L-05-154, Supplemental Information for License Amendment Request Nos. 302 and 173

Supplemental Information for License Amendment Request Nos. 302 and 173

ML052850145
Person / Time
Site:	Beaver Valley
Issue date:	10/07/2005
From:	Lash J FirstEnergy Nuclear Operating Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
L-05-154
Download: ML052850145 (33)

Text

FEN OC _O Beaver Valley Power Station Route 168 v~t PO. Box 4 FirstEnergy Nuclear Operating Company Shippingport, PA 15077-0004 James H. Lash 724-682-7773 Director,Site Operations October 7, 2005 L-05-154 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. 302 and 173 Pursuant to 10 CFR 50.90, FirstEnergy Nuclear Operating Company (FENOC) requested amendments to the above licenses in the form of changes to the Beaver Valley Power Station (BVPS) Operating Licenses and Technical Specifications. License Amendment Requests 302 and 173, transmitted by FENOC letter L-04-125 dated October 4, 2004, proposed Operating License and Technical Specification (TS) changes that support an increase in the licensed power level from the current level of 2689 MWt to 2900 MWt Rated Thermal Power (RTP). This Extended Power Uprate (EPU) License Amendment Request (LAR) also proposed changes reflecting the installation of replacement steam generators in BVPS Unit No. 1.

FENOC License Amendment Request 320, known as the replacement steam generator (RSG) LAR, was transmitted by FENOC letter L-05-069 dated April 13, 2005. The RSG LAR contains those Technical Specification changes proposed in FENOC letter L 125, the Extended Power Uprate (EPU) LAR, that are needed to replace the BVPS Unit No. 1 steam generators.

Enclosures 1 through 5 provide supplemental information that pertains to the EPU LAR.

The supplemental information is the result of a variety of actions associated with the review of the RSG and EPU submittals. The reason for the supplemental information is provided in each of the enclosures. The content of each enclosure is reflected in the enclosure title. The regulatory commitments contained in this letter are provided in Enclosure 6.

The responses contained in this transmittal have no impact on either the proposed Technical Specification changes or the no significant hazards consideration transmitted by FENOC letter L-04-125. -\Cc I

Beaver Valley Power Station, Unit Nos. 1 and 2 Supplemental Information for License Amendment Request Nos. 302 and 173 L-05-154 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 October 7, 2005.

Sincerely, s H. Lash

Enclosures:

I. Conformance to WRB-2M Conditions

2. Reactor Vessel Internals Inspection

3. Operator Actions

4. Leading Edge Flow Meter

5. Extended Power Uprate (EPU) Licensing Report Items

6. Commitment List 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)

L-05-154 Enclosure 1 Conformance to WRB-2M Conditions Reason for the contained supplemental information.

During the development of the RSG LAR (Reference 1-1), which is applicable to only BVPS Unit No. 1, it was noted that the EPU LAR (Reference 1-2), which is applicable to BVPS Unit Nos. I and 2, did not address the specified four conditions associated with the use of the WRB-2M critical heat flux correlation. Therefore, the following supplemental information is provided to demonstrate BVPS Unit No. 2 conformance with the four conditions and to provide consistency between the two License Amendment Requests.

Correlation Background Nuclear fuel correlations are used to predict the initiation of boiling crisis at the surface of the fuel rods, which might lead to fuel damage. Boiling crisis occurs when the heat flow rate at the cladding surface exceeds a critical heat flux (CHF) so that the mode of heat transfer changes from nucleate boiling to film boiling.

The Vantage 5 fuel design incorporates intermediate flow mixer (IFM) grids. The IFM mixing vanes were the same as the mixing vanes in the standard support grids except the IFM grids had no structural function. Additional CHF tests were performed by Westinghouse for this design and a new CHF correlation was developed called WRB-2. The WRB-2 correlation is similar to the WRB-1 correlation but includes a term that accounts for the change in CHF performance as grid spacing changes. Westinghouse has further modified the fuel design to reduce fuel rod mechanical wear and to further improve thermal/hydraulic performance. In the modified fuel design, the mixing vanes are slightly longer than the previous design. Critical heat flux tests of the modified fuel were conducted with and without control rod guide thimbles, and with and without modified intermediate flow mixer grids. Although the data from these tests could be successfully correlated using WRB-2, a better correlation was obtained when a multiplier "M" was developed using statistical regression techniques. The improved correlation is called WRB-2M. The WRB-2M correlation would be applicable to the Westinghouse RFA and RFA-2 fuel products which are used at both BVPS units.

WRB-2M Correlation Condition Conformance The NRC Safety Evaluation Report dated December 1, 1998 (Reference 1-3) states that a utility's use of WRB-2M correlation with a Departure from Nucleate Boiling Ratio (DNBR) limit of 1.14 for plant safety analyses, as described in WCAP-15025-P-A (Reference 1-4) may be approved by the NRC staff, and may be used provided the specified four conditions are met.

Each of the four conditions, and their fulfillment, is addressed below.

Condition 1. "Since WRB-2M was developed fiom test assemblies designed to simulate Modified 17x17 Vantage 5H fuel, the correlation may only be used to perform evaluation for fuel of that type without further justification. Modified Vantage 5H fuel with or without modified intermediate flow mixer grids may be evaluated with WRB-2M."

L-05-154 Enclosure 1 Page 2 of 3 This condition is met. The structural mid-grid design used in the RFA fuel assembly is a minor modification of the Modified Low Pressure Drop mid-grid that was addressed in WCAP-15025-P-A for use with the WRB-2M DNB correlation. The RFA mid-grid design was evaluated by means of the NRC-approved Fuel Criteria Evaluation Process (FCEP)

(Reference 1-5). By complying with the requirements of FCEP, it has been demonstrated that the new mid-grid design meets all design criteria of existing tested mid-grids that form the basis of the WRB-2M correlation database and that the WRB-2M correlation with a 95/95 correlation limit of 1.14 applies to the new RFA mid-grid. As required by FCEP, the Westinghouse notification to the NRC of the RFA mid-grid design modifications and the validation of the WRB-2M DNB correlation applicability to the RFA mid-grid was provided in written notification to the NRC (Reference 1-6).

Condition 2. "Since WRB-2M is dependent on calculated local fluid properties, these should be calculated by a computer code that has been reviewed and approved by the NRC staff for that purpose. Currently WRB-2M with a DNBR limit of 1.14 may be used with the THINC-IV computer code. The use of VIPRE-01 by Westinghouse with WRB-2M is currently under separate review."

This condition is met. For the RFA fuel in BVPS Unit 2, the analysis of the RFA fuel was based on the VIPRE computer code (as licensed for Westinghouse in Reference 1-7) and the WRB-2M DNB correlation with a 95/95 correlation limit of 1.14. The use of VIPRE by Westinghouse with WRB-2M was approved by the NRC as part of Reference 1-8. As discussed for Condition 1, the Westinghouse notification to the NRC of the validation of the WRB-2M DNB correlation ntf. applicability to the RFA mid-grid was provided in Reference 1-6.

, Condition 3. "WRB-2M may be used for PWR plant analyses of steady state and reactor transients other than loss of coolant accidents. Use of WRB-2M for loss of coolant accident analysis will require additional justification that the applicable NRC regulations are met and the computer code used to calculate local fuel element thermal/hydraulic properties has been approved for that purpose."

This condition is met. The WRB-2M correlation is not used for the loss of coolant accident analysis of the RFA fuel in BVPS Unit 2.

Condition 4. "The correlation should not be used outside its range of applicability defined by the range of the test data from which it was developed. The range is listed in Table 1."

