L-05-198, Supplemental Information for License Amendment Request

Supplemental Information for License Amendment Request

ML053560175
Person / Time
Site:	Beaver Valley
Issue date:	12/16/2005
From:	Lash J FirstEnergy Nuclear Operating Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
L-05-198, TAC MC4645, TAC MC4646, TAC MC6725
Download: ML053560175 (44)

Text

FENOC FirstEnergy Nuclear Operating Company James H. Lash 724-682-5234 Site Vice President Fax: 724-643-8069 December 16, 2005 L-05-198 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555-0001

Subject:

Beaver Valley Power Station, Unit Nos. 1 and 2 BV-1 Docket No. 50-334, License No. DPR-66 BV-2 Docket No. 50-412, License No. NPF-73 Supplemental Information for License Amendment Request Nos. 320 (Unit No. 1 TAC No. MC6725) and 302/173 (Unit No. 1 TAC No. MC4645/Unit No. 2 TAC No. MC4646)

On October 4, 2004, FirstEnergy Nuclear Operating Company (FENOC) submitted License Amendment Request (LAR) Nos. 302 and 173 by letter L-04-125 (Reference 1).

This submittal requested an Extended Power Uprate (EPU) for Beaver Valley Power Station (BVPS) Unit Nos. 1 and 2 and is known as the EPU LAR.

On April 13, 2005, FENOC submitted LAR No. 320 for BVPS Unit No. 1 by letter L-05-069 (Reference 2). This submittal requested the Technical Specification changes necessary for operation of BVPS Unit No. 1 with the replacement steam generators and is known as the RSG LAR. provides supplemental information that pertains to the RSG LAR and the EPU LAR relative to the Probabilistic Risk Assessment (PRA) Auxiliary Feedwater (AFW) System success criteria and AFW Technical Specification Bases changes. provides supplemental information that pertains to the BVPS Unit No. 1 RSG and EPU LARs relative to the BVPS Unit No. 1 Pressurizer Safety Valves (PSVs).

The supplemental information is the result of a review of the RSG and EPU submittals as described in the information provided in the enclosure.

The supplemental information provided in this transmittal has no impact on either the proposed Technical Specification changes or the no significant hazards consideration, transmitted by References 1 or 2. The regulatory commitments contained in this letter are listed in Enclosure 3.

Add

V Beaver Valley Power Station, Unit Nos. 1 and 2 Supplemental Information for License Amendment Request Nos. 320 (Unit No. I TAC No. MC6725) and 302/173 (Unit No. I TAC No. MC4645/Unit No. 2 TAC No. MC4646)

L-05-198 Page 2 If you have questions or require additional information, please contact Mr. Gregory A.

Dunn, Manager - Licensing, at 330-315-7243.

I declare under penalty of perjury that the foregoing is true and correct. Executed on December It

, 2005.

Sincerely, t

Apes H. Lash

Enclosures:

1.

Probabilistic Risk Assessment (PRA) Auxiliary Feedwater (AFW) System Success Criteria and AFW Technical Specification Bases Changes

2.

Pressurizer Safety Valve (PSV) Flow Capacity

3.

List of Commitments

References:

1.

FENOC Letter L-04-125, License Amendment Requests 302 and 173, dated October 4,2004.

2.

FENOC Letter L-05-069, License Amendment Request 320, dated April 13, 2005.

C:

Mr. T. G. Colburn, NRR Senior Project Manager Mr. P. C. Cataldo, NRC Senior Resident Inspector Mr. S. J. Collins, NRC Region I Administrator Mr. D. A. Allard, Director BRP/DEP Mr. L. E. Ryan (BRP/DEP)

i Enclosure I of L-05-198 Probabilistic Risk Assessment (PRA) Auxiliary Feedwater (AFW) System Success Criteria and AFW Technical Specification Bases Changes Reason for the contained supplemental information:

During teleconferences on November 29, 2005, and December 8, 2005, the NRC staff requested additional clarification concerning the Probabilistic Risk Assessment (PRA) success criteria for the Auxiliary Feedwater (AFW) System. In addition, the NRC requested FENOC modify the AFW Technical Specification Bases to include a justification of the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed outage time (AOT) and the discussion of the realistic assessment that demonstrates that only one motor-driven AFW pump is required to mitigate the Loss of Normal Feedwater event.

Supplemental Information:

Realistic assessments for a Loss of Normal Feedwater event were performed for Beaver Valley Power Station Unit No. 1 (BVPS-1) and Beaver Valley Power Station Unit No. 2 (BVPS-2) in support of Emergency Operating Procedures (EOP) setpoint development for Extended Power Uprate (EPU) and Replacement Steam Generators (RSG) for conditions related to the minimum AFW flow required to maintain a secondary heat sink. This assessment was performed using the Westinghouse LOFTRAN non-LOCA code. The results showed that the minimum AFW flow required was less than the capacity of one motor-driven pump assuming realistic conditions with either the condenser steam dump valves or the atmospheric steam dump valves available. In this assessment, flow was assumed to be delivered to all three steam generators.

