L-2011-532, Response to NRC Reactor Systems Branch and Nuclear Performance Branch Request for Additional Information Regarding Extended Power Uprate License Amendment Request

Response to NRC Reactor Systems Branch and Nuclear Performance Branch Request for Additional Information Regarding Extended Power Uprate License Amendment Request

ML12019A074
Person / Time
Site:	Saint Lucie
Issue date:	01/14/2012
From:	Richard Anderson Florida Power & Light Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
L-2011-532
Download: ML12019A074 (73)

Text

0Florida FIPL Power & Light Company, 6501 S. Ocean Drive, Jensen Beach, FL 34957 Proprietary Information - Withhold From Public Disclosure Under 10 CFR 2.390 The balance of this letter may be considered non-proprietary upon removal of Attachment 2.

January 14, 2012 L-2011-532 10 CFR 50.90 10 CFR 2.390 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Re: St. Lucie Plant Unit 2 Docket No. 50-389 Renewed Facility Operating License No. NPF- 16 Response to NRC Reactor Systems Branch and Nuclear Performance Branch Request for Additional Information Regarding Extended Power Uprate License Amendment Request

References:

(1) R. L. Anderson (FPL) to U.S. Nuclear Regulatory Commission. (L-2011-021),

"License Amendment Request for Extended Power Uprate," February 25, 2011, Accession No. ML110730116.

(2) Email from T. Orf (NRC) to C. Wasik (FPL), "St. Lucie 2 EPU - draft RAIs Reactor Systems Branch and Nuclear Performance Branch (SRXB and SNPB),"

September 6, 2011.

(3) Email from L. Abbott (FPL) to T. Orf (NRC), "Re: St. Lucie 2 EPU - draft RAls Reactor Systems Branch and Nuclear Performance Branch (SRXB and SNPB) -

Question Numbering," September 28, 2011.

By letter L-2011-021 dated February 25, 2011 [Reference 1], Florida Power & Light Company (FPL) requested to amend Renewed Facility Operating License No. NPF- 16 and revise the St. Lucie Unit 2 Technical Specifications (TS). The proposed amendment will increase the unit's licensed core thermal power level from 2700 megawatts thermal (MWt) to 3020 MWt and revise the Renewed Facility Operating License and TS to support operation at this increased core thermal power level. This represents an approximate increase of 11.85% and is therefore considered an extended power uprate (EPU).

an FPL Group company

L-2011-532 Page 2 of 3 In an email dated September 6, 2011 from NRC (T. Orf) to FPL (C. Wasik)

[Reference 2], the NRC staff requested additional information regarding FPL's license amendment request (LAR) to implement the EPU. FPL email dated September 28, 2011 from FPL (L. Abbott) to NRC (T. Orf) [Reference 3], provided specific numbers (SXRB-01 through SRXB-102) for the questions included in the September 6, 2011 email. Attachments 1 and 2 to this letter provide the FPL responses to RAI questions SRXB-40 through SRXB-77, excluding SRXB-71, related to non-loss of coolant accident (non-LOCA) analyses. The remaining responses are being provided in separate submittals. contains the non-proprietary responses to RAI questions SRXB-40 through SRXB-77, excluding SRXB-71. Attachment 2 contains the proprietary response to RAI question SRXB-64. contains a copy of the Proprietary Information Affidavit. The purpose of this attachment is to withhold the proprietary information contained in the response to SRXB-64 (Attachment 2) from public disclosure. The Affidavit signed by Westinghouse as the owner of the information sets forth the basis for which the information may be withheld from public disclosure by the Commission and addresses with specificity the considerations listed in paragraph (b)(4) of § 2.390 of the Commission's regulations.

Accordingly, it is respectfully requested that the information which is proprietary to Westinghouse be withheld from public disclosure in accordance with 10 CFR 2.390.

In accordance with 10 CFR 50.91(b)(1), a copy-of this letter is being forwarded to the designated State of Florida official.

This submittal does not alter the significant hazards consideration or environmental assessment previously submitted by FPL letter L-2011-021 [Reference 1].

This submittal contains no new commitments and no revisions to existing commitments.

Should you have any questions regarding this submittal, please contact Mr. Christopher Wasik, St. Lucie Extended Power Uprate LAR Project Manager, at 772-467-7138.

I declare under penalty of perjury that the foregoing is true and correct to the best of my knowledge.

Executed on /'- J ,,- ,-oi.

Very truly yours, Richard L. Ande~on Site Vice President St. Lucie Plant

L-2011-532 Page 3 of 3 Attachments (3) cc: Mr. William Passetti, Florida Department of Health

L-2011-532 Attachment 1 Page 1 of 62 Response to Reactor Systems Branch and Nuclear Performance Branch Request for Additional Information The following information is provided by Florida Power & Light (FPL) in response to the U.S. Nuclear Regulatory Commission's (NRC) Request for Additional Information (RAI). This information was requested to support the review of Extended Power Uprate (EPU) License Amendment Request (LAR) for St. Lucie Nuclear Plant Unit 2 that was submitted to the NRC by FPL via letter (L-2011-021), February 25, 2011, Accession No. ML110730116.

In an email dated September 6, 2011 from NRC (T. Orf) to FPL (C. Wasik), "St. Lucie 2 EPU -

draft RAls Reactor Systems Branch and Nuclear Performance Branch (SRXB and SNPB)," the NRC staff requested additional information regarding FPL's request to implement the EPU. FPL email dated September 28, 2011 from FPL (L. Abbott) to NRC (T. Orf), "Re: St. Lucie 2 EPU -

draft RAls Reactor Systems Branch and Nuclear Performance Branch (SRXB and SNPB) -

Question Numbering," provided specific numbers (SXRB-01 through SRXB-1 02) for the questions included in the September 6, 2011 email. The non-proprietary responses to RAI questions SRXB-40 through SRXB-77, excluding SRXB-71, are provided in Attachment 1. The remaining responses are being provided in separate submittals.

The response to SRXB-64 contains information that is proprietary to Westinghouse Electric Company (Westinghouse). As such, the non-proprietary response for this RAI is provided below.

The proprietary response is provided in Attachment 2.

Ill. Non-LOCA Transients Analysis and Related Analysis (Attachment 5 of Licensing Report)

SRXB-40 (RAI 2.3.5-1)

Table 2.3.5-2 lists for the station blackout (SBO) analysis the assumed initial conditions including moderator temperature coefficient (MTC) and primary coolant leakage.

Discuss the bases for selecting the values of -o.91X10 4 Ap/°F and 16 gpm for the MTC and primary coolant leakage, respectively. Discuss the reactor coolant pump (RCP) seal break flows assumed, and provide a discussion of an analysis or RCP seal testing data to show adequacy of the RCP seal flow rates assumed in the SBO analysis. The RCP seal testing data should be acceptable to the SL2 RCP seals and SBO conditions extended for at least 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to be consistent with the SBO coping time.

Response

EPU LAR Attachment 5, Table 2.3.5-2 incorrectly listed the moderator temperature coefficient (MTC) for the station blackout (SBO) event as -0.91X10-4 Ap/°F. As indicated on EPU LAR , Table 2.8.2-2 Range of Key Safety Parameters, the correct value for the MTC is

-0.91X10. 5 Ap/rF.