This condition is met. Application of the WRB-2M correlation to the RFA fuel upgrade in BVPS Unit 2 was consistent with the range of parameters specified in Table 4-1 of WCAP-15025-P-A.

L-05-154 Enclosure I Page 3 of 3 Conclusions The supplemental information provided in this enclosure documents that the four specific conditions of the WRB-2M correlation are met for BVPS Unit 2. The addition of this supplemental information does not alter the no significant hazards consideration determination documented in Reference 1-2. Specific references to the WRB-2M correlation in the no significant hazards consideration determination documented in Reference 1-2 are not necessary because the WRB-2M correlation is part of the VIPRE code and the VIPRE code is explicitly referenced in the no significant hazards consideration determination.

Enclosure I References 1-1 FENOC Letter L-05-069, License Amendment Request 320, dated April 13, 2005.

1-2 FENOC Letter L-04-125, License Amendment Requests 302 and 173, dated October 4, 2004.

1-3 NRC Safety Evaluation Report, "Acceptance for Referencing of Licensing Topical Report WCAP-15025-P, Modified WRB-2 Correlation, WRB-2M, for Predicting Critical Heat Flux in 17x17 Rod Bundles with Modified LPD Mixing Vane Grids (TAC NO.

MA1074)," December 1, 1998.

1-4 WCAP-15025-P-A, "Modified WRB-2 Correlation, WRB-2M, for Predicting Critical Heat Flux in 17x17 Rod Bundles with Modified LPD Mixing Vane Grids," April 1999.

1-5 Davidson, S. L. (Ed.), "Westinghouse Fuel Criteria Evaluation Process," WCAP-12488-A, October 1994.

1-6 Letter from H. A. Sepp (Westinghouse) to J. S. Wermiel (NRC), "Fuel Criterion Evaluation Process (FCEP) Notification of the RFA-2 Design, Revision I (Proprietary),"

LTR-NRC-02-55, November 13, 2002.

1-7 WCAP-14565-P-A, "VIPRE-01 Modeling and Qualification for Pressurized Water Reactor Non-LOCA Thermal-Hydraulic Safety Analysis," October 1999.

1-8 NRC Safety Evaluation Report, "Acceptance for Referencing of Licensing Topical Report WCAP-14565, VIPRE-01 Modeling and Qualification for Pressurized Water Reactor Non-LOCA Thermal-Hydraulic Safety Analysis (TAC NO. M98666)," January 19, 1999.

L-05-154 Enclosure 2 Reactor Vessel Internals Inspection Reason for the contained supplemental information.

During a phone call on June 20, 2005 with the NRC staff, the reviewer requested the following supplemental information to support the response to Questions J.8 and J.9 of Reference 2-1.

1. Supplemental response for the reactor vessel (RV) surveillance capsule withdrawal schedules to confirm that the NRC had previously approved the withdrawal schedules that were submitted in Table 7-1 of WCAP-15771 for BVPS Unit No. 1 and Table 7-1 of WCAP-1 5675 for BVPS Unit No. 2.

2. Supplemental response providing a new commitment for the RV internals at BVPS Unit Nos.

1 and 2 to implement the results of the Materials Reliability Program's (MRP's) industry recommended inspection initiatives on pressurizer water reactor (PWR) RV internals. The NRC reviewer referred to the Waterford commitment as an acceptable example.

Supplemental Information

1. The capsule withdrawal schedule submitted in Table 7-1 ofWCAP-15771 for BVPS Unit No. I was approved by NRC Safety Evaluation Report dated January 13, 2003, "BEAVER VALLEY POWER STATION, UNIT I - CHANGES TO THE REACTOR PRESSURE VESSEL SURVEILLANCE CAPSULE WITHDRAWAL SCHEDULE (TAC NO.

MB3901)."

The capsule withdrawal schedule submitted in Table 7-1 of WCAP- 15675 for BVPS Unit No. 2 was approved by NRC Safety Evaluation Report dated March 19, 2002, "BEAVER VALLEY POWER STATION, UNIT 2 - CHANGES TO THE REACTOR PRESSURE VESSEL SURVEILLANCE CAPSULE WITHDRAWAL SCHEDULE (TAC NO.

MB2974)."

2. FirstEnergy Nuclear Operating Company (FENOC) is currently an active participant in the Electric Power Research Institute (EPRI) MRP research initiatives on aging related degradation of reactor vessel internals components. By way of this submittal, FENOC commits to continue its active participation in the MRP initiative to determine appropriate reactor vessel internals degradation management programs.

Conclusions The supplemental information provided does not impact the no significant hazards consideration determination documented in Reference 2-2 because the supplemental information has no impact on the three no significant hazards consideration questions.

Enclosure 2 References 2-1 FENOC Letter L-05-078, Responses to a Request for Additional Information in Support of License Amendment Request Nos. 302 and 173, dated May 26, 2005.

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

L-05-154 Enclosure 3 Operator Actions Reason for the contained supplemental information.

During a telephone call held on August 4, 2005 with the NRC reviewers, BVPS personnel were requested to provide information regarding request for additional information (RAI) response L.3 "Operating Procedures" submitted by Reference 3-1 in support of the EPU LAR.

Specifically, the following questions were asked:

1. How does EPU affect the operator's ability to perform the functions required?

2. How exactly do the operator action times change? (amount of change and if the time increases or decreases)?

3. For the operator initiator times, has the licensee done some sort of run through to determine if they can complete the required tasks in an acceptable time?

The NRC reviewer also asked that the following information discussed during the call be included in the response. 1) Are the simulators separate or are they the same for each unit?

2) How many crews would perform the validations? and 3) Describe the Emergency Operating Procedure (EOP) validation process.

Supplemental Information The following responses are provided to the three questions listed above.

1. The operator's ability to perform the functions required does not change for EPU. The opeators are trained on emergency and abnormal operating procedures, and as part of the procedural change process, all of the crews require training on the changes as a result of EPU.

2. See Table 3-1, "Comparison to Operator Action Times in BVPS EPU UFSAR Safety Analysis." These times are the operator action times used in the safety analyses. The EPU and current analysis times are provided to identify the changes. The loss of coolant accident (LOCA), non-LOCA and main steamline break (MSLB) operator action times are not significantly impacted by EPU analysis. The operator action times assumed within the steam generator tube ruptures (SGTR) overfill analysis did shorten in several instances, but a simulator run proved that the overall time to safety injection (SI) termination was not impacted and this total time is the critical time for the overfill analysis.

3. The new operator response times are in the process of being validated as part of the EOP review process. These validations are performed on the simulator for control room actions. Actions outside the control room are being validated via operator walkdowns as part of the procedural change process. The operator action times are monitored and evaluated to ensure the operator can perform the required tasks within an acceptable time to satisfy the event acceptance criteria.

L 154 Enclosure 3 Page 2 of 6 The response to the simulator request and the validation process follows.

Each unit has its own specific plant simulator. One crew at each unit performs the validation of the EOPs for EPU. All of the remaining crews are trained on the changes prior to plant startup.

A summary of the BVPS EOP validation process (1/20M-53B.1, "Generation, Revision, Review And Approval Of Emergency Operating And Abnormal Operating Procedures") is described below.

The validation process is conducted in three phases; Preparation, Assessment and Resolution.

A. The Preparation Phase consists of the following actions of various members:

1. Operations Manager or designee shall:

a. Determine which validation method to use (Table-Top, Walk-Through, Simulator, Talk-Through)

b. Designate an individual knowledgeable in EOP usage as the Review Team Chairman (normally an SRO)

c. Provide Operations personnel to participate in the validation

d. Ensure other disciplines are invited to participate as needed in the validation process (Training, QA/QC, Engineering, Human Performance)

e. Coordinate with Training the use of the Simulator (if applicable)

2. Review Team Chairman shall:

a. Obtain and become familiar with the EOP changes.

b. Ensure correct validation method is used.

c. Recommend what team members are needed for validation.

d. Determine scenarios for validation if simulator is used.