Additionally, a best estimate analysis was performed using MAAP for both BVPS-1 and BVPS-2 to determine the Probabilistic Risk Assessment (PRA) success criteria for the post-EPU Loss of Normal Feedwater. The BVPS-1 analysis also included the RSG, since the post-EPU steam generator low-low level reactor trip setpoint would result in less secondary water inventory. Two cases were run for each unit. The first case used the EPU Technical Specification steam generator water level low-low reactor trip setpoint allowable value. These values are 19.1% of the narrow range instrument span at BVPS-1, and 20.0% of the narrow range instrument span at BVPS-2. These are considered the best estimate cases. The second case involved a sensitivity case, which used a steam generator water level low-low reactor trip setpoint corresponding to 0% of the narrow range instrument span for both BVPS-1 and BVPS-2. For all cases, the Reactor Coolant Pumps (RCPs) were not tripped, and one motor-driven AFW pump was used to deliver a maximum flow of 310 gpm to the steam generators based on the installed cavitating venturis.

The results of these best estimate MAAP analyses show that the pre-EPU and post-EPU PRA transient and the Small Break Loss of Coolant Accident (SBLOCA) success criteria of one AFW pump to one steam generator at BVPS-1 and one AFW pump to two steam generators at BVPS-2 remain valid for the Loss of Normal Feedwater transients. It should be noted that the success criteria requirement for two steam generators at BVPS-2 is due to the smaller capacity of the atmospheric steam dump valves and is based on a SBLOCA with failure of High Head Safety Injection (HHSI), which requires a maximum cooldown of the RCS for accumulator and Low Head Safety Injection (LHSI) pump injection. For all cases, the minimum wide range steam generator level remained above the EOP setpoint for initiating feed and bleed cooling (14% of the wide range instrument span at BVPS-1 and 13% of the wide range instrument span at BVPS-2). A summary of the best estimate MAAP analyses results is presented in Table 1-1.

of L-05-198 Page 2 of 2 Table 1-1: PRA Best Estimate MAAP Results for Loss of Main Feedwater AFW Success Criteria SG Low-Time of Number Number of Minimum Time that Time to Low Level SG Low-of Motor-Steam SG Level SG Narrow Recover Reactor Low Level Driven Generators

(% Wide Range SG Trip Reactor AFW Range)

Level Nominal Setpoint Trip Pumps Comes Level

(% Narrow (seconds)

Back on (hrs)

Range)

Scale (hrs)

BVPS-1 19.1 46.2 1

1 19.1 4.1 6.2 Case I BVPS-1 0

47.4 1

1 18.0 4.2 6.4 Case 2 BVPS-2 20 23.5 1

2 39.0 2.8 6.2 Case 1 BVPS-2 0

36.3 1

2 26.4 3.7 5.9 Case 2

==

Conclusion:==

As per the NRC request, FENOC will modify the AFW Technical Specification Bases to include a justification of the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> AOT and the discussion of the realistic assessment that demonstrates that only one motor-driven AFW pump is required. The additional wording for the AFW Technical Specification Bases, to be incorporated when the amendments are implemented, is provided below:

"With one inoperable AFW pump, the remaining two AFW pumps will be aligned to separate redundant headers capable of supplying flow to each steam generator.

A realistic analyses of a loss of normal feedwater event demonstrates that one motor-driven AFW pump will maintain sufficient steam generator inventory to provide a secondary heat sink and prevent the RCS from exceeding applicable pressure and temperature limits.

For BVPS-1, the licensing basis has changed to a requirement for two of three AFW pumps to meet the flow requirements for the limiting DBAs. This change was necessitated by the installation of cavitating venturis in the AFW injection paths. The venturis protect the AFW pumps from runout conditions and allow for flow to be directed to the intact steam generators during a FWLB. Cavitating venturis in each individual injection path to the steam generators ensure that sufficient flow will be delivered to the two intact steam generators during a FWLB. Since no single failures are assumed to occur while in an AOT, adequate flow can be supplied by the two operable AFW pumps.

Based on this, the AOT of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> continues to remain applicable. This change to the BVPS-1 licensing basis is consistent with the original licensing basis for BVPS-2."

1V of L-05-198 Pressurizer Safety Valve (PSV) Flow Capacity Reason for the contained supplemental information:

In support of a maintenance initiative program to upgrade the BVPS-1 pressurizer safety valves due to consideration for parts availability and obsolescence, a review of replacement options for the BVPS-1 PSVs was performed. As part of this review, a comparison was made between the BVPS-1 and BVPS-2 PSVs, and a discrepancy was identified for the BVPS-1 PSVs that affects assumed valve performance within selected safety analyses. The discrepancy was in the minimum valve flow capacity at rated pressure. For the EPU LAR, a calculated PSV flow capacity was used in selected plant safety analyses based on the valve flow orifice diameter.

This capacity was greater than the rated PSV flow capacity. It was determined that the BVPS-1 PSV design uses a more limiting flow area than what is calculated based on the valve orifice diameter. The discrepancy results in a lower PSV flow capacity than assumed in selected EPU BVPS-1 safety analyses.

As a result, selected EPU non-LOCA transients were re-analyzed to demonstrate continued acceptable reactor coolant and main steam system overpressure protection. Specifically, the Loss of Extemal Load and/or Turbine Trip event and the Single Reactor Coolant Pump Locked Rotor event were re-analyzed. The re-analyses results are applicable to the BVPS-1 RSG and EPU LARs.