With respect to the MTC value chosen for the SBO event, a least negative (most positive) MTC value is used. This is consistent with Westinghouse standard methodology for the event. The value input into the RETRAN code is -0.91 x 10-5 Ap/°F which is a combination of the MTC and a bounding least negative Doppler temperature coefficient (DTC) applicable to the EPU. Since the least negative MTC at hot full power is 0 per EPU LAR Attachment 5, Section 2.8.5.0, Figure 2.8.5.0-6, the corrected MTC value for EPU LAR Attachment 5, Table 2.3.5-2 is equal to the least negative DTC of -0.91 x 10.5 Ap/°F.

Note that in addition to the normal SBO conditions, the analysis of record (AOR), as documented in Updated Final Safety Analysis Report (UFSAR) Section 15.10, performed a shutdown margin depletion study which resulted in the use of a conservatively high positive MTC during the first

L-2011-532 Attachment 1 Page 2 of 62 10 seconds of the transient and a conservatively low, most negative, MTC for the duration of the event.

A shutdown margin depletion study was not performed for the EPU based on analysis of the limiting case results for the SBO event. The maximum post-trip reactivity at the end of the event is -4.74$ (-0.03318 Ap). Since the MTC used in the event is 0, this maximum post trip reactivity is a combination of the negative reactivity provided by control rod insertion and the positive reactivity insertion via Doppler feedback. The maximum cooldown in the reactor core is 92 0 F.

Assuming a most negative MTC based on technical specifications limits of -32 pcm/°F, a most negative MTC would contribute 2944 pcm (0.02944 Ap) of positive reactivity. Inclusion of most negative MTC reactivity contribution would result in the reactor remaining subcritical by 374 pcm (0.00374 Ap or 0.534$).

The total reactor coolant system (RCS) leakage is 16 gpm and is modeled based on the AOR as presented in UFSAR Table 15.10-2. The total RCS leakage remains constant throughout the event and conservatively does not decrease with depressurization. The breakdown of the total RCS leakage is provided in Table SRXB-40-1 below:

Table SRXB-40-1 Total RCS Leakage Breakdown Component Assumed Leakage Component __(gpm)

Identified leakage*

SG tube leakage**, 1 Pressurizer safety valve leakage 3 Other identified leakage 6 Unidentified leakage* 1 RCP controlled bleedoff 4 RCP seal leakage 1 Total 16 Notes

• Consistent with Technical Specification 3.4.6.2

• • This analysis value exceeds the Technical Specification 3.4.6.2 primary-to-secondary leak limit of 150 gallons per day through any one SG, and is conservative to provide margin to account for any leakage increase due to higher pressure differentials under accident conditions.

WCAP-16175-P-A Revision 0, Model for Failure of RCP Seals Given Loss of Seal Cooling in CE NSSS Plants, January 2004, was submitted by Westinghouse to model failures of reactor coolant pump (RCP) seals in a loss of seal cooling scenario for Combustion Engineering (CE) designed plants. This analysis was reviewed and approved by the NRC via the safety evaluation report (SER) dated February 12, 2007 (Accession Number ML070240429). WCAP-16175-P-A contains a discussion on a loss of component cooling water analysis performed for St. Lucie by RCP pump vendor Byron Jackson. The analysis considered seal exposure to water temperature of 550°F at a pressure of 2250 psig for a duration of 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br />. Seal leakage on the order of 0.25 gpm was observed during the 100 hour0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> analysis. As the SBO analysis performed for the EPU is

L-2011-532 Attachment 1 Page 3 of 62 significantly shorter than the test documented WCAP-1 6175-P-A and RCS pressure and cold leg temperatures decrease below the test values of 2250 psia and 550'F respectively, the modeling of a total of 1 gpm seal leakage is appropriate.

An additional analysis performed by CE, simulated an 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> SBO event to test the upgraded Byron Jackson N-9000 seals, as described in WCAP-16175-P-A. St. Lucie Unit 2 was upgraded to the N-9000 seals in 1999. This analysis simulated depressurization and repressurization in order to model a closer approximation of a typical 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> SBO event. Test data from this analysis illustrates that maximum seal leakage observed during this test was approximately 14 gph (0.233 gpm). This test further justifies the use of 0.25 gpm of seal leakage for each RCP.

SRXB-41 (RAI 2.3.5-2)

Page 2.3.5-6 indicates that the RETRAN code is used for the SBO analysis.

Confirm that the RETRAN code is an NRC-approved code for the SBO analysis, and address compliance with each of restrictions and conditions specified in the NRC safety evaluation approving the code for the SBO analysis. Identify any changes and address acceptability of the changes from the NRC-approved version of the RETRAN code for the SBO analysis.

Response

The purpose of the RETRAN code for the station blackout (SBO) analysis is to simulate the nuclear steam supply system (NSSS) thermal-hydraulic response to the SBO event. The SBO event is simulated as a loss of feedwater with a concurrent loss of offsite power event analyzed for-an extended period of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Table 1 of the safety evaluation report (SER) to the RETRAN-02-report documented in WCAP-14882-P-A, RETRAN-02 Modeling-and Qualification-for Westinghouse Pressurized Water Reactor Non-LOCA Safety Analyses, D. S. Huegel, et al.,

April 1999, indicates that the NRC approves the use of the RETRAN code for the loss of main feedwater event, which includes cases with and without offsite power available. No changes to the RETRAN code were required to perform the SBO analysis.

The RETRAN-02 SER limitations were reviewed and the SBO event presented for the EPU is in compliance with these limitations. It should be noted that although voiding appears in the reactor vessel upper head, 7 ft of water remains above the top of the hot legs with a minimum subcooling margin at the hot leg inlets of 26.1 OF, and as such, no boiling occurs in the hot legs or the upper portions of the steam generator U-tubes. Natural circulation is maintained and no reflux boiling is present.

L-2011-532 Attachment 1 Page 4 of 62 SRXB-42 (RAI 2.3.5-3)

Table 2.3.5-1 indicates that, during an SBO event, steam bubble formation would occur in the reactor vessel upper head at about 11,315 seconds following initiation of the SBO event.

Justify that the use of RETRAN is adequate for simulating conditions with bubble formation at the reactor vessel upper head. Discuss the results of the SBO analysis to show that there is no steam bubbles carried into the RCS hot-legs, steam generator U-tubes, RCS cold-legs, down-comer and lower core regions, and that there is no sufficient steam bubbles accumulated at the SG U-tubes to block the natural recirculation flow for decay heat removal.

Response

The station blackout (SBO) analysis presented in EPU LAR Attachment 5, Section 2.3.5 indicates that the upper head voiding occurs at 11,335 seconds, rather than 11,315 seconds as indicated above, due to the pressurizer emptying (EPU LAR Attachment 5, Table 2.3.5-1). At the peak of voiding in the upper head, at the end of the transient, 7 ft of liquid level remains above the top of the hot leg. The minimum subcooling margin observed at the hot leg inlets is 26.1*F. As such, no steam bubbles are carried into the hot legs, U-tubes, cold legs, downcomer and lower core regions. Since no bubbles are present in these regions, natural circulation flow is maintained and a reflux boiling condition is not reached.

The-RETRAN code has the ability to model the upper head as a non-equilibrium node, essentially allowing for different steam and liquid temperatures within the region. This is the same model-used in the pressurizer and is termed the "non-equilibrium pressurizer option." The non-equilibrium option allows for accurate predictions of conditions in the upper head when voiding-occurs. The non-equilibrium option is detailed in the RETRAN-02 topical report WCAP-14882-P-A, approved by the NRC via the SER dated February 11, 1999.