B. The Assessment Phase may consist of any of the following as determined by the Operations Manager and Review Team Chairman:

• Table-Top A review of the draft EOP by the Review Team, conducted in a seminar environment

• Walk-Through A step-by-step walk-through in the plant of the draft EOP being validated

• Simulator Objective observation of the performance of the draft EOP on the simulator, applying specific evaluation criteria to determine the acceptability of the EOP.

• Talk-Through The team reads and evaluates the understandability of the steps, notes or cautions in the EOPs. This method can be used for simple changes or as a final validation of proposed corrections or resolutions for discrepancies that have been identified in other validation activities.

L-05-154 Enclosure 3 Page 3 of 6 C. The Resolution Phase consists of the following:

1. Review discrepancies

2. Research and propose resolutions for discrepancies

3. Discuss discrepancies with Operations Manager or designee

4. Incorporate approved resolutions into procedures Conclusions The supplemental information does not impact the no significant hazards consideration determination documented in Reference 3-2 because it consists of additional information pertaining to operating actions assumed in the EPU safety analyses and does not impact the three no significant hazards consideration questions. References 3-1 FENOC Letter L-05-078, Responses to a Request for Additional Information in Support of License Amendment Request Nos. 302 and 173, dated May 26, 2005.

3-2 FENOC Letter L-04-125, License Amendment Requests 302 and 173, dated October 4, 2004.

L-05-154 Enclosure 3 Page 4 of 6 Table 3-1 Comparison of Operator Action Times in BVPS EPU UFSAR Safety Analysis UFSAR Operator Action Operator Action Time Used in Operator Action Time Used in Safety Analysis I I EPU Analysis Current Power Analysis Loss of Coolant Accident (LOCA)

LOCA Initiate switchover to At the following times after the At the following times after the Switchover from Cold Leg simultaneous hot start of the event: start of the event:

Recirculation to Hot Leg leg/cold leg recirculation 6.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> (BVPS-l) 8.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> (BVPS-l)

Recirculation (BVPS- I) or to hot leg 6.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> (BVPS-2) 7.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> (BVPS-2) recirculation (BVPS-2)

LOCA Initiate cycling between At the following times after the At the following times after the Switchover cycling between hot leg recirculation and start of the previous initiation of start of the previous initiation of Hot Leg Recirculation and cold leg recirculation a recirculation alignment: a recirculation alignment:

Cold Leg Recirculation 9.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> (BVPS-2) 11.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> ( BVPS-2)

(BVPS-2)

Non-Loss of Coolant Accident (Non-LOCA)

Non-LOCA Terminate uncontrolled Within 15 minutes after the start Within 15 minutes after the start Uncontrolled Boron boron dilution flow to of the event for all Modes of the event for all Modes Dilution the RCS (Modes 1, 2 and 3)

Non-LOCA Terminate auxiliary Within 15 minutes after low-low Within the following times after Main Feedline Break feedwater flow to the level is reached in the faulted SG low-low level is reached in the faulted steam generator faulted SG:

10 minutes (BVPS-l) 15 minutes (BVPS-2)

Non-LOCA Terminate high head Within 10 minutes after the start There is no current power Spurious SI - Pressurizer safety injection flow to of the event pressurizer overfill analysis for Overfill the RCS BVPS-1 Within 10 minutes after the start of the event (BVPS-2)

Non-LOCA Mitigate uncontrolled Within 10 minutes after the start Within 10 minutes after the start Loss of Offsite Power - charging flow to the of the event of the event Pressurizer Overfill (due to RCS in conjunction charging/letdown with no letdown flow malfunction) from the RCS

L-05-154 Enclosure 3 Page 5 of 6 Table 3-1 (Continued)

Comparison of Operator Action Times in BVPS EPU UFSAR Safety Analysis UFSAR Operator Action Operator Action Time Operator Action Time Used in Safety Analysis IUsed in EPU Analysis Current Power Analysis Steam Generator Tube Rupture (SGTR)

SGTR " 1. Isolate auxiliary Within the following times There is no current power Overfill Analysis feedwater flow to the after reactor trip: LOFTTR2 SG overfill ruptured SG 6.8 minutes (BVPS-1) operational analysis for BVPS-I 5.5 minutes (BVPS-2)

Within 9.1 minutes after reactor trip (BVPS-2)

2. Isolate steam flow (close Within the following times There is no current power MSIV) from the ruptured after reactor trip: LOFTTR2 SG overfill SG 16.7 minutes (BVPS-1) operational analysis for BVPS-1 15.0 minutes (BVPS-2)

Within 9.1 minutes after reactor trip (BVPS-2)

3. Initiate cooldown from Within the following times There is no current power the intact SGs via the main after the MSIV is closed: analysis for actions inside the steam system after MSIV main control room or LOFTTR2 closure 1. For actions from inside SG overfill operational analysis the main control room: for BVPS- 1 2.4 minutes (BVPS-1) 2.0 minutes (BVPS-2)

2. For actions from outside Within 9 minutes after the the main control room: MSIV is closed for action from 10.0 minutes (BVPS-1) outside main control 7.0 minutes (BVPS-2) room(BVPS-2)

4. Initiate RCS Within the following times There is no current power depressuriztion (open after reaching the end of LOFTTR2 SG overfill pressurizer PORV) after cooldown target operational analysis for BVPS- 1 completion of the temperature:

cooldown 3.0 minutes (BVPS-1) Within 2.5 minutes after 4.0 minutes (BVPS-2) reaching the end of cooldown target temperature (BVPS-2)

5. Terminate SI (isolate the Within the following times There is no current power high bead safety injection after reaching the end of LOFTTR2 SG overfill flow path) after completion RCS depressurization operational analysis for BVPS- 1 of RCS depressurization target pressure:

4.9 minutes (BVPS-1) Within 1.25 minutes after 3.0 minutes (BVPS-2) reaching the end of RCS depressurization target pressure (BVPS-2)

L-05-154 Enclosure 3 Page 6 of 6 Table 3-1 (Continued)

Comparison of Operator Action Times in BVPS EPU UFSAR Safety Analysis UFSAR Operator Action Operator Action Time Operator Action Time Used in Safety Analysis Used in EPU Analysis Current Power Analysis Main Steam Line Break (MSLB) Mass and Energy (M&E) Releases MSLB M&Es Isolate auxiliary feedwater Within 30 minutes after the Within the following times after Inside Containment (for flow to faulted SG start of the event the start of the event:

containment response) 10 minutes (BVPS-1) 30 minutes (BVPS-2)

MSLB M&Es Trip the reactor, isolate Within 30 minutes after the Within the following times after Outside Containment (basis main feedwater flow to and start of the event the start of the event:

for M&Es that define EQ steam flow from faulted 10 minutes (BVPS-1) profile) SG and isolate auxiliary 30 minutes (BVPS-2) feedwater flow (if applicable) to faulted SG Notes:

1. The SGTR analysis for BVPS-2 is a licensing basis safety analysis while the SGTR analysis for BVPS- 1 is an operational response analysis for operator training purposes. Operator actions are modeled in conjunction with the performance of the RCS and steam generators in the LOFTTR2 computer code to achieve the desired goal of preventing overfill of the ruptured SG.

L-05-154 Enclosure 4 Leading Edge Flow Meter Reason for the contained supplemental information.