The subject re-analyses and associated calculations were completed and available at the time of the NRC safety analysis calculation note audit that was held in November 2005.

Supplemental Information:

A review of the BVPS-1 RSG and EPU Licensing Reports and FENOC responses to NRC's Request for Additional Information (RAls) relative to the RSG and EPU LARs was conducted to identify necessary changes as a result of the re-analysis. Since the RSG Licensing Report and the EPU Licensing Report are affected, revised pages for the RSG and EPU Licensing Reports are provided in the Attachments to Enclosure 2. Table 2-1 lists the affected pages for the RSG and EPU Licensing Reports along with a discussion pertaining to the changed items.

Attachment A of Enclosure 2 provides the revised pages of the RSG Licensing Report, and Attachment B of Enclosure 2 provides the revised pages of the EPU Licensing Report.

==

Conclusion:==

The identified discrepancy was entered into the BVPS Corrective Action Program and evaluated for impact. The identified changes do not impact the conclusions drawn in the applicable EPU safety analysis, do not require a change to the Technical Specifications and do not invalidate the no significant hazards consideration submitted by References 2-1 or 2-2. The proposed changes have been provided to reflect the revised calculations and the corresponding reanalysis.

of L-05-198 Page 2 of 3 Table 2-1 Affected RSG and EPU Licensing Report Pages RSG EPU l Discussion Page Page RSG & EPU Section 5.3.6, Loss Of External Electrical Load and/or Turbine Trip 5-79 5-124 Updated peak pressure location and data provided in Table 5.3.6-1A N/A 5-125 Updated peak pressure location and data provided in Table 5.3.6-1 B 5-80 5-126 Replace existing Figure 5.3.6-1 A with new figure 5-81 5-128 Replace existing Figure 5.3.6-2A with new figure 5-82 5-130 Replace existing Figure 5.3.6-3A with new figure 5-83 5-132 Replace existing Figure 5.3.6-4A with new figure 5-84 5-134 Replace existing Figure 5.3.6-5A with new figure 5-85 5-136 Replace existing Figure 5.3.6-6A with new figure 5-86 5-138 Replace existing Figure 5.3.6-7A with new figure 5-87 5-140 Replace existing Figure 5.3.6-8A with new figure RSG & EPU Section 5.3.15, Single Reactor Coolant Pump Locked Rotor 5-156 5-240 Updated data presented in Tables 5.3.15-1 and 5.3.15-2 5-157 5-241 Replace existing Figure 5.3.15-l1A with new figure 5-158 5-243 Replace existing Figure 5.3.15-2A with new figure 5-159 5-245 Replace existing Figure 5.3.15-3A with new figure 5-160 5-247 Replace existing Figure 5.3.15-4A with new figure RSG & EPU Section 5.3.20, Summary 5-185 5-307 Updated data presented in Table 5.3.20-1A 5-186 5-309 l Updated data presented in Table 5.3.20-2A EPU Section 9.1.3.6, RCS Design Calculations N/A 9-5 Updated statement to reflect that there are several limits used in RCS maximum pressure analyses N/A 9-6 Updated statement to reflect the applicable safety analyses report sections that address reactor coolant and main steam system overpressure protection of L-05-198 Page 3 of 3 References 2-1 FENOC Letter L-05-069, License Amendment Request 320, dated April 13, 2005.

2-2 FENOC Letter L-04-125, License Amendment Requests 302 and 173, dated October 4, 2004.

Attachment A of Enclosure 2 of L-05-198 RSG Licensing Report - Revised Pages

FE OC REPLACEMENT STEAM GENERATORS Table 5.3.6-1 A BVPS-I Time Sequence of Events - Loss of External Electrical Load and/or Turbine Trip Case Event Time (Sec)

With pressurizer pressure control Loss of Electrical Load/Turbine Trip 0.0 (minimum reactivity feedback-DNB Case)

Overtemperature AT Reactor Trip Setpoint reached 12.3 Rods begin to drop 14.3 Minimum DNBR occurs 15.6 Without pressurizer pressure Loss of Electrical Load/Turbine Trip 0.0 control (minimum reactivity High Pressurizer Pressure Reactor Trip Setpoint reached 5.5 feedback-Pressure Case)

Rods begin to drop 7.5 RCcs Peak rNMuN99F.ipressure occurs 4--.

I 6676.doc-041 105 5-79 6676.doc-041105 5-79

FENOC REPLACEMENT STEAM GENERATORS 1.2 a

0.)