SRXB-43 (RAI 2.3.5-4)

Table 2.3.5-1 includes the SBO sequence of events at EPU conditions.

Specify the non-safety grade systems or equipment used in the analysis specified in the table and justify adequacy of use of them for mitigating the consequences of the SBO.

Discuss single failure considered in the analysis. Address acceptability of the setpoints listed in the table for actuating automatic systems or providing signal to the operator to take actions.

Response

In accordance with 10 CFR 50.2, Definitions, the station blackout (SBO) event does not assume a concurrent single failure. As such, no single failure is modeled in the analysis performed for the EPU.

Per Section 15.10.3 of the St. Lucie Unit 2 Updated Final Safety Analysis Report (UFSAR), the following instrumentation is required to remain functional during an SBO:

• Pressurizer pressure,

" Steam generator (SG) pressure,

• SG level,

L-2011-532 Attachment 1 Page 5 of 62

• Auxiliary feedwater (AFW) system valve position indication,

• Power operated relief valve (PORV) position indication,

• Containment pressure,

• Containment radiation monitors,

• Battery voltage and current,

• Engineered safety features actuation system (ESFAS),

• AFW actuation system (AFAS), and

• Reactor protective system (RPS) (including hot and cold leg temperature, neutron flux).

The instrumentation presented above, with the exception of the containment pressure and radiation monitors and the instrumentation for battery voltage and current, are considered in the EPU LAR Attachment 5, Section 2.3.5 analysis. The containment and battery instrumentation are not within the scope of the non-loss of coolant accident (Non-LOCA) analysis and thus, are not credited in the event. Additionally, no instrumentation other than those listed above is required to produce the results documented in EPU LAR Attachment 5, Section 2.3.5.

The instrumentation listed above are safety grade with the exception of the AFW system valve position indicator and the PORV position indicator. Since pressurizer pressure does not reach the PORV opening setpoint, the PORV position indicator, while not safety grade, is not relied upon based on the thermal-hydraulic analysis performed for EPU. Additionally, although the AFW system valve position indicator is not safety grade, AFW flow can be successfully confirmed through using the safety grade SG level indication instrumentation.

The following-equipment is also required to remain functional during an SBO per UFSAR Section 15.10;3:

• Control element drive mechanisms (CEDMs), condensate storage tank (CST), safety injection tanks (SITs),

• AFW pump 2C,

• Steam supply to AFW turbine driven pump isolation valves,

" AFW flow control valves,

• Atmospheric dump valves (ADVs),

" AFW isolation valves,

• PORVs,

• Main steam safety valves (MSSVs),

• Letdown isolation valves, and

• Turbine stop valves.

The analysis performed for the EPU considers the equipment shown above with the exception of the SITs and PORVs. The reactor coolant system (RCS) pressure does not reach the SIT actuation setpoint in the EPU analysis; thus they are not credited. The pressurizer pressure remains below the opening setpoint of the PORVs; thus the PORVs and associated instrumentation are not credited. Additionally, no equipment other than those listed above is required to produce the results documented in EPU LAR Attachment 5, Section 2.3.5.

L-2011-532 Attachment 1 Page 6 of 62 The equipment listed above and in UFSAR Section 15.10.3 are safety grade with the exception of the turbine stop valves. Per UFSAR Section 10.3.3, however, the turbine stop valves fail closed and are backed up by the closure of the turbine governor valves. Thus, a failure of a turbine stop valve would still result in steam isolation to the turbine. Closure of the turbine stop valves is modeled in the analysis as early isolation of the steam flow to the turbine results in a more limiting analysis as it places a greater strain on the AFW system, and thus condensate inventory, in removing decay heat from the RCS. Note that the safety grade main steam isolation valves (MSIVs) are fully closed approximately 3 seconds after turbine trip.

Table SRXB-43-1 below presents the components and setpoints shown in EPU LAR , Table 2.3.5-1 and their acceptability for the SBO analysis.

Table SRXB-43-1 Component and Analysis Justification Action Value 91.9% of Set equal to a fraction of normalized initial differential pressure Lowterecor coot thermal design corresponding to the nominal low flow trip setpoint of 95.4%

system flow trip flow minus a 3.5% uncertainty.

The nominal MSSV setpoint is used for this event. The nominal opening setpoint is acceptable for this event as biasing to either First bank of MSSVs 1000 psia minimum or maximum opening setpoints would have a open negligible effect on the minimum SG inventory and the MSSVs actuate only during the first 30 minutes of the event, at which point pressure is reduced via the operation of the ADVs.

Set to match the value used in the analysis of record (AOR).

AFW actuation 5% sGan An actuation setpoint of 5% SG NRS level is significantly more range span conservative thanNRS-minus-the the allowable Technical signal (NRS) level setpoint of 18% uncertaintySpecifications of 5% NRS.

AFW flow delay 330 sec Set conservatively based on inservice testing (IST) acceptance criteria.

Set equal to the flow rate provided by the single turbine driven AFW flow rate 500 gpm total pump as both electrical driven pumps are assumed to be inoperable during an SBO. The turbine driven pump provides a total of 500 gpm to both SGs.

Set equal to the opening setpoint of the ADVs consistent with ADV open by the AOR. Operator action of the ADVs is credited 30 minutes raction to 900 psia into the event to maintain subcooling in the RCS. An opening operatorSG pressus pressure of 900 psia was chosen consistent with the AOR to control SG pressure mimic steam relief typically provided by the steam bypass control system when normal or offsite power is available.

Set equal to the opening setpoints - 5 psia. Consistent with MSSVs close 995 psia Westinghouse standard methodology for small blowdowns.

Note that the MSIVs close 26.8 seconds into the event. The MSIV closure setpoint is not a key analysis parameter and although the MSIVs actuate and close, they are not required as indicated by UFSAR Table 15.10-4. The earlier closing of the MSIVs is conservative as it maximizes the heat load to be removed for the event.

L-2011-532 Attachment 1 Page 7 of 62 SRXB-44 (RAI 2.5.4.5-1)

Page 2.5.4.5-8 indicates that water 154,000 gallons in the condensate storage tank (CST) is required to accommodate the SL2 decay heat removal for removal for 10.63 hour7.291667e-4 days <br />0.0175 hours <br />1.041667e-4 weeks <br />2.39715e-5 months <br /> cooldown period including the RCS at hot standby for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> in order to reduce the reactor coolant temperature to shutdown cooling entry condition in the event of loss-of-offsite-power (LOOP).

Provide a discussion of the analysis that determines the CST water of 154,000 gallons for the required cooldown for LOOP conditions, and address the relevancy of the CST water inventory determination for the NCC analysis discussed in Section 2.8.7.2. The information should include a discussion of methods, assumptions, sequence of cooldown events, and single failure consideration for the analysis. Provide justification if non-safety grade equipment is used in the cooldown analysis.

Response

The two EPU LAR Attachment 5 sections noted in the RAI are each associated with the plant's need for condensate, but each has a distinct purpose. EPU LAR Attachment 5, page 2.5.4.5-8 addresses the condensate storage tank (CST) sizing analysis done to calculate the required CST volume for EPU conditions. The CST sizing analysis for EPU conditions results in a required inventory of 154,000 gallons. This is an increased volume from the existing analysis of record (AOR) for the tank sizing. This-analysis supports the St. Lucie Unit 2 current CST design, as stated in the Technical Specifications Bases, based on the requirements of NRC Regulatory Guide (RG) 1.139 where hot standby is maintained for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> followed by a cooldown of 75°F per hour.