During a telephone call held on July 28, 2005 with the NRC reviewers, BVPS personnel were requested to provide supplemental information regarding request for additional information (RAI) response I. 1 - I&C Section; Leading Edge Flow Meter (LEFM) submitted by Reference 4-1 in support of the EPU LAR.

Supplemental Information Reference 4-2 included Attachment C-2, Licensing Requirements Manual, which addresses BVPS Unit No. 2 operation with an inoperable LEFM. As defined in Section 3.8, Reactor Power will be reduced to 98.6% rated thermal power (RTP) should the LEFM be inoperable prior to the next required daily calorimetric heat balance. The asterisk footnote on the BVPS Unit No. 2 LRM markup submitted as part of Reference 4-2 was not corrected for operation at the extended power uprate but identifies the current plant operating conditions. As part of implementation, this footnote is changed based on power ascension testing to properly reflect a BVPS Unit No. 2 power reduction of 1.4% RTP with the LEFM declared inoperable.

The asterisk footnote is applicable to BVPS Unit No. 2 only because of an inaccuracy associated with the BVPS Unit No. 2 venturis. As stated previously, the power levels specified in the asterisk footnote will be changed as the power level is increased. The values will reflect 98.6%

of RTP as RTP is raised because power must be limited to 98.6% of RTP when the LEFM is inoperable, regardless of the numerical value of RTP.

Conclusions The supplemental information being provided does not impact the no significant hazards consideration determination documented in Reference 4-2. There is no change to the LEFM footnote and the supplemental information being provided is immaterial to the no significant hazards consideration. References 4-1 FENOC Letter L-05-078, Responses to a Request for Additional Information in Support of License Amendment Request Nos. 302 and 173, dated May 26, 2005 4-2 FENOC Letter L-04-125, License Amendment Requests 302 and 173, dated October 4, 2004.

L-05-154 Enclosure 5 Extended Power Uprate (EPU) Licensing Report Items Reason for the contained supplemental information.

During the development of the replacement steam generators (RSG) license amendment request (LAR), items needing correction, clarification or enhancements in the EPU Licensing Report (Enclosure 2 of Reference 5-2) were identified. The items were corrected in the RSG LAR submittal (Reference 5-1). The identification of these items resulted in more rigorous review and validation of the EPU submittal.

Supplemental Information Markups of the EPU Licensing Report pages are provided in Attachment A to this enclosure.

Table 5-1 lists the affected pages contained in Attachment A and provides a discussion pertaining to the items and the changes noted in the attachment.

Table 5-1 EPU Licensing Report Items Page Discussion 5-11 Revision provides clarification of the acceptance criteria. There is no effect on the analysis because both criteria do not need to be met.

5-24 The revised values is the sequence event table do not impact the limiting case which is based on maximum PCT. The revised values reflect the calculation values and are the result of transcription errors. Thus, there is no effect on the analysis.

5-80 The revised value is more conservative than the value originally reported. The revised value reflects the impact of Technical Bulletin 04-12. The revised value reflects the calculation value and is the result of a transcription error. Thus, there is no effect on the analysis.

5-89 The change is an enhancement that provides more detail and documents consistency with the Technical Specifications. Thus, there is no effect on the analysis.

5-173 The change is an enhancement that provides more detail and documents consistency with the analysis methodology. Thus, there is no effect on the analysis.

5-177 The change is an enhancement that provides consistency with the analysis. The revised statement is more conservative than the original statement. Thus, there is no effect on the analysis.

5-199 The change is a correction of the positioning of the values. The revised values reflect the calculation values and is the result of a transcription error. Thus, there is no effect on the analysis.

5-236 The revised uncertainty value is more conservative than the value originally reported. The revised value reflects the calculation value and is the result of a transcription error. Thus, there is no effect on the analysis.

L-05-154 Enclosure 5 Page 2 of 3 Table 5-1 EPU Licensing Report Items Page Discussion 5-295 The change is an enhancement that avoids potential confusion with Table 5.3.20-I A which does not report the steam system piping failure at full power case. Thus, there is no effect on the analysis.

5-297 The revised values reflect the calculation values and are the result of transcription errors. Although one of the revised values is more conservative than the value originally reported and the other is less conservative, the magnitude of the change is inconsequential to the analysis and conclusions drawn. Thus, there is no effect on the analysis.

5-307 The revised values reflect the calculation values and are the result of transcription errors. The magnitude of the change to Peak Primary Pressure for the Loss of Load event is inconsequential to the analysis and conclusions drawn. The change to Peak Secondary Pressure for the Complete Loss of Flow event is made to reflect the limiting peak secondary pressure for all of the Complete Loss of Flow event cases run. This is done to achieve consistency with the how limiting pressures are reported for the other events, but does not result in a change to the minimum DNBR for the Unit 1 Condition II events. Acronym typographical error. Thus, there is no effect on the analysis.

5-308 The revised values reflect the calculation values and are the result of transcription errors. The magnitude of the changes to Peak Secondary Pressure for the RCCA Bank Withdrawal at Power and Peak Primary Pressure for the Partial Loss of Flow events are inconsequential to the analysis and conclusions drawn. The change to Peak Secondary Pressure for the Complete Loss of Flow event is made to reflect the limiting peak secondary pressure for all of the Complete Loss of Flow event cases run. This is done to achieve consistency with the how limiting pressures are reported for the other events, but does not result in a change to the minimum DNBR for the Unit 2 Condition II events. The revised value for Minimum DNBR for the Feedwater System Malfunctions, Feedwater Enthalpy Decrease event case is less conservative than the value originally reported. However, this does not change the minimum DNBR for the Unit 2 Condition II events. Acronym typographical error. Thus, there is no effect on the analysis.

5-316 The revised value reflects the calculation value and is the result of transcription errors. The magnitude of the change is inconsequential to the analysis and conclusions drawn. Thus, there is no effect on the analysis.

5-319 The revised value reflects the calculation value and is the result of a transcription error. The magnitude of the change is inconsequential to the analysis and conclusions drawn. Thus, there is no effect on the analysis.

5-383 The revised value reflects the calculation value and is the result of a transcription error. The magnitude of the change is inconsequential to the analysis and conclusions drawn. Thus, there is no effect on the analysis.

L-05-154 Enclosure 5 Page 3 of 3 A transcription error is defined as an error made in transferring a value from the safety analysis calculation into the EPU Licensing Report. In each case, the corrected value reflects the value used in the calculation. The correction of a transcription error has no effect on the analysis or conclusions drawn because correcting EPU Licensing Report results in the report reflecting the safety analysis calculation value.

Conclusions All of the identified items have been entered into the BVPS Corrective Action Program and evaluated for impact. None of the identified items impact the results of the EPU safety analysis or the conclusions drawn, or invalidate the no significant hazards consideration. The proposed revisions do not impact the no significant hazards consideration determination documented in Reference 5-2 because they reflect the calculations and analysis upon which the analysis conclusions were drawn and how the three no significant hazards consideration questions were answered. References 5-1 FENOC Letter L-05-069, License Amendment Request 320, dated April 13, 2005.

5-2 FENOC Letter L-04-125, License Amendment Requests 302 and 173, dated October 4, 2004.

Enclosure 5 Attachment A EPU Licensing Report Items

FENOC EXTENDED POWER UPRATE reactor coolant system blowdown ensues in which the heat from fission product decay, the hot reactor internals, and the reactor vessel continues to be transferred to the RCS fluid. The heat transfer between the RCS and the secondary system may be in either direction and is a function of the relative temperatures or the primary and secondary conditions. In the case of continuous beat addition to the secondary during a period of quasi-equilibrium, an increase in the secondary system pressure results in steam relief via the steamn generator safety valves.