0 a-C1

.8

.6

.4

.2 a

Time (s) 1.2 Q

C_,

C CD a) 0.)-

I-Z C~)

1

.8

.6

.4

.2 0

Figure 5.3.6-1A BPS-1 Loss of Load / Turbine Trip with Pressure Control Nuclear Power and Core Heat Flux versus Time 5-80

FENOC REPLACEMENT STEAM GENERATORS 2500 2400 t

2300 CD 2200 CO or c? 2100 2000 Co1900 0)9O a>

1800 1700 1400 1300 1200 0n D

1100 a)900 CL, 700 700 Time (s)

Figure 5.3.6-2A BVPS-1 Loss of Load / Turbine Trip with Pressure Control Pressurizer Pressure and Water Volume versus Time 5-81

I FENOC REPLACEMENT STEAM GENERATORS 1200 en 110(0 C.

cn 1-at1000 0>

=3 w

9000 b--

(a_

U-)

700 2600

.2_

2400 CL 2200 er, C-,

E E 2000 C7 1800 Time (s)

Time (s)

Figure 5.3.6-3A B-VPS-1 Loss of Load I Turbine Trip with Pressure Control Steam Generator Pressure and Maximum RCS Pressure versus Time 5-82

FENOC REPLACEMENT STEAM GENERATORS Tang 620 -

L1 610-ca 600-

/

x590-

/

E 570-

/

-Z5 560 -

cn~

550-540 Time (s) 7 6

5 4

3 2

Time (s)

Figure 5.3.64A BVPS-1 Loss of Load / Turbine Trip with Pressure Control RCS Coolant Temperatures and DNBR versus Time 5-83

FENOC REPLACEMENT STEAM GENERATORS 1.2 C3 E

CD C:>

C._

C)

U-Q),

0 0>

QV

)

Cab C->

1

.6

.4

.2 0

1.2 Time (s)

C5 CI C3 CO Up 4Z7 WI 0r 1

.8

.4

.2 0

Figure 5.3.6-5A BVPS-1 Loss of Load / Turbine Trip without Pressure Control Nuclear Power and Core Heat Flux versus Time 5-84

FENOC REPLACEMENT STEAM GENERATORS 2800

.2 2600

=

2400 CL)

CL 2200 CO, cn

? 2000 1800 1200 1100 01000 E_:I 900 C7 800 a) n 700 600 Time (s)

Time (s)

Figure 5.3.6-6A BVPS-1 Loss of Load / Turbine Trip without Pressure Control Pressurizer Pressure and Water Volume versus Time 5-85

FENOC REPLACEMENT STEAM GENERATORS 1200

.(n qu 1100

=3 (n

0n 1000 a)

E 900 CD a) 800 2800 0n29 so 2600 x

2400 a) 0-CT_

2200 E

F 1800 Time (s)

Time (s)

Figure 5.3.6-7A BVPS-1 Loss of Load I Turbine Trip without Pressure Control Steam Generator Pressure and Maximum RCS Pressure versus Time 5-86

FENOC REPLACEMENT STEAM GENERATORS T in 610 -

LoX~

600 -

c) 5 90 -

A 580-570 -

En 560-550 -

Time (s)

Figure 5.3.6-8A BVPS-1 Loss of Load I Turbine Trip without Pressure Control RCS Coolant Temperatures versus Time 5-87

FENOC REPLACEMENT STEAM GENERATORS Table 5.3.15-1 Time Sequence of Events - Single RCP Locked Rotor BVPS-I BVPS-2 Event Time (see)

Tame (see)

Rotor on one pump locked or the shaft breaks 0.0 NA Low flow reactor trip setpoint reached 0.04 NA Rods begin to drop 1.04 NA Remaining pumps lose power and begin to coastdown 1.04 NA Maximum RCS pressure occurs

_Jff3.4 NA Maximum clad average temperature occurs 3.8 NA Time of maximum clad oxidation 10.0 NA Table 5.3.15-2 Summary of Results for Single RCP Locked Rotor BVPS-I BVPS-2 3 Loops Initially 3 Loops Initially Operating, One Locked

. Operating, One Locked Criteria Rotor Rotor Limit Maximum Clad Temperature at 1

8 NA 2700 Core Hot Spot, 'F Maximum Zr-H20 Reaction at 0.41 NA 16.0 Core Hot Spot, wL %

Maximum RCS Pressure, psia 21-2.147 NA 2997 I

I I

6676.doc- 041 105 5-156

FENOC REPLACEMENT STEAM GENERATORS IC_-

C

.Fa C::

Is r_-

01 f

C

Z=:-

3.00 G--

-a,>

C*

A!

.2L>

1=

W

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.6

.2 0

4 r

.E

'a-o>

0 40

-A

-,5

.),

7E lime (Seconds)

Figure 5.3.15-1A BVPS-1 Single Reactor Coolant Pump Locked Rotor Reactor Vessel Flow and Faulted Loop Flow versus Time 5-157

FENOC REPLACEMENT STEAM GENERATORS CE L...

Cp

£_-

I

.8

.6

.4

.2 0

3000 2800

'I,Vo C

2600

-3C" U>.1 c'

2400 X-,

2200 2000 Figure 53.15-2A BVPS-1 Single Reactor Coolant Pump Locked Rotor Nuclear Power and RCS Pressure versus Time 5-158

FENOC REPLACEMENT STEAM GENERATORS 12 0

=

4, a,

=

0)

E 0

0 0

0a,.

-a; C0 C-)

0.

1.2 Time (Seconds)

Figure 5.3.15-3A BVPS41 Single Reactor Coolant Pump Locked Rotor Average Channel and Hot Channel Heat Flux versus Time 5-159

FENOC REPLACEMENT STEAM GFNFRATORS w

0-W Z w f3-.

zwU w

w

~LL 0.