The natural circulation cooldown (NCC) analysis discussed in EPU LAR Attachment 5, Section 2.8.7.2 addresses the Standard ReviewPlan guidance as described in. Branch Technical Position (BTP) 5-4 to calculate the time to achieve shutdown cooling (SDC) entry conditions and CST inventory usage. Per BTP 5-4, water supply for the auxiliary feedwater system shall have sufficient inventory to permit operation at hot standby for at least 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, followed by cooldown to the conditions permitting operation of the residual heat removal system based on the longest cooldown time with an assumed single failure. The NCC analysis for EPU conditions results in a required inventory of 178,200 gallons.

The CST sizing analysis methodology uses a CENTS computer code cooldown simulation from hot full power conditions to SDC system entry conditions. The CST sizing analysis assumptions are as follows:

a. Plant power is initially at 100.3% of rated power including 0.3% power measurement uncertainty;

b. Maximum cooldown rate of 75'F/hr;

c. Loss of off-site power (LOOP);

d. Limiting single failure of a DC emergency power train;

e. Only safety grade equipment is used;

f. Four hour hold at hot standby followed by cooldown to SDC entry conditions;

g. 1979 ANS 5.1 Standard Decay Heat Curve including long term actinides with 2a uncertainty;

h. Charging is available following the plant trip;

i. Letdown is disabled;

j. Main feedwater is disabled;

L-2011-532 Attachment 1 Page 8 of 62

k. Main steam safety valves (MSSVs) provide the initial heat removal path; I. Two of four atmospheric dump valves (ADVs) are credited;

m. Safety injection system (SIS) is not used;

n. Reactor coolant system (RCS) heat losses to containment are set to zero;

o. Reactor vessel upper head heat losses to containment are set to zero;

p. Main steam isolation valves (MSIVs) are closed upon event start;

q. The auxiliary feedwater (AFW) flow is set to maintain the steam generator (SG) level to match boiloff during the cooldown;

r. SG blowdown is unavailable; and

s. As required, charging is controlled to maintain pressurizer level within the acceptable range.

The limiting single failure of a DC emergency power train, assumption (d), prevents AC power from one emergency diesel generator from being transferred to the onsite electrical system. The single failure disables one train of components associated with the ADVs, AFW system, and SDC system.

The sequence of events for the CST sizing analysis is outlined in Table SRXB-44-1.

Table SRXB-44-1 CENTS CST Sizing Analysis Sequence of Events 75°F/hr Cooldown with Four Hour Hold at Hot Standby Time (seconds) Event Reactor trip 1 Turbine trip Reactor coolant pump (RCP) trip 2,600 Turn off charging flow to maintain pressurizer level 14,000 Turn on one charging pump Set ADVs to manual control 14,401" Initiate cooldown at 75 0 F/hr Turn second charging pump on 15,000 Set AFW flow to 18 lbs/sec per SG 19,000 Turn off one charging pump 27,000 Turn off second charging pump 28,500 Turn on one charging pump 29,000 Turn on auxiliary spray from one charging pump Turn off auxiliary spray from one charging pump Set AFW flow to 12 lbs/sec per SG 34,000 Turn on auxiliary spray from one charging pump Turn off auxiliary spray from one charging pump Set AFW flow to 10 lbs/sec per SG Turn on auxiliary spray from one charging pump Set AFW flow to 8 lbs/sec per SG 38,250 SDC entry conditions achieved

• End of four hour hold period at hot standby.

L-2011-532 Attachment 1 Page 9 of 62 The modeling simulation and assumptions are reflective of the AOR, updated for EPU core power.

The analysis supporting EPU LAR Attachment 5, Section 2.8.7.2, the NCC analysis, supports BTP 5-4 and uses the same methodology and limiting single failure as the CST sizing analysis.

In addition, the assumptions are the same as described for the CST sizing analysis with the exception of the maximum cooldown rate, 30'F/hr, and initial core power, 100.5% of the uprate core power. These values were conservatively chosen to support the purpose of BTP 5-4, particularly cooldown duration and condensate use.

As described in Section 2.8.7.2, the NCC analysis done to support BTP 5-4 results in a CST inventory usage of 178,200 gallons for EPU conditions. The current NCC CST inventory usage of 276,000 gallons is maintained as the described requirement for EPU as it is bounding of the explicit NCC analysis results for EPU conditions.

The 24,000 gallon difference in CST inventory usage between the NCC analysis done for BTP 5-4 and the CST sizing analysis (178,200 gallons versus 154,000 gallons) is attributed to the differences in the analysis assumptions and the simulation cases. As noted, the differences in the case files are the initial core power and the cooldown rate. Cooldown rate has limited consequential effect on condensate usage; the ADVs typically limit the maximum cooldown rate.

The higher initial core power also directly affects the condensate requirements in the NCC analysis. In addition, based on the time that the comparative case runs are terminated, the levels in the steam generator will vary when shutdown cooling entry conditions are achieved. Case data shows that the final CST sizing case run has a lower final SG level than the results for the NCC analysis. The combination of these two considerations address the specific difference in described CST inventory use.

SRXB-45 (RAI 2.5.4.5-2)

Page 2.5.4.5-9 indicates that the IGOR code is used in the analysis of a loss of normal feedwater (LONF) event.

Provide a discussion of the code and address acceptability of the code for the LONF analysis.

Response

IGOR is used as a pre-processor to the Westinghouse version of the RETRAN-02 computer code. IGOR allows the proper definition of the nuclear steam supply system (NSSS) initial conditions and setpoints for the specific transient analysis. The result of IGOR is a partially completed RETRAN NSSS model for the specific transient setup. This model, along with additional transient specific RETRAN input data, creates a completed loss of normal feedwater model to be analyzed with RETRAN. The complete setup of the RETRAN model for the transient is consistent with the NRC approved Westinghouse methodology as documented in WCAP-14882-P-A, RETRAN-02 Modeling and Qualification for Westinghouse Pressurized Water Reactor Non-LOCA Safety Analyses, D. S. Huegel, et al., April 1999.

L-2011-532 Attachment 1 Page 10 of 62 SRXB-46 (RAI 2.8.4.3-1)

Page 2.8.4.3-5 indicates that for the low temperature over-pressurization protection (LTOP) calculations, each energy addition of mass addition event is analyzed at the most limiting initial temperature and pressure and the worst alignment of system components permitted by the Technical Specifications.

Discuss the methods and address acceptability of the methods used in the analysis of the energy addition or mass addition event. Specify the initial values of key plant parameters including temperature, pressure, decay heat model, and time after reactor shutdown for determining the initial decay heat rate assumed in the analysis and justify adequacy of the values used. Discuss assumptions used to maximize a RCS peak pressure. Provide a description of how uncertainties of the RCS temperature and pressure instrument are accounted for determination of the LTOP requirements. List all single failures considered and explain how the worst single failures are determined for use in the analysis. Specify the calculated peak pressures for the analysis of the energy addition and mass addition event, and show how the peak pressures meet the applicable acceptance criteria.