When a Small Break LOCA occurs, depressurization of the RCS causes fluid to flow into the loops from the pressurizer resulting in a pressure and level decrease in the pressurizer. The reactor trip signal subsequently occurs when the pressurizer low-pressure reactor trip setpoint. conservatively modeled as 1935 psia, is reached LOOP is postulated to occur coincident with reactor trip. A safety injection signal is generated when the pressurizer low-pressure safety injection setpoint. conservatively modeled as 1745 psia for BVPS- I and 1760 psia for BVPS-2, is reached. Safety injection flow is delayed 27 seconds after the occurrence of the low-pressure condition. This delay accounts ror signal processing. diesel generator start up and emergency power bus loading consistent with the loss-of-olfsite power coincident with reactor trip, as well as the pump acceleration and valve delays.

The following countermeasures limit the consequences of the accident in two ways:

I Reactor trip and borated water injection supplement void fornation in causing a rapid reduction of nuclear power to a residual level corresponding to the delayed fission and Fission product decay. No credit is taken in the Small Break LOCA analysis for the boron content of the injection water. In addition, credit is taken in the Small Break LOCA analysis for the insertion of Rod Cluster Control Assemblies (RCCAs) subsequent to the reactor trip signal. considering the most reactive RCCA is stuck in the flil out position. A rod drop time of 2.7 seconds was used while also considering an additional 2 seconds for the signal processing delay time. Therefore, a total delay time of4.7 seconds from the time of reactor trip signal to full rod insertion was used in the Small Break LOCA analysis.

2 Injection of borated water provides sufficient flooding of the core to prevent excessive cladding temperatures During the earlier part or the Small Break transient (prior to the postulated loss-of-offsite power coincident with reactor trip), the loss of flow through the break is not sufficient to overcome the positive core flow maintained by the reactor coolant pumps. During this period, upward flow through the core is maintained. However, following the reactor coolant pump trip (due to a LOOP) and subsequent pump coastdown, a period of core uncovery occurs. Ultimately, the Small Break transient analysis is terminated when the top of the core is recoverepjinttECCS flow provided to the RCS exceeds the break flow rateC pr[ning adA9ion; t cor uno-cryd-vbe ueds rod-hezt or- the Core_ Ai4m7 I Sn/rusgnJ The core heal transfer mechanisms associated with the Small Break transient include the break itself. the injected ECCS water. and the heat transferred from the RCS to the steam generator secondary side. Main Feedwaler(MFW) is conservatively isolated in lseconds for BVPS-I (consisting of a 3 second signal delay time and a 7 second main feedwater isolation valve stroke time) and 7 seconds for BVPS-2 (consisting of a 2 second signal delay time and a 5 second main keedwater isolation valve stroke time) following the generation of the pressurizer low-pressure Si signal. Additional makeup water is also provided to the secondary using the auxiliary feedwater (AFW) system. An AFW actuation signal is 5-Il 6517 i-Npdoc-492!tea

)04 i-NPdoe-092 5$?? 541

FENOC EXTENDED POWER UPRATE Table 5-2.24A BYPS-I NOTRUMP Results Event Time (see) 2-Inch 3-4nch 44ncb Break Iniliation 0 0 0 Reactor TnpSignal 28.9 12.3 7.3 S-Signal 42-3 20.8 14.4 SI Flow Delivered 69.9 47.8 41.4 Loop Seal Clearing'" 925 420 23Z42 Core Uncovery 1020 S62 63,- 56 I Accumulator Injection NIA 1355 766 RWST Volume Delivered 3025 3003 2992 PCTTume 3158 1734 5+1 I Core Recovery"' >TMAX >TMAX >TMAX Notes:

(I) psealclearidefinedasbreakvapoflow>l Iros.

(2) For iCe cases where core recovevy is> TMAX, basis for transien mnnination an be concluded based on the rotlowing: (I)Tlh RCS system pressurc is dc asing which wiU inc SI ilow, (2) Tol RCS systemmuss is ineasing due io SI flow exceeding break ow, and (3)Core mixturr level as begun to increase and is expected to continue for the remainder of the accident. _-,

6s1?7-5Nr.doc0s-09Z4 5-24

FENOC EXTENDED POWER UPRATE Table 5.3.1-4B BVPS-2 Non-LOCA Key Accident Analysis Assumptions NSSS Thermal Design Flow (per Loop) 87,200 gpm Minimum Measured Flow (per Loop) 88,933 gpm Programmed Full Power Vessel Average Temperature 580.0° to 566.20 F Maximum Steam Generator Tube Plugging Level 22%

Max FAH 1.56 (RTDP) 1.62 (STDP)

DNB Methodology (where applicable) RTDP Max EOL MDC 0.43 £klgIcc Max BOL MTC +5 pcinPF <70% RTP ramping to 0 at 100% RTP Initial Condition Uncertainties:

Power +I- 0.6% RTP Temperature +/- 4.0F('

Pressure 45 psi Steam Generator Water Level +1-7% NRS2 Pressurizer Water Level +1- 7% span Notes:

(I) The analyses also include X3.5 F for loop-to-loop asymmetry. -2°F to allow for inpit tion below the design average temperature and a +13P bias.

(2) The calculated final Stearn Generator Water Level uncertainties are +3.5 0 /. for BVPS-2. For non-LOCA analyses, a negative bias means that the channel indicates higher than actual and a positive bias means the channel indicates lower than actual. The Feedwater System Pipe Break analysis (see Section 5.3.17) assumed uncertainties of

+7%I-10.3% NRS. For all other events, only the positive uncertainty is applicable and a +7s% NRS was assumed.

6517-5-NP doc492304 5-80

FIENOC EXTENDED POWER UPRATE 533.2 Input Parameters and Assumptions A number of cases were analyzed assuming a range of reactivity insertion rtes for both minimum and maximum reactivity feedback conditions at various power levels. The cases presented in Section 5.3.3.4 are representative for this cvenL For an uncontrolled RCCA bank withdrawal at power accident, the analysis assumes the following conservative assumptions:

a. This accident is analyzed with the Revised Thermal Design Procedure (Reference 2). Initial reactor power, RCS pressure, and RCS temperature are assumed to be at their nominal values, adjusted to account for any applicable measurement biases, consistent with steady-state full power operation. Minimum Measured Flow is modeled. Uncertainties in initial conditions are included in the DNBR limit as described in Reference 2.

b. For reactivity coefficients, two cases are analyzed. for I. Minimum Reactivity Feedback: A +5 pcmJ0F temperature mnor coefficient and a least-negative Doppler-only power coefficient rcn thc basis for the begirning-of-life (BOL) minimum reactivity feedback assumptionAjw Tc.4 F' EO lass;^c C t*s l c^~eL zt'-1jel iAc&{1 P0r oct"l*

2. Maximum Reactivity Feedback: A consetrvativety large positive moderator density Co ct'I coefficient of 0.43 Ak/gfem3 (corresponding to a large negative moderator temperature Ilie_ ;)PS ; .

coefficient) and a most-negativec Doppler-only power coefficient form the basis for the i4c4 S<u4 ,

end-of-life (EOL) rmax imum reactivity feedback assumption-c The reactor trip on high neutron flux is assumed to be actuated at a conservative value of 116% of nominal full power. The AT trips include all adverse instrumentation and selpoint errors, while the delays [or the trip signal actuation are assumed at their maximum values.

d. The RCCA trip insertion characteristic is based on the assumption that the highest-worth rod cluster control assembly is stuck in its fully withdrawn position-c A range of reactivity insertion rates arc examined. The maximum positive reactivity insertion rate is greater than that which would be obtained from die simultaneous withdrawal of the two control rod banks having the maximum combined worth at a conservative speed (48.125 inches/minute, which corresponds to 77 stcpstminute).

f. Power levels of 10. 60 and 100%o ofthe NSSS power of 2910 MWt are considered.