F-LU TIME (SECONDS) 2000 TIME (SECONDS)

Figure 53.15-4A BVPS-1 Single Reactor Coolant Pump Locked Rotor Fuel Centerline and Clad Inner Temperatures versus Time 5-160

FE JOC REPLACEMENT STEAM GENERATORS Table 53.20-IA BVPS-I Condition 11 DNB Event Results Peak Peak UFSAR Report Minimum Primary Secondary Event Name Section Section DNBR Pressure (psia)

Pressure (psia)

RCCA Bank Withdrawal from 14.1.1 5.3.2 Limit metd5 1 N/A N/A Subcritical RCCA Bank Withdrawal at Power 14.1.2 5.3.3 1.57 NWA" 1170.1 RCCA Misalignment 14.1.3 5.3.4 Limit mete-5 N/A WA Loss of Load 14.1.7 5.3.6 2.23 2 J144 ef Feedwater System Malfunctions

a. Feedwater Flow Increase 14.1.9 53.9 1.75M 2357.0 1124.0

b. Feedwater Enthalpy Decrease 14.1.9 5.3.9 1.67 2300.0 914.0 Excessive Load Increasett 14.1.10 5.3.10 Limit met Limit met Limit met RCS Depressurization 14.1.15 5.3.11 1.62 NIA NIA Main Steam Pipe Rupture (HZP)"1 14.2.5.1 5.3.12 Limit met,6) N/A N/A Partial Loss of Flow 14.1.5 53.13 2.25"'

2373.8 989.0 Complete Loss of Flow(31 14.2.9 5.3.14 1.64i't 2504.1 992.8 Limits 1.55 2748.5 1208.5 I

Notes:

(I) A generic Westinghouse evaluation addresses peak pressures for Rod Withdrawal at Power analyses.

(2) Current methodology for evaluating this event involves a comparison of conservative generic statepoints to the plant specific core thermal limits. In all cases, the generic statepoints are bounded by the come thermal limits.

(3) These events are not Condition 11 events but are analyzed to the more restrictive Condition 11 acceptance criteria.

(4) The analysis supports a pressurizer safety valve setpoint tolerance of +/-3.0%

(5) DNB statepoints are evaluated and the conclusion is that the limits are met.

(6) The 1.55 DNBR limit listed above is not applicable for these events. See Table 6-1-3 for the applicable DNB correlations and limits.

(7) The results reported are for the HFP case. An additional case was analyzed at HZP conditions. It was conduded that this case is bounded by the HZPsteamline break analysis (UFSAR 14.2.5.1).

(8) These values are applicable for the RFA fueL For the V5H fuel, the Partial Loss of Flow minimum DNBR is 1.90 compared to a limit of 1.32 (thimble cell) and the Complete Loss of Flow minimum DNBR is 1.39 compared to a limit of 1.33 (typical cell).

6676.doc-04l 105 5-185 6676-doc4041 105 5-185

FjEN C REPLACEMENT STEAM GENERATORS Table 5.320-2A BVPS-I Locked Rotor Analysis Results Percentage of UFSAR Rods-in-DNB Peak Primary Pressure Event Name Section Report Section (M)

(psia)

Locked Rotor 14.2.7 53.15

< 20 Hi 20M 0 Limits 20 2997 Note:

(I) The peak Reactor Coolant System pressure reached during the transient is less than that which would cause stresses to exceed the faulted condition stress limits.

I Table 53.20-3A BVPS-I Pressurizer Filling Event Results UFSAR Report Peak Pressurizer Volume Event Name Section Section (fit)

Loss of Normal Feedwater 14.1.8 5.3.7 1384.0 Loss of Non-Emergency AC Power 14.1.11 5.3.8 1224.0 Spurious Safety Injection at Power 14.1.16 5.3.18 NA Limits 1458.1 Note:

NA 6676.doc-04t 105 5-186 6676.doc 041 105 5-186

Attachment B of Enclosure 2 of L-05-198 EPU Licensing Report - Revised Pages

__,XCEXTENDED POWER UPRATE Table 5.3.6-1A BVPS-1 Time Sequence of Events - Loss of External Electrical Load and/or Turbine Trip Case Event Time (Sec)

With pressurizer pressure control Loss of Electrical Load/Turbine Trip 0.0 (minimum reactivity feedback-DNB Case)

Overtemperature AT Reactor Trip Setpoint reached 12.3 Rods begin to drop 14.3 Minimum DNBR occurs 15.6 Without pressurizer pressure Loss of Electrical Load/Turbine Trip 0.0 control (minimum reactivity High Pressurizer Pressure Reactor Trip Setpoint reached 5.5 feedback-Pressure Case)

Rods begin to drop 7.5 Peak peest1rier pressure occurs

_&2 RCs e'sk 6517-5-NP.doc-092304 5-124

FENOC EXTENDED POWER UPRATE qZe Table 53.6-1B BVPS-2 Time Sequence of Events - Loss of External Electrical Load and/or Turbine Trip Case Event Time (Sec)

With pressurizer pressure control Loss of Electrical Load/Turbine Trip 0.0 (minimum reactivity feedback-High Pressurizer Pressure Reactor Trip Setpoint reached 11.2 DNB Case)

Rods begin to drop 13.2 Minimum DNBR occurs 14.6 Without pressurizer pressure Loss of Electrical Load/Turbine Trip 0.0 control (minimum reactivity High Pressurizer Pressure Reactor Trip Setpoint reached 5.4 feedback-Pressure Case)

Rods begin to drop 7.4 Peak prmssuriez pressure occurs 8.4 RLCs

'V 6517-5-NP.doc-0923045 5-125

FENOC EXTENDED POWER UPRATE 1.2 C) 0 C) 1.