Response

The low temperature overpressure protection (LTOP) analyses for EPU conditions were performed consistent with- the current design basis described in the Updated Final Safety Analysis Report (UFSAR) Section 5.2.6. The most limiting LTOP scenarios for mass and energy addition are separately analyzed to-show that the reactor vessel (RV) is sufficiently protected from overpressurization by showing that the reactor coolant system (RCS) pressure-temperature (P-T) limits are not violated during an overpressurization event. In addition, the peak transient

-pressures at the limiting point for each analysis cannot exceed 11 0%-of the design pressure of the shutdown cooling (SDC) system per the American Society of Mechanical Engineers (ASME)

Code,Section III, Article NC-7000. The methods used in each LTOP analysis are acceptable because appropriate conservatisms are applied in each analysis to generate conservatively high peak transient pressures.

The most limiting transients initiated by a single operator error or equipment failure are:

1. An inadvertent safety injection actuation (mass addition).

2. A reactor coolant pump (RCP) start when a positive steam generator (SG) to RV temperature differential exists (energy addition).

The transients were determined as most limiting by conservative analyses which maximize mass and energy additions to the RCS. In addition, the RCS is assumed to be in a water-solid condition at the time of the transient.

The mass addition overpressurization event analysis considers two worst case scenarios:

1. Two high pressure safety injection (HPSI) pumps and three charging pumps at temperatures greater than 2000 F.

2. A single HPSI pump and three charging pumps at temperatures less than or equal to 2000 F.

Initial pressurizer pressure is conservatively assumed to be a bounding low pressure of 300 psia, and is increased until a maximum or equilibrium pressure is reached. The 300 psia value is based on the anticipated range of equilibrium pressures. The mass addition analysis conservatively accounts for RCS volume expansion contributions from decay heat and the full capacity of the pressurizer heaters. A bounding minimum RCS volume is conservatively used.

Uncertainty of 0.3% is applied to the core power to maximize the core power used in the

L-2011-532 Attachment 1 Page 11 of 62 calculation of decay heat. Bounding generic decay heat fraction data in conjunction with a maximum allowable cooldown rate is used to minimize time after shutdown, which in turn maximizes decay heat energy input. The minimum temperature is assumed for the start of cooldown, and the maximum cooldown rate is assumed in order to minimize the time period from the start of reactor shutdown, conservatively maximizing the decay heat. The maximum pressurizer heater capacity is used, and it is assumed that a single failure occurs and only one of the two SDC system relief valves is operable during the overpressurization event. A maximum temperature which bounds the initial heatup temperature including instrument uncertainty is conservatively used for heatup and a minimum temperature which bounds the initial cooldown temperature and includes instrument uncertainty is conservatively used for cooldown.

Determination of peak transient pressure conservatively accounts for the time delay in power operated relief valve (PORV) opening, instrument loop uncertainty, and PORV lift setpoint uncertainty.

The energy addition overpressurization event analysis considers a RCP start with an initial SG to RV temperature differential conservatively maximized to the Technical Specifications limit, which is greater than the differential temperature limit in the emergency operating procedure. The energy addition overpressurization event analysis considers worst single failure cases where a single PORV or a single SDC system relief valve provides overpressure protection. Initial RCS temperature and pressure are conservatively assumed to be at bounding maximum levels for conditions prior to the initiation of shutdown cooling. Initial pressure bounds the pressurizer pressure including instrument uncertainty. Initial temperature bounds LTOP enable temperatures for both heatup and coo.ldown, including instrument uncertainty. PORV opening pressure is increased from-the nominal setpoint by accounting for setpoint uncertainty, instrument loop uncertainty, and pressure accumulation due to finite PORV opening time to conservatively maximize the RCS pressure at the PORV opening. Instrument loop uncertainty is accounted for in the SDC initiation pressure to conservatively maximize this value. The decay heat rate is determined based on a-conservative maximum temperatureand maximum core power including uncertainty. The heat addition also accounts for heater power and RCP heat input.

PORV and SDC system relief valve setpoints and peak pressures from the mass and energy addition LTOP analyses are shown in Table SRXB-46-1.

L-2011-532 Attachment 1 Page 12 of 62 Table SRXB-46-1 PORV and SDC System Relief Valve Peak Transient Pressures for LTOP Analyses Peak Transient Setpoint Event Description Pressure Spoint (psia) (psia)

PORV setpoint 531 490 (1 HPSI and 3 charging pumps)

PORV setpoint 586 490 Mass Addition (2 HPSI and 3 charging pumps)

SDC system relief valve setpoint 368 350 (1 HPSI and 3 charging pumps)

SDC system relief valve setpoint 387 350 (2 HPSI and 3 charging pumps)

PORV setpoint 502 450 PORV setpoint 522 470 Energy Addition PORV setpoint 542 490 SDC system relief valve setpoint 368 350 The peak pressures shown in Tdble SRXB-46-1 are-evaluated to identify the controlling pressures and applicable-temperature ranges. The controlling pressures are the maximum transient pressures of all applicable transients in a particular temperature region. The controlling pressures are compared to the P-T limit curves to show that the P-T limits are not violated during the LTOP transients and the reactor vessel-is protected from overpressurization.

The SDC system relief valve setpoint is set to protect the SDC system from exceeding the maximum allowable SDC system design pressure. In accordance with ASME Code,Section III, Article NC-7000, the peak pressure is acceptable if it does not exceed 110% of the SDC system design pressure. Table SRXB-46-2 shows that the peak transient pressures at the limiting point of the SDC system are within acceptable limits for each event.

Table SRXB-46-2 SDC System Peak Transient Pressures for LTOP Analyses Peak Transient Maximum Allowable Event Pressure Pressure (psia) (psia)

Mass Addition 389 400 Energy Addition 380 400

L-2011-532 Attachment 1 Page 13 of 62 SRXB-47 (RAI 2.8.4.4-1)

Section 2.8.4.4.2.5 discuss the results of the analyses for (1) the normal plant cooldown duration, (2) Appendix R safety shutdown cooldown within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, and (3) the TS required cooldown within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

Discuss for the above three analyses the methods used and address acceptability of the methods. Discuss for each analysis the assumptions and values used for key parameters and show that the assumptions and values meet the TS requirements and are conservative, resulting in a longest time for the required cooldown.

Response

Shutdown cooling (SDC) system analyses are performed for a normal two train cooldown scenario and a single train emergency cooldown scenario. The time required for cooldown following natural circulation and to cool the plant from hot standby to cold shutdown conditions following the SDC system initiation are also analyzed. A description of the assumptions and key parameters for each SDC system analysis scenario is provided in Table SRXB-47-1.

Table SRXB-47-1 SDC System Cooldown Scenarios Scenario Description

• Cooldown from SDC entry conditions to cold shutdown conditions Normal N Normal plant conditions Cooldown No single failure-assumed

• Two available trains of SDC system

• SDC system initiated 3.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after shutdown

• Cooldown from SDC entry conditions to cold shutdown conditions E Normal plant conditions Cooldown

• One available train of SDC system

• Cooldown with most limiting failure

• SDC system initiated 3.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after shutdown

• Cooldown from SDC entry conditions to cold shutdown conditions

• Plant fire assumed 10 CFR 50 Parametric study based on start time Appendix Cooldown R R Single failure assumed (diesel generator)

• One available train of SDC system

• SDC system initiated from 10 to 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> after shutdown*

Note

• Assumptions used to determine the time to reach SDC system initiation time for the 10 CFR 50 Appendix R cooldown analysis are discussed below.

SDC system analysis scenarios have the following additional conservative assumptions:

• Replacement steam generator (RSG) metal mass and water volume are included in the reactor coolant system (RCS) metal heat capacity and water volume;

• 10% steam generator tube plugging is assumed for the SDC heat exchanger. (This assumption conservatively increases the cooldown time compared to the cooldown time based on the full SDC heat exchanger effective area); and

L-2011-532 Attachment 1 Page 14 of 62

• No credit is taken for convective heat losses from piping or equipment.