533.3 Description of Analysis The purpose of this analysis is to demonstrate the manner in which the protection functions described above actuate for various combinations of reactivity insertion rates and initial conditions. Insertion rate and initial conditions determine which trip function actuates first.

549 1.5-tW4oc492304 6 I 7-5SHPAW923" 6515 5-89

FENOC EXTENDED POWER UPRATE 5.3.9 Excessive Het Retnoval Dae To Feedwater System Malfunctions 5.3.9.1 Identification ofCauscs and Accident Description Reductions in feedwater temperature or excessive feedwater additions are means of increasing core power above full power. Such transients arc attenuated by the thermal capacity of the RCS anud the secondary sidc of the plant. The overpowertovertempctaturw protection functions (neutron high flux, overtemperature AT. and overpower AT trips) prevent any power increase that could lead to a DNBR that is less than the limit value.

An example of excessive reedwater flow would be a full opening of one feedwater control valve due to a feedwater control system malfunction or an operator error. At power, this excess flow causes a greater load demand on the RCS due to increased subcooling in the steam generator. With the plant at no-load conditions. the addition of cold feedwater may cause a decrease in RCS temperature and thus a reactivity insertion due to the efTects of thc negative moderator temperature coefficient of reactivity. Continuous excessive leedwater addition is prevented by the steam generator high-high water level trip.

A second example of excess heat removal is the transient associated with failure of the low-pressure heaters' bypass valve resulting in an immediate reduction in feedwater temperature. Al power, this increased subcooling will create a greater load demand on the RCS.

539.2 Input Parameters and Assumptions The reactivity insertion rate following a ftedwater system malfunction, attributed to tie cooldown of the RCS. is calculated with the following assumptions:

a Tkis on4analyzed with the Revised Thermal Design Procedure as described in Reference . Initial reactor power. RCS pressure, and RCS temperature are assumed to be at their nominal values, adjusted to account for any applicable measurement biases, consistent with steady-state full power operation. Minimum Measured Flow is modeled. Uncertainties in initial conditions are included in the DNBR linit as described in Reference 1. $e Zevo pver e acs rilk

b. The analyses are done at the NSSS power level of 2910 MWt . s

c. For the feedwater control valve accident at full-power conditions that result in an increase in feedwate flow to one steam geneator, one feedwater control valve is assumed to malfiuction resulting in a step increase to 162% for BVPS-I and 156% for BVPS-2 of nominal full power feedwater fow to one steam generator.

d. The increase in feedwater flow rate results in a decrease in the feedwater tempenture due to the reduced efficiency of th feedwater heaters For thc hot full power c a 51s4°f for BVPS-I and 50°F for BVPS-2 decrease inthe feedwater temperature is assumed to occur coincident with the leedwater flow increase.

e. For the feedwater control valve accident at zero-load conditions that result in an increase in feedwater flow to one steam generator. onc feedwater control valve is assumed to malfunction 5-173 6511S-lWdoc-092104 w

6SIIS-A-0 302 S-173

FENOC EXTENDED POWER UPRATE Table 5.3.9-1 Trne Sequence or Events - Eicessive Hemt Removal Due t Feedwater System Malfuactions BV`PS~l BVPS-l Event Trie (seconds) Time (seconds)

One rnainieedwater control valve rails full open 0 0 Minitnum DNBR occurs 111.0 72.5 H;-Hi steam generator water level trip setpoint is reached 108.9 114.9 Turbine trip occurs due to hi-hi steam generator level 111.4 117.4 Rod motion begins 113.4 119.4 Feedwatet isolation valves el11.9 121.9 t 0.0e_ CASV \,] crl I:,- t 5-177 651 J-5-Ptl'.doc-092)04 651liP~e20 5-177

FENOC EXTENDED POWER UPRATE Table 5-3.12-IA BViS-I Time Sequence otEventts - Rapture of 2 Main Steam Pipe Case Event Time (see)

Reactor at hot zero power with Doubleended guillotine bak occuts 0.0 oisiite power available (Unisolatable steam release paths Low Steam Pressure SIS actuation setpoint readied 0.7 case) MSIVs closed 8 seconds after SIS actuation signal t.7 Higb-bead SI pump at rated speed 27 seconds after SIS 27.7 actualion signal Main Feedwater Iow isolated 30 seconds aier SIS 30.7 actuation signal Reactor becomes cntical 32.4 Time orminimum DNBR Power rtachcs maximum leved 3M*.

Reactor returns subewcical 396.0 6~I75-tJP~dc491O4 .19 6517 5-Nrjbc.092104 5-1"

FENOC EXTElNDED POWER UPRATE Both the RCS pressure case and the ONB case assume a zero moderator temperature coefficient (MTC) and a conservatively large (absolute value) Doppler-only power coefficient. The negative reactivity from control rod insertioniscram for both cases is based on 4.01f AMkk trip reactivity from HFP.

Normal reactor control systems and engineered safety systems (e.g., Safety Injection) a*c not required to function. No single active failure in any system or component required for mitigation will adversely aficct the consequences o[ this event.

Ihe effects of asymmetric RCS flow (maximum loop-to-loop flow asymmetry of 5%/) on the Locked Rotor transients were also evaluated.

S.3.tS.3 Description of Analysis The following locked rotor / shaft break cases were analyzed:

I1. Peak RCS pressure resulting from a locked rotor I shaft break in one-of-three loops

2. Number of rods-in-DNB resulting from a locked rotor 1 shaft break in one-of-thre lhops The pressure case is analyzed using two digital conputer codes. The LOFTRAN code (Reference 2) is used to calculate thC resulting loop and core flow transients following the pump seizure, the time ot reactor trip based on the loop flow transients, the nuclear power following reactor trip, and the peak RCS pressure. The reactor coolant flow coastdown analysis performed by LOFERAW is based on.a momentum balance around each reactor coolant loop and across the reactor core. This momentum balanct is combined with the continuity equation, a punp momentum balsance, the as-built pump characteristics, and is based on conservative system pressure loss estimates The thermal behavior of the Fuel located at the core hot spot is investigated using the FACTRAN code (Reference 3) which uses the core flow and the nuclear power values calculated by LOFTRAN. The FACTRAN code includes a film boiling heat transfer coefficient.

The case analyzed to evaluate core DNB uses LOFEWAN, FACTRAN and the VIPRE code (Reference 4). The LOFTRAI and FACTRAN codes are used in the same manneras in the pressure case. The VIPRE code is used to calculate the DNBR during the transient based on the heat flux from FACTRAN and the flow from LOFWRAN.

4s For the peak Rsite evaluation, the initial pressure is conservatively estimated to be 40 psi for BVPS-I and psi tor BVPS-2 above the nominal pressure of 2250 psia to allow for initial condition uncertainties in the pressurizer pressure measurement and control channels. This is done to obtain the highest possible rise in the coolant pressure during the transient. To obtain the maximum pressure in the primary side, conservatively high loop pressure drops are added to the calculated pressurizer pressure.

The pressure response reported in Table 5.3.15-1 is at the point in the RCS having the maximum pressure.

at the outlet of the RCP in the faulted loop.

e.C..

For a conservative analysis of fuel rod behavior, the hot spot evaluation assumes that DNB occurs at the initiation of the transient and continues throughout the event. This assumption reduces heat transfer to the coolant and results in conservatively high hot spot temperatures.