0~

L.

6 CL 0.)-

C) an 1

.6

.4

.2 0

1.2 Time (s)

C-C>

c cv C)I

(-

c::

I 1

.8

-6

.4

.2 0

Time (s)

Figure 5.3.6-1A BVPS-I Loss of Load / Turbine Trip with Pressure Control Nuclear Power and Core Heat Flux versus Time 5-126

FENOC EXTENDED POWER UPRATE 2500 2400 Is-2300 "o 2200 U,

f) m-2100

- 2000 en 1900 1

8 180 1700 1400

-,() 1300

'a) 1200 8

-3 1100 tQ 1000

=3 tV 900 t

800 70I 700 Time (s)

Figure 5.3.6-2A BVPS-1 Loss of Load / Turbine Trip with Pressure Control Pressurizer Pressure and Water Volume versus Time 5-128

FENOC EXTENDED POWER UPRATE 1200 I-en a1)

C-s En

~0

(,)c>

a) 2600

.2_

2400 Q>

(n I-(n a

2200 C-D E

E 2000 1800 Time (s)

Figure 5.3.6-3A BVPS-1 Loss of Load / Turbine Trip with Pressure Control Steam Generator Pressure and Maximum RCS Pressure versus Time 5-130

FENOC EXTENDED POWER UPRATE r~ in T a v 620

-17 610 cD C=) 600 En 2a) 590

° 580 E 570

-Z 560 (n

CIO

)

550 540 Time (s) 7 6

5 3

2 Time (s)

Figure 5.3.64A BVPS-1 Loss of Load / Turbine Trip with Pressure Control RCS Coolant Temperatures and DNBR versus Time 5-132

FENOC EXTENDED POWER UPRATE 1.2 C=E C3 0a) 0.

0 i1) 1

.6

.4

.2 a

1.2 Time (s) 0 0

C.)

IZ) 0

(..)

I

.8

.6

.4

.2 a

Time (s)

Figure 5.3.6-5A BVPS-1 Loss of Load / Turbine Trip without Pressure Control Nuclear Power and Core Heat Flux versus Time S-134

FENOC EXTENDED POWER UPRATE 2800

.° 2600 en I-to 2400 c,

0-8 2200 1n

'-2000 1800 1200 3,

C) 0)

E a>

0=

C')

C,,

V 0-1100 1000 900 800 700 600 Figure 5.3.6-6A BVPS-1 Loss of Load I Turbine Trip without Pressure Control Pressurizer Pressure and water Volume versus Time 5-136

FENOC EXTENDED POWER UPRATE 1200 c._

V)

ED C) a)

1100 1000 900 800 2800

.T n 2600 c-en) 24100 Q.

CI)

? 2200 n 2000 p

18 200 Time (s)

Figure 5.3.6-7A BVPS-1 Loss of Load / Turbine Trip without Pressure Control Steam Generator Pressure and Maximum RCS Pressure versus Time 5-138

FENOC EXTENDED POWER UPRATE T i n tavg 610 C-1 z \\

U-600-N c"

I CD

/

Ca)

/

Xn 590 - _ '

Q

° 580 41)a-EZ a 570-

/

Xn 560 550*

Time (s)

Figure 5.3.6-8A BVPS-1 Loss of Load / Turbine Trip without Pressure Control RCS Coolant Temperatures versus Time 5-140

FENOC EXTENDED POWER UPRATE Table 5.3.15-1 Time Sequence of Events - Single RCP Locked Rotor BVPS-1 BVPS-2 Event Time (see)

Time (sec)

Rotor on one pump locked or the shaft breaks 0.0 0.0 Low flow reactor trip setpoint reached 0.04 0.04 Rods begin to drop 1.04 1.04 Remaining pumps lose power and begin to coastdown 1.04 1.04 Maximum RCS pressure occurs

.G 3.6 Maximum clad average temperature occurs 3.8 3.9 Time of maximum clad oxidation 10.0 10.0 Table 5.3.15-2 Summary of Results for Single RCP Locked Rotor BVPS-1 BVPS-2 3 Loops Initially 3 Loops Initially Operating, One Locked Operating, One Locked Criteria Rotor Rotor Limit Maximum Clad_7emperature at

)1A6 ifM 1824 2700 r

Core Hot Spot, Maximum Zr-1120 Rtaction at 0.41 0.35 16.0 Core Hot Spot, wt. %

Maximum RCS Pressure, psia 2 Y e

7 2825 2997 j

6517--NP~oc-023045-24 I

I I

6517-5-NP~loc-092304 5-240

FENOC EXTENDED POWER UPRATE

-2 B

E C>

=

A a

Cu

.4 C:X 1i.