In addition, a minimum component cooling water (CCW) shell side flow is conservatively used. A maximum CCW inlet fluid temperature is conservatively used at the start of the cooldown for all SDC system analyses. For the 10 CFR 50 Appendix R cooldown analysis, the maximum CCW fluid temperature is conservatively used for the duration of the analysis. The 10 CFR 50 Appendix R cooldown analysis conservatively uses a cooldown rate of 25 0 F, a lower cooldown rate than the maximum allowable cooldown rate in order to generate a conservatively long cooldown time. The cooldown analysis also accounts for RCS temperature instrument uncertainty.

To support the 10 CFR 50 Appendix R analysis, in order to show that the cumulative time from reactor trip to cold shutdown is less than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, an analysis is performed to determine the longest time to reach SDC system entry conditions. The following conservative assumptions are used to determine the longest time to SDC system initiation:

• The RCS charging system requires two hours for initiation.

" The plant requires an additional two hours to align the SDC system.

" The maximum cooldown rate is 25 0 F per hour, which is lower than the maximum cooldown rate.

" The cold shutdown temperature is reduced by 3 0 F to 197 0 F.

" Only one atmospheric dump valve (ADV) and one feedwater pump are available for cooldown from hot standby to hot-shutdown.

• The-condensate storage tank (CST) inventory temperature is 120'F.

• There is a hold time to allow the reactor vessel upper head to- reach saturation temperature once hot shutdown is achieved.

• Cold leg temperature measurement uncertainty is applied.

• No credit is taken for heat removed by the ADV.

• Liquid and metal masses of the primary and secondary plant are included as part of the heat capacity with no heat loss to the environment.

To support the Technical Specifications analysis, it is demonstrated that at EPU conditions, the plant reaches SDC system entry conditions in less than 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> when a cooldown rate lower than the maximum allowed cooldown rate is conservatively assumed. One train of SDC system equipment is then placed in operation. The additional time to reach cold shutdown conditions is determined using the SDC system initiation time with a parametric analysis of the time to cool the plant from hot shutdown to cold shutdown as a function of the SDC system initiation time. The parametric analysis provides this information for SDC system initiation times of 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> to 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> following reactor trip. Using the calculated SDC system initiation time which falls within this time range, it is determined that 200°F is achieved in approximately 10 additional hours.

Therefore, continued compliance with the 10 CFR 50 Appendix R cold shutdown (Mode 5) requirement within the 72-hour timeframe is demonstrated at EPU conditions.

L-2011-532 Attachment 1 Page 15 of 62 SRXB-48 (RAI 2.8.5.0-1)

Page 2.8.5.0-16 shows that for the analysis of the loss of condenser vacuum (LOCV) event, the initial pressurizer water level of 66% of the span is used for the overpressure and DNB case. The results of both cases shows that the peak pressurizer water remains below the total volume of the pressurizer (pages 2.3.5.2.1-6 and 2.8.5.2.1-7), resulting in no pressurizer overfill to occur.

Explain why the maximum initial value of 71% span (specified as the upper limit of 68% in TS 3.4.3 with uncertainty of 3%) is not used to minimize the margin to the pressurizer overfill. Also, discuss the values of the initial SG water level used in both overpressure and DNBR cases for SG overfill consideration. The information should include a discussion of the effect of measurement uncertainties, and SG water mass addition due to turbine runback on the maximum SG initial water level assumed in the LOCV analysis.

Provide justification if the maximum initial SG water level is not used to minimize margin to the SG overfill. This RAI is also applicable to the uncontrolled control rod assembly withdrawal at power event (page 2.8.5.4.2-9) and asymmetric SG transient analysis (page 2.8.5.2.5-5) while pressurizer and SG overfill may occur.

Response

An initial pressurizer level of 66% span is assumed for the loss of condenser vacuum (LOCV) event. This consists of the nominal pressurizer level of 63% span plus 3% uncertainty. This is consistent with the analysis of record (AOR) documented in Updated Final Safety Analysis Report (UFSAR) Section 15.2.3. Furthermore, the assumption of nominal pressurizer level plus-uncertainty is consistent with standard Westinghouse methodology-for the LOCV event. The LOCV event is the limiting Chapter 15 analysis with respect to reactor coolant system (RCS) pressure. As such, the event is modeled such that the peak pressure can be obtained. A maximum possible initial pressurizer level is not chosen for this peak pressure case since starting at a higher level causes a smaller steam bubble. This in turn results in a lower overall pressurizer pressure increase, as a reactor trip would occur faster than when starting at a lower initial pressurizer level. Initializing from 66% span as opposed to 71% span delays the reactor trip and provides a longer increase in pressure before reactor trip, ultimately leading to a higher observed pressurizer pressure.

Pressurizer filling is reported as one of the acceptance criteria for the LOCV event and other anticipated operational occurrences (AOOs) to ensure that the incident does not generate a more serious plant condition without other faults occurring independently. The maximum pressurizer water volume observed during the LOCV event is slightly less than 1100 ft 3. The limit for pressurizer filling criteria is 1519 ft 3. Over 400 ft3 of margin exists within the pressurizer and a total rise of less than 200 ft 3 is observed from the initiation of the event to the time of maximum volume. The difference between 71% span and 66% span is approximately 76 ft 3 of additional water volume, meaning that over 300 ft 3 of margin would still remain if the maximum initial value was used. Ultimately, pressurizer filling is not significantly challenged in the LOCV event. The chemical and volume control system (CVCS) malfunction event described EPU LAR , Section 2.8.5.5 is the limiting Chapter 15 event with respect to pressurizer filling. It bounds the LOCV event in this regard. The maximum volume of the pressurizer in the CVCS malfunction event is 1512.3 ft3 which remains below the limit of 1519 ft 3. Note that additional discussion of the CVCS malfunction event as related to initial pressurizer level is contained in the response to RAl SRXB-70.

Similar analysis can be applied to the asymmetric steam generator transient (ASGT) event. The maximum pressurizer water volume observed in the limiting ASGT case is 962.8 ft 3 . This case is

L-2011-532 Attachment 1 Page 16 of 62 initialized at 66% span in the pressurizer (63% nominal plus 3% uncertainty). Initializing at 71%

span would contribute an extra 76 ft 3 of inventory, however, there would still be significant margin (approximately 480 ft3) to pressurizer overfill. EPU LAR Attachment 5, Figure 2.8.5.2.5-11 demonstrates that pressurizer overfill is not challenged for the ASGT event.

The control element assembly (CEA) Withdrawal at Power event documents a maximum pressurizer water volume of 1483.4 ft 3 in EPU LAR Attachment 5, Table 2.8.5.4.2-2. The limiting case with respect to pressurizer overfill is the 100% power, maximum reactivity feedback, slow withdrawal of 1 pcm/sec case. This case is run with an initial pressurizer level of 66% span (63%

nominal plus 3% uncertainty). Although the maximum possible reactivity insertion limit at 100%

power is 500 pcm, the analysis was run with significantly larger reactivity insertion to produce conservative departure from nucleate boiling ratio (DNBR) results. The total reactivity insertion at the time of peak pressurizer volume of 1483.4 ft 3 is 1515 pcm, which is 3 times greater than the CEA withdrawal reactivity insertion limit of 500 pcm that can be achieved at 100% power Analysis of the CEA Withdrawal at Power event documented in EPU LAR Attachment 5, Section 2.8.5.4.2 shows that when the 500 pcm reactivity insertion limit is reached, the 3 3

pressurizer water volume is approximately 1107 ft , which is significantly less than the 1519 ft limit. The transient is run past the reactivity insertion limit conservatively to minimize DNBR margin and force a reactor trip. If the event stopped upon reaching the 500 pcm limit, the system would stabilize at a slightly higher power level and temperature with pressurizer water volume remaining stable near 1107 ft3 .