5-236 65171.5-tW.doc-O2 653 304 5i1,11`4m-02Me 5-236

FENOC EXTENDED POWER UPRATE

g. Reactivity coefficients - The analysis assumed maximum moderator reactivity feedback and minimum Doppler power feedback to maximizc the power increase following the break.

h Protection system - The protection systcm features that mitigate the effects of a stearnlinc break are described in Section 53.12. This analysis only considers die initial phase of the transient from at-power conditions. Protection in tlis phase of the transient is providcd by reactor trip, if necessary. Section 5.3.12 presents the analysis of the bounding transient following reactor trip.

where other protection system features are actuated to mitigate the effects of the stcamline break.

i Control systems - The only control that is assumed to function during a full power steamline rupture - core response event is the main feedwater system. For this event, th feedwater flow is set to match the steam flow.

53.19.3 Description of Analysis The analysis of the steamline break at power for the EPU was performed as follows:

a. The LOFTRAN code (Reference I) was used to calculate the nuclear power. coe beat flux, and reactor coolant system temperature and pressure transients resulting from the cooldown following the steamlitte break.

b. Thc core radial and axial peaking factors were determined using the thermal-hydraulic conditions from LOFTRAN as input to the nuclear core models. A detailed thermal-hydraulic code, VIPRE (Reference 2), was used lo calculate the DNBR for the limiting time during the tansient. The DNBR calculations were performed using the W-3 correlation. Since the initial conditions uncertainties are not statistically included in the W-3 DNBR limit (of 1.30), uncertainties on power, temperature, pressure, etc. were applied to the limiting statepoints and the Thermal Design Flow was assumed in the calculation of the minimum DNBR.

53.19.4 Accptance Criteria and Riesults Depending on the size of the break. this event isclassified as either a Condition 111 (ialrequent fault) or Condition IV (limiting fault) event, however, the analysis is done to the more conservative Condition It acceptancp criteri. The acceptance criteria for this event are consistent with those stated in Subsection 5.3. 12.4 4AW 1t3GA4P For BVPS- I. the limiting break size from the spectrum of break sizes analyzed is 0.6 W. with l DtSBR cf I 1 c hoa flnof a.53 1.?. The T.4 sequence of events for the timitingeasc with a 0.6 (2

/ break is shown in Table 5.3.19-1. Plots for this limiting case are provided in Figures 5.3.19-lA tIhroughd5e3-. 1; i OitB c n4 lbC4I6&@

oeS For 8VPS-2, the limiting break size fron the spectrum olbreak sizes analyzed is 0.8 fl4uui 1ii Oct D4 -id a Lc u.tF 1.23. The sequence of events for this limiting case is shown in Table 5.3 19-1. Plots for this limiting case ar provided in Figures 5.3.19-1 B through 5.1.19-4B.

5-295 65t7 S-NP.doe*092304 ESti S-NPAdOC092304 5-295

FENOC EXTENDED POWER UPRATE Table 5.3.19-1 Time Sequence o(Evenis - Steam System Piping Failure atFutl Power (Core Responsc)

BVIS-I BYPS-2 Even Time (sec) Time (c)

Steam line ruptures 0.0 0.0 Overpower aT reactor trip sctpoint reached 30.4 26.5 Rods begin to drop 32.4 28.5 Micinum DNBR occurs .34s 3W. 29/0 Peak wce heat flux occurs 33.0 29.a 5-297 6S17$-t#4oc-092304 6517 S"P~loc-09210W 5-297

FENOC EXTENllDED POWER UPRATE Tatl S3.20-1A BVVS-1 Condid-n USDNB Event Results Peak reak UFSAR Report MKnimum Primary Secandary Evenit Name Section Section DNOR Pressure (psia) ressure (psts)

RCCA Bank Withdrawal from 14.1.1 5.3.2 LUmit mcA' N/A NIA Subcritical RCCA Bank Withdrawal at Power 14.1.2 5.3.3 137 N/AW' 1170.1 RCCA Misalignment 14.1.3 5.3.4 Liwit mde N/A NWA Loss of Load 14.1.7 5.3.6 2.23 27441" 1187.7 Fecdwater System Malfimciions

a. Feedwater Flow Increase 14.1.9 5.3.9 1 7 5m7' 2357.0 1124.0

b. Feedwater Emthalpy Decrease 14.1.9 5.3.9 1.67 2300.0 914.0 Excessive Load Increasc"' 14.1.10 5.3.10 Limit met Limit met Limit met RCS Depressurization 14.1.15 5.3.11 1.62 N/A WA Main Steam Pipe Rupture (HZPY" 14.2.5.1 5.3.12 Limit mes* NWA WA Partial Loss of Flow 14.1.5 5.3.13 .250" 2373.8 9S9.0 Complete Loss of Flow'3' 14.2.9 5.3.14 1.64"' 2504.1 Mq . I Limits _ 155 2748.5 12085 Nostes (t) A geaenc Wcstinejtouse evaluation adesscs peak pressu ,sfo Rod Wlithdrawal at Power analyses.

(2) Current wnwiodolgy for evahlatingtitsevent involves a comparison ofconseative geetric stalepoints to tie plant specific core Itnal limits. In all cases. the generic statepontts ebounded by Ihccewe thermal limits (3) Thse eveats are not Condition 11events but are analyzed to the mo¢nrestrictive Condition It acceptance eiteri.

(4) The analysis supports a pressurzer safety valve sctpoins toleraice of +-].O%

(5) DNB statepoints as evaluated and die coodusiont is that the limits we meIt (6) The 1.55 DN8R limit isted ebove is mtu appticabe f hese events. See Table 61-3 for die applicable ONB correlations arnd limits.

(7) rk resuultreported are ir the UR caw. An addionalease was asctyzed at IZ?conditions. It vwasecaluded that this case is bounded by the tlZP C9 aysis JFSAt 14 2 5,1 (8) Tkes values am applicable irxW L wt V5H fle.dartiatl s ofFv minianunt mDNBR is .90 I compared to a limit Orl.32 (thimbl cl) a t Complete Los ofFlow tit'nwm DNBR is 139 eoaaradto tlimit of 1.33 Itypical mel 5-307 45t 457-7.$ NPdOC.092304 NI'doct 02304 5-301

FENOC EXTENDED POWER UPRATE Table 5.3.20- I B BVPS-2 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 15.4.1 5.3.2 Limit met' *6 1 N/A N/A Subcritical RCCA Bank Withdrawal at Power 15.4.2 5.3.3 1.58 N/AtI) 1174.f I RCCA Misalignment 15.4.3 5.3.4 Limit met'" N/A N/A Loss of Load 15.2.2 & 5.3.6 1.83 2746.2(4) 1191.0 15.2.3 Feedwater System Malfunctions

a. Feedwater Flow Increase 15.1.2 5.3.9 1[967 2353.3 1141.2

b. Feedwater Enthalpy Decrease 15.1.1 5.3.9 t.(4. 2287.3 928.0 I Excessive Load Increase'2' 15.1.3 5.3.10 Limit met Limit met Limit met RCS Depressurization 15.6.1 5.3.11 1.64 N/A N/A Main Steam Pipe Rupture 15.1.5 5.3.12 Limit met"'" N/A N/A (HZPC"'

Partial Loss of Flow 15.3.1 5.3.13 2.25"s ..23641O2no*q 995.0 I 5 w 1 ZLA7 Complete Loss of Flow' 15.3.2 5.3.14 1.64' 0 2503.3 Limits -- -- 1.55 2748.5 1208.5 Notes (II A generic Westinghouse evaluation addresses peak pressures Ibr Rod Withdrawval at Power analyses.

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

(3t'Ihese events are not Condition 11events but are analyzed to the more restrictive Condition 11acceptance criteria.