W

.4

(-)1 CZ,

.4 Ti

(

Time (Seconds) i T0 v

.E 0f C;

CO C>

0 TV 0

2.

1.-5 I

.5

-5 Time (Seconds)-

.Figure 5.3.15-1A BVPS-1 Single Reactor Coolant Pump: Locked Rotor Reactor Vessel Flow and Faulted Loop-Flow versus Time 5-241

FENOC EXTENDED POWER UPRATE 1.Z C>

C)

C.)

I-C:

(-3 at:

Timne (Seconds) 3.0 2800 7> 2600 C/>

co V),

C)J C-)

2200 2000 Figure 5.3.15-2AL BVPS-1 Single Reactor Coolant Pump Locked Rotor Nuclear Power and RCS Pressure versus Time 5-243

FENOC EXTENDED POWER UPRATE

.E'c C) a,.R 0C' Qa) of 1.2 1

8

.6

.4

.2 0

Time (Seconds)

-t

.2 5.

-5; CDI coo C=

I 4

.9

.4 2

2 Time (Seconds)

Figure 5.3.15-3A BVIPS-1 Single Reactor Coolant Pump Locked Rotor

-Average Channel and Hot Channel Beat Flux versus Time 5-245

FENOC I------ --

EXTENDED POWER UPRATE 3500 20 a) 1O 3000 140 E 2000 01800D a) 1, a)

I-50

~ 11000 2-180o 600 I Figure 5.3.15-4A.

BVPS-1 Single Reactor Coolant Pump Locked Rotor Fuel Centerline and Clad Inner Temperatures versus Time S-247

FjfPIC EXTENDED POWER UPRATE Table 53.20-IA BVPS-I Condition 11 DNB Event Results Peak Peak UFSAR Report Minimum Primary Secondary Event Name Section Section DNBR Pressure (psia)

Pressure (psia)

RCCA Bank Withdrawal from 14.1.1 5.3.2 Limit mete'-6 N/A N/A Subcritical RCCA Bank Withdrawal at Power 14.1.2 5.3.3 1.57 N/A(

t )

1170.1 RCCA Misalignment 14.1.3 53.4 Limit met(5 N/A N/A Loss of Load 14.1.7 5.3.6 2.23 jjt' Iq (.Ilp Feedwater System Malfunctions

a. Feedwater Flow Increase 14.1.9 53.9 I.75(7) 2357.0 1124.0

b. Feedwater Enthalpy Decrease 14.1.9 5.3.9 1.67 2300.0 914.0 Excessive Load Increase(2) 14.1.10 5.3-10 Limit met Limit met Limit met RCS Depressurization 14.1.15 5.3.11 1.62 N/A N/A Main Steam Pipe Rupture (HZP3) 14.2.5.1 53.12 Limit met/=6)

N/A N/A Partial Loss of Flow 14.1.5 5.3.13 2.25(x) 2373.8 989.0 Complete Loss of Flow(3) 14.2.9 5.3.14 l.64s) 2S04.1 966.5 Limits 1.55 2748.5 1208.5 Notes:

(1) A generic Westinghouse evaluation addresses peak pressures for Rod Withdrawal at Power analyses.

(2) Current methodology for evaluating this event involves a comparison of conservative generic statepoints to the plant specific core thermal limits. In all cases, the generic statepoints are bounded by the core thermal limits.

(3) These events are not Condition 11 events but are analyzed to the more restrictive Condition II acceptance criteria.

(4) The analysis supports a pressurizer safety valve setpoint tolerance of +/-3.0/

(5) DNB statepoints are evaluated and the conclusion is that the limits are met.

(6) The 1.55 DNBR limit listed above is not applicable for these events. See Table 6.1-3 for the applicable DNB correlations and limits.

(7) The results reported are for the HFP case. An additional case was analyzed at HZP conditions. It was concluded that this case is bounded by the HZP SLB analysis (UFSAR 14.2.5.1 )

(8) These values are applicable for the RFA fuel. For the V5H fuel, the Partial Loss of Flow minimum DNBR is 1.90 compared to a limit of 1.32 (thimble cell) and the Complete Loss of Flow minimum DNBR is 1.39 compared to a limit of 1.33 (typical cell).

6517-5-NP.doc-092304 5-307 6517-5-NP doc 092304 5-307

FENOC EXTENDED POWER UPRATE Table 5.3.20-2A BVPS-1 Locked Rotor Analysis Results UFSAR Percentage of Rods-in-Peak Primary Pressure Event Name Section Report Section DNB (%)

(psia)

Locked Rotor 142.7 5.3.15

< 20 2-191" Affix Limits 20 2997 Note:

(I) The peak Reactor Coolant System pressure reached during the transient is less than that which would cause stresses to exceed the faulted condition stress limits.

I Table 5.3.20-2B BVPS-2 Locked Rotor Analysis Results UFSAR Percentage of Rods-in-Peak Primary Pressure Event Name Section Report Section DNB (%)

(psia)

Locked Rotor 15.3.3 5.3.15

< 20 2825 (')

Limits 20 2997 Note:

(I) The peak Reactor Coolant System pressure reached during the transient is less than that which would cause stresses to exceed the faulted condition stress limits.