Applying the CEA withdrawal reactivity insertion limits to all cases analyzed in the CEA withdrawal at power event, the limiting case with respect to pressurizer overfill is determined to be the case at 65% power, maximum reactivity feedback, 1 pcm/sec withdrawal. The peak pressurizer volume observed in this case is 1297 ft 3 with the transient initialized at 66% span in

-the pressurizer. Initializing at 71% span would contribute an extra 76 ft3 of inventory, however, there would still- be 146 ft 3 of available margin to preclude pressurizer overfill, The CEA withdrawal at power event thus, does not significantly challenge pressurizer overfill.

The initial steam generator (SG) water level is not a key parameter in the LOCV analysis. It is set equal to the nominal SG level of 65% narrow range span (NRS) for all 3 cases performed. This is consistent with the AOR documented in UFSAR, Section 15.2.3, and with Westinghouse standard methodology for the event. Analysis of the LOCV event performed for EPU shows that SG inventory does not increase during the duration of the transient. Therefore, SG margin to overfill (MTO) is not challenged for any of the cases performed for the LOCV event.

The ASGT event, much like the LOCV analysis, is initialized at 65% NRS in the SGs. The limiting case with respect to SG MTO for the ASGT event is the 0% SG tube plugging case which reaches a maximum level of 85.77% NRS in SG #1. Despite the increase in level in SG #1, approximately 2500 ft 3 of MTO exists for the limiting ASGT event. SG overfill, even when including uncertainties or maximum initial level, is not challenged for the ASGT event.

The limiting CEA withdrawal at power case with respect to secondary is the 20% power, 1 pcm/sec withdrawal with maximum reactivity feedback case. The maximum observed SG level is 72.2% NRS at the end of the transient. This is a rise of 7.2% NRS from the initial level of 65%

NRS over the duration of the event. Despite the slight rise in SG inventory, approximately 3000 ft3 of MTO exists for the limiting CEA withdrawal at power event. SG overfill is thus not challenged for this event, even with the maximum initial SG level. The turbine runback is not applicable to St. Lucie Unit 2.

L-2011-532 Attachment 1 Page 17 of 62 The bounding analysis for the SG MTO is the steam generator tube rupture (SGTR) event. The SGTR event also does not challenge SG overfill since the design of the Combustion Engineering (CE) plants provides significant capacity for secondary inventory. Although not analyzed in the current licensing basis, a SGTR MTO analysis is being addressed in the responses to RAIs SRXB-01 through SRXB-07 to demonstrate that significant margin remains and MTO is not challenged for the St. Lucie Unit 2 EPU. Similarly, the uncontrolled CEA withdrawal at power event and the ASGT event are bounded by the SGTR MTO analysis with respect to challenging MTO.

SRXB-49 (RAI 2.8.5.0-2)

Page 2.8.5.0-13 lists the values of the reactivity feedback coefficients assumed in the analyses of the cooldown events resulting from an increase in heat removal by the secondary. Different values are used: 0.43, 0.0 to 0.43, 0.30 Ak/gm/cc and Figure 2.8.5.0-7 for the moderator density coefficient; Figure 2.8.5.0-6 and -0.45 pcm/°F for the moderator temperature coefficient; and upper curve of Figure 2.8.5.0-5 and Figure 2.8.5.0-8 for the Doppler power coefficient.

Discuss the bases for use of the above different values or functions of the reactivity feedback coefficients in the analyses for each of the cooldown events. This RAI is also applicable to the reactivity coefficients used in the analyses for each of (1) the heatup events on page 2.8.5.0-14, (2) RCS flow reduction events on page 2.8.5.0-17, (3) reactivity transients on page 2.8.5.0-18, and (4) events resulting from an increase or decrease in coolant inventory- listed on page 2.8.5.0-20.

-Response Reactivity coefficients are chosen conservatively on an event by event basis depending upon the specific event criteria. The three tables below present the justifications for the moderator density coefficient (MDC), moderator temperature coefficient (MTC) and Doppler power coefficient (DPC) used in each analysis discussed in EPU LAR Attachment 5, Section 2.8.5.0. EPU LAR , Table 2.8.2-2 presents the ranges of MDC, MTC and DPC values used in the EPU Non-LOCA safety analyses. In some cases, however, more conservative reactivity values were chosen to match values used in previous analyses.

L-2011-532 Attachment 1 Page 18 of 62 Table SRXB-49-1 Moderator Density Coefficient Justification for EPU Non-LOCA Safety Analyses Event MDC Value Justification Maximum reactivity feedback is conservatively modeled for this Decrease in feedwater temperature event since it results in a primary system cooldown. As such, the most positive MDC of 0.43 Ak/gm/cc is used.

Maximum reactivity feedback is conservatively modeled for this Increase in feedwater flow rate event since it results in a primary system cooldown. As such, the most positive MDC of 0.43 Ak/gm/cc is used.

Excessive increase in main steam This event is bounded by other events.

flow Inadvertent gnadverantor opening of a steam reief ora safetyale This event is bounded by other events.

generator (SG) relief or safety valve Reactivity feedback is conservatively chosen to maximize the Pre-trip steamline break (SLB) with pre-trip power increase and thus maximize the heat flux. A full failure of the fast bus transfer (FFBT) range of MDC values from 0 to 0.43 Ak/gm/cc are considered in this analysis. The limiting MDC value was determined to be 0.30 Ak/gm/cc through the performed sensitivity study.

The MDC spectrum scoping performed for the limiting pre-trip Pre-trip steamline break coincident SLB with FFBT event identified a limiting MDC value to be with loss of offsite power (LOOP) 0.30 Ak/gm/cc. This value is also used for the less-limiting pre-trip SLB with LOOP event.

MDC-values for the post-trip SLB event are chosen, along with DPC values to model conservative stuck rod coefficients. The Post-trip steamline break values chosen for the MDC are unchanged for EPU and provide maximum core energy transfer to the primary coolant in an effort to maximize potential return to power.

MDC is not a key parameter for this event. A default MDC of 0 is Loverprssuf cn ser vused since minimum moderator reactivity feedback is conservative for a primary system heatup event.

Loss of condenser vacuum - MDC is not a key parameter for this event. A default MDC of 0 is departure from nucleate boiling used since minimum moderator reactivity feedback is (DNB) case conservative for a primary system heatup event.

Loss of non-emergency AC to the This event is bounded by other events.

station auxiliaries Loss of normal feedwater flow This event is bounded by other events.

Feedwater system pipe rupture The FLB event is analyzed as a primary heatup event, and as (FLB) - reactor coolant system such, it is conservative to select minimum reactivity feedback.

(RCS) overpressure case Therefore a 0 MDC value is conservatively chosen.

Feedwater system pipe rupture - The FLB event is analyzed as a primary heatup event, and as main steam (MS) system such, it is conservative to select minimum reactivity feedback.

overpressure case Therefore a 0 MDC value is conservatively chosen.