(4) This analhsis supporn a pressurizer safety valve setpoint tolerance of- 1.6%1-3.0%.

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

(6) The 1.55 DNBR limit listed abo'e is not applicable forthese events. See Table 6.1-3 fortbeapplicable 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 cse is bounded bN thc HZP L analysis (UFSAR 15.1.5). I (8\ These v-alues are applicable li the RFA fuel. For the V5H-lfuel, the Partial loss of Flow minimum DNBR is 1.90 compared to a limit of 1.32 ( imble cell) and the Complete Loss of Flow minimum DNBR is 1.38 compared to alimit of 1.33 (typical cell).

in~ e i-b~

5-308 7-5-NP doc-092304 6517-5-NP 651 doc-092304 5-308

- 0 EXTENDED POWER UPRATE time-dependent flashing fraction that incorporates the expected changes in primary-side temperatures cannot be calculated. Instead. a conservative calculation of the flashing fraction is performed using the limiting conditions from the break flow calculation cases. Two time intervals are considered, as in the break flow calculations; pre-reactor trip and post-reactor trip (Si initiation occurs concurrently with reactor trip). Since the RCS and steam generator conditions are different before and after the trip, different flashing fractions would be expected.

The flashing fraction is based on the difference between the primary-side fluid enthalpy and the saturation enthalpy on the secondary side. Therefore. the highest flashing will be predicted for the case with the highest primary-side temperatures. For the flashing fraction calculations, it is conservatively assumed that all of the break flow is at the hot leg temperature (the break is assumed to be on the hot leg side of the steam generator). Similarly. a lower secondary-side pressure maximizes the difference in the primary and secondary enthalpies. resulting in more flashing. The highest pre-trip flashing fraction based on the range 0

of operating conditions covered by this analysis is for the case with a hot leg temperature of 603.9 F, an initial RCS pressure of 2250 psia, and an initial secondary pressure of 623 psia. The case with a hot leg temperature of 617'F would have a lower flashing fraction because the corresponding conservatively high secondary pressure is 831 psia and the flashing is more dependent on se ondary pressure than hot leg temperature. All cases consider the same post-trip RCS pressure of 188/7.4 psia and post-trip steam generator pressure of 932.75 psia. The highest post-trip flashing fraction, based on the range of operating temperatures covered by this analysis. is for a case with a hot leg temperature of 617'F. It is conservatively assumed that the hot leg temperature is not reduced for the 30 minutes in which break flow is calculated.

Miscellaneous Parameter Assumptions

• Low pressurizer pressure SI actuation setpoint - 1860 psia

• Lowest steam generator safety valve reseat pressure = 932.75 psia, and includes 11.6% main steam safety valve (MSSV) blowdown and 3%/0 safety valve setpoint tolerance.

5.4.1.3 Description of Analyses Performed 0

A T.,t window of 566.20 up to 580.0 F is considered. Section 2.1.1 documents four Performance Capability Working Group (PCWG) cases that have been used for the BVPS-1 SGTR analysis.

0 Cases are analyzed at a T.,, of 566.20 and 580.0 F. with 0% and 22% SGTP. All the cases support a power of 2910 MWt (NSSS power) and thermal design flow (TDF) of 87200 gpm/loop.

Break Flow, Steam Releases, and Feedwater Flows In total. four cases were considered in the SGTR thermal-hydraulic analysis to bound the EPU operating conditions. Note that these four cases are individually analyzed in order to determine the limiting steam release and limiting break flow between 0 and 30 minutes for the radiological consequences calculation. A single calculation is performed to determine long-term steam releases from, and feedwater flow to, the intact steam generators for the time interval from the start of the event (0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />) to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and from 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to RHR cut-in at 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The 0 to 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> calculations use the 0 to 30 minute intact steam 6517-5-NP doc-092304 5-316

v c FENOC EXTENDED POWER UPRATE Table :5.4.1-1 BVPS-1 Limiting SGTR Thermal-Hydraulic Results Tube Rupture Break Flow for 0 to 30 Minutes T., = 566.2°F, 0% SGTP 135,900 Ibm T,, = 566.2°F, 22% SGTP 136,300 Ibm T,,, = 580.0°F, 0°,0 SGTP 134,700 Ibm T,,, = 580.0°F, 22% SGTP 135,500 Ibm Steam Release from Ruptured SC (Post-Trip) for 0 to 30 Minutes T., = 566.2°F. 0% SGTP 55,00 Ibm I T, = 566.2°F, 22% SGTP 53,joo Ibm T., = 580.0°F. 0% SGTP 62,600 Ibm T, = 580.0°F, 22% SGTP 58,600 Ibm

• Values rounded up to the nearest 100 5-3 19 7-5.\P.doe-092304 651 7-5-\ P.doo-092304 5-319

FENOC EXTENDED POWER UPRATE 5.6.3 Steam Releases for Radiological Dose Analysis 5.6.3.1 Introduction In support of radiological dose analyses, steam and radioactivity releases to the environment are postulated to occur via the following scenarios.

• An activity level exists in the reactor coolant system (RCS): The activity level in the RCS may be low. resulting from activated corrosion products or from the potential minute release of fission material from defective fuel assemblies. The activity level may also be moderate to high, resulting from potential fuel cladding failures and the subsequent fission product release.

• A primary-to-secondary leak occurs: The most common primary-to-secondary leak would be a leak through the wall of one or more steam generator tubes. A maximum allowable leak rate is specified in the Technical Specifications based on tube integrity requirements. The Technical Specifications leakage limit is used to determine radioactivity releases to the environment.

• Secondary-side activity is released into the atmosphere: Given that a primary-to-secondary leak exists and the condenser is not available for steam dump following an accident that produces a reactor trip. steam and radioactivity will be released through the atmospheric dump valves while the plant is being brought to a cold shutdown condition. The Loss of Non-Emergency AC Power es ent. and other events that result in a loss-of-offsite power, are situations that result in the unavailabiliti of the condenser.

Vented steam releases have been calculated for the Loss of Non-Emergency AC Power, Locked Rotor, and Steamline Break esents to support the EPU Project.

5.6.3.2 Input Parameters and Assumptions The following general assumptions associated with EPU have been used in the calculation of the steam releases and feed% ater flows.

• NSSS power (2910 MWt) plus 0.6% uncertainty

• RCS average temperature (580.00 F)

• Nominal RCS pressure (2250 psia)

• Steam generator tube plugging is chosen to maximize secondary-side mass inventory. The operating conditions used in this analysis reflect the high end of the Ta., RCS temperature range, high secondary-side (steam) temperature. the low end of the main feedwater temperature range, and no steam generator tube plugging.

• Nominal steam temperature (522.\OF) for BVPS-I with the Model 54F replacement steam generators (RSGs) and nominal steam temperature (521 .90 F) for BVPS-2 with the original steam generators (OSGs).

6517-5-NP doc.A92304 5-383

L-05-154 Enclosure 6 Commitment List The following list identifies those actions committed to by FirstEnergy Nuclear Operating Company (FENOC) for Beaver Valley Power Station (BVPS) Unit Nos. 1 and 2 in this document. Any other actions discussed in the submittal represent intended or planned actions by FENOC. They are described only as information and are not regulatory commitments. Please notify Mr. Gregory A. Dunn, Manager - Licensing, at 330-315-7243 of any questions regarding this document or associated regulatory commitments.

Commitment Due Date FirstEnergy Nuclear Operating Company (FENOC) Not Applicable commits to continue its active participation in the Electric Power Research Institute (EPRI) Materials Reliability Program (MRP) initiative to determine appropriate reactor vessel internals degradation management programs.