I and 2 1.80 Indian Point Unit 21.75 Point Beach Unit IIL 1
_1.73 1
- 4.
Includes time integration leak rate adjustment discussed in Section 9.5.
- 5.
The larger of the AP's for SLB or FLB is used.
- 6.
VR - Viscosity Ratio a,c,e WCAP-17071-NP April 2009 Revision 0 9-30 Table 9-7 Final H* Leakage Analysis Leak Rate Factors Transient SLBIFLB Locked Rotor FLB-SLBIFLB VR3 -
Leak Plant Name SLBINOP VR3@
Leak Rate LRINOP Rate Adjusted
~PRatio 2672 psia
~PRatio Factor LRLRFI (High Tav,)2 Factor(LRF) 2711 psia (LRF) r-a,c,e 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 WolfCreek 2.03 Surry Units 1 and 2 1.80 Indian Point Unit 2 1.75 Point Beach Unit 1 1.73 L-
- 4.
Includes time integration leak rate adjustment discussed in Section 9.5.
- 5.
The larger of the ~P's for SLB or FLB is used.
- 6.
VR - Viscosity Ratio WCAP-17071-NP Control Rod Ejection VR J
Leak CREINOP Rate
~P Ratio 3030 Factor psi a (LRF)
Adjusted CRELRF i April 2009 Revision 0 a,c,e