- 4

,~~~

1

tI zl :; I I-,-I, I

-I

.-,I

11'Io, I

6517-5-NP.doc-092304 5-309

FEAIOC EXTENDED POWER UPRATE new calculation was performed to determine both the maximum and minimum pressurizer spray flow capabilities.

9.1.3.2 Pressurizer Spray Line Temperature In the assessment of system operation, the minimum RCS T,0Id temperature (provided in Table 9.1-1) for the EPU conditions was compared to the existing pressurizer spray line low temperature alarm setpoint.

The available temperature difference between RCS Tc0Id and the low temperature alarm was evaluated to determine acceptability of the alarm setpoint.

9.1.3.3 RCS Temperatures In the assessment of system operation, the maximum expected RCS Tht temperature (provided in Table 9.1-1) was compared to RCS design temperatures.

9.1.3.4 Pressurizer Relief Tank Sizing and Level Alarm Setpoints In the assessment of the pressurizer level conditions, the maximum steam space volume discharged from the pressurizer during a loss of normal feedwater event was compared to the volume assumed in the original PRT design basis calculation to determine acceptability of the PRT sizing and level alarm setpoints at EPU conditions.

9.1.3.5 RCS Net Heat Input The net heat input calculation is a detailed heat balance on the RCS. The purpose is to determine thtiiet' heat input-to the RCS considering all heat inputs and losses. The calculation considers the primary source; 1/2i of heat input which is the RCPs, but it also considers other relatively smaller heat inputs and losses such as letdown and charging flow. The original value used for net heat input is 8 MWt. For the EPU Project, a value of 10 MWt is used. The net heat input calculation was performed to verify that a minimum net heat input of 10 MWt is available to support the PCWG parameters for EPU conditions. The calculation considered an SG tube plugging range of 0% to 22% consistent with the PCWG parameters for EPU.

9.1.3.6 RCS Design Calculations The following RCS design calculations were evaluated to determine their applicability at 2910 MWt NSSS power considering the revised PCWG parameters that are associated with the EPU conditions:

Pressurizer Spray Flow Capability Pressurizer Relief Tank Sizing Pressurizer Relief Tank Setpoints Pressurizer Surge Line Data Pressurizer Surge Line Pressure Drop Pressurizer Relief Line Pressure Drop The pressurizer safety valves operate to prevent the RCS from being pressurized above its Safety Limi of-293-psig. Each safety valve is designed (i.e., rated) to relieve at least 345,000 lb per hour of saturated 6517-9.doc-092304 9-5

FENOC EXT ENDED POWER UPRATE 5 3.t 1 5

steam at the valve set point of 2485 psig. The safety analysis for EPU presented in Sectio4^5.3.6con1ir%

that the installed pressurizer safety valves are adequate for at-power overpressure protection.

9.1.4 Acceptance Criteria and Results 9.1.4.1 Pressurizer Spray Flow The design basis minimum pressurizer spray flow requirement (total) was established at 600 gpm. The minimum calculated flow (considering RCS process conditions and RCS best estimate flow) should be at or above this value. Otherwise, RCS control system transient analyses, which inherently considered this flow, would have to be reanalyzed. The minimum RCS best estimate flow is calculated based on a maximum SG tube plugging level of 22% and the maximum RCS best estimate flow is calculated based on a minimum SG tube plugging level of 0%. The calculated minimum pressurizer spray flow based on minimum RCS best estimate flow is 713 gpm for BVPS-I and 787 gpm for BVPS-2. The calculated maximum pressurizer spray flow based on maximum RCS best estimate flow is 776 gpm for BVPS-I and 854 gpm for BVPS-2. These values exceed the-minimum flow requirement of 600 gpm (total); thereby supporting RCS control systems transient analyses.

9.1.4.2 Pressurizer Spray Line Temperature In the assessment of system operation, the minimum RCS T.1d must be several degrees higher than the pressurizer spray line low temperature alarm setpoint. The minimum RCS T.,,d is limited to 530'F, which corresponds to operation near the bottom of the RCS T.,, range. Since operation is expected to be in the middle to upper portion of the Tan range, To.d during operation is expected to be at least several degrees above the 530'F minimum value. Thus, the current spray line low temperature alarm setpoints of 515IF for BVPS-I and 530VF for BVPS-2 are sufficiently below the expected T,.od during operation to avoid unnecessary alarms. Thus, changes to the spray line low temperature alarm setpoints are not required.

9.1.4.3 RCS Temperatures In the assessment of system operation, the maximum expected RCS Throt must be less than or equal to the maximum RCS design temperature of 6500 F. The maximum RCS T,,,t of6170 F is still less than the RCS design temperature.

9.1.4.4 Pressurizer Relief Tank Sizing and Level Alarm Setpoints In the assessment of the PRT relief capability, the desirable acceptance criteria for the PRT is "successful" operation following a maximum expected pressurizer discharge condition. The PRT nominal liquid and gas volumes specified for the tank for full power operation are based on the following Westinghouse PRT design criteria:

1.

The PRT initial water volume was selected to limit the final water temperature (following a steam discharge) to 2000F. This is the maximum allowable temperature for discharge to the Liquid Waste Disposal System without external cooling.

6517-9.doc-092304 9.6 6517-9.dxo-0923 9-6