Maximum reactivity feedback is conservative for the ASGT event ransymentri stem gas it maximizes the core power increase. As such, the most transient (ASGT) positive MDC of 0.43 Ak/gm/cc is chosen.

L-2011-532 Attachment 1 Page 19 of 62 Table SRXB-49-1 (Continued)

Moderator Density Coefficient Justification for EPU Non-LOCA Safety Analyses Event MDC Value Justification MDC is not a key parameter for this event. A default MDC of 0 is Partial/complete loss of forced flow used as minimum reactivity feedback is conservative for a primary system heatup event.

MDC is not a key parameter for this event. A default MDC of 0 is reator/coolant pumk DB(C seie used as minimum reactivity feedback is conservative for a primary rotor/shaft break - DNB case sse etpeet system heatup event.

RCP seized rotor/shaft break - MDC is not a key parameter for this event. A default MDC of 0 is overpressure/peak cladding used as minimum reactivity feedback is conservative for a primary temperature (PCT) case system heatup event.

Uncontrolled control element MDC is not a key parameter for this event. A default MDC of 0 is assembly (CEA) bank withdrawal used.

from subcritical Both minimum and maximum reactivity feedback are considered Uncontrolled CEA bank withdrawal at for this event in an effort to minimize departure from nucleate power boiling ratio (DNBR). As such, the full range of 0 to 0.43 Ak/gm/cc is considered for the MDC value.

MDC is not a key parameter for this event. A default MDC of-0 is CEA misoperation (dropped rod) used.

Startup of an inactive loop at an Event precluded by plant Technical Specifications (TS).

incorrect temperature Chemical and volume control system Reactivity parameters are not considered in this analysis as no (CVCS) malfunction that results in a case runs or simulations are performed. This analysis consists of decrease in the boron concentration a series of hand calculations used to determine time to criticality in the reactor coolant and monitoring frequencies.

CEA ejection MDC is not a key parameter for this event. A default MDC of 0 is used.

Inadvertent emergency core cooling Event precluded by safety injection system design.

system (ECCS) operation at power Maximum reactivity feedback is conservatively chosen to CVCS malfunction maximize pressurizer filling during the event. As such, the most positive MDC of 0.43 Ak/gm/cc is used.

Minimum MDC reactivity feedback is conservatively chosen to Inadvertent RCS depressurization minimize the DNBR. As such a 0 MDC is used in this event consistent with beginning of life (BOL) conditions.

Steam generator tube rupture The selection of reactivity parameters does not affect the leakage Stea rate and thus has no impact on steam releases and margin to (SGTR) overfill. Therefore, a 0 MDC is used.

Anticipated transients without scram Precluded by the presence of the diverse scram system (DSS),

(ATiaS) diverse turbine trip (DIT) and diverse auxiliary feedwater actuation system (DAFAS).

L-2011-532 Attachment 1 Page 20 of 62 Table SRXB-49-2 Moderator Temperature Coefficient Justification for EPU Non-LOCA Safety Analyses Event MTC Value Justification Maximum reactivity feedback is conservatively modeled for this Decrease in feedwater temperature event since it results in a primary system cooldown. As such, the most negative MTC specified in the TS is assumed.

Maximum reactivity feedback is conservatively modeled for this Increase in feedwater flow rate event since it results in a primary system cooldown. As such, the most negative MTC specified in the TS is assumed.

Excessive increase in main steam This event is bounded by other events.

flow Inadvertent opening of an SG relief This event is bounded by other events.

or safety valve Pre-trip steamline break with failure Reactivity feedback is conservatively chosen to maximize the ofPthe-trstebustramnsebrek with fpre-trip power increase and thus maximize the heat flux.

of the fast bus transfer (FFBT) Therefore, the most negative specified in the TS is chosen.

Reactivity feedback is conservatively chosen to maximize the Pre-trip steamline break coincident pre-trip power increase and thus maximize the heat flux.

with loss of offsite power (LOOP) Therefore, the most negative MTC specified in the TS is chosen.

The most negative MTC specified in the TS is chosen as, under a Post-trip steamline break primary system cooldown, a negative MTC will maximize the core energy transfer to the primary coolant and -thus maximize-the potential for return to power.

Minimum reactivity feedback is conservatively used since the Loss of condenser vacuum - event results in a primary system heatup. EPU LAR overpressure case Attachment 5, Figure 2.8.5.0-6 indicates that a 0 MTC is applicable to this case at 100% power.

Minimum reactivity feedback is conservatively used since the Loss of condenser vacuum - event results in a primary system heatup. EPU LAR DNB case Attachment 5, Figure 2.8.5.0-6 indicates that a 0 MTC is applicable to this case at 100% power.

Loss of non-emergency AC to the This event is bounded by other events.

station auxiliaries Loss of normal feedwater flow This event is bounded by other events.

The FLB event is analyzed as a primary heatup event, and as Feedwater system pipe rupture - such, it is conservative to select minimum reactivity feedback.

RCS overpressure case Therefore a least negative MTC value of 0 is conservatively chosen.

The FLB event is analyzed as a primary heatup event, and as Feedwater system pipe rupture - such, it is conservative to select minimum reactivity feedback.

MS system overpressure case Therefore a least negative MTC value of 0 is conservatively chosen.

Maximum reactivity feedback is conservative for the ASGT event ransymentri stem gas it maximizes the core power increase. As such, the most transient (ASGT) negative MTC specified in the TS is chosen.

L-2011-532 Attachment 1 Page 21 of 62 Table SRXB-49-2 (continued Moderator Temperature Coefficient Justification for EPU Non-LOCA Safety Analyses Event MTC Value Justification Partial/complete loss of forced flow A least negative MTC of 0 is conservatively chosen for this event as it initially results in a primary system heatup.

RCP seized rotor/shaft break - DNB A least negative MTC of 0 is conservatively chosen for this event case as it initially results in a primary system heatup.

RCP seized rotor/shaft break - A least negative MTC of 0 is conservatively chosen for this event overpressure/PCT case as it initially results in a primary system heatup.

A least negative (at low power, most positive) MTC of +5 pcm/0 F is conservatively chosen for this event as once the initial neutron Uncontrolled CEA bank withdrawal flux peak is reached, a most positive MTC will result in a higher from subcritical succeeding rate of power change. The most positive MTC at low power conditions is shown in EPU LAR Attachment 5, Figure 2.8.5.0-6.

This event considers both minimum and maximum reactivity Uncontrolled CEA bank withdrawal at feedback in an effort to minimize DNBR. As such, the minimum power MTC of 0 and the maximum MTC specified in the TS are considered.

A wide range of MTCs from 0 up to and exceeding the TS limit are conservatively analyzed in an effort to minimize DNBR.

Startup of an inactive loop at an Event precluded by plant TS.

incorrect temperature incVCSrmfcti teaturest i Reactivity parameters are not considered in-this analysis as no dcreasefinctheiboron conrenltrtionacase runs or simulations are performed. This analysis consists of horolant a series of hand calculations used to determine time to criticality in the reactor cand monitoring frequencies.

Several MTC values are conservatively used in this analysis. The least negative (or most positive for the hot zero power (HZP) case at BOL conditions) MTC of 0 at hot full power (HFP) or +5 pcm/°F CEA ejection at HZP is conservatively chosen to maximize the power increase in the event. For the HFP and HZP cases at end of life (EOL) conditions, the least negative MTC values are used in an effort to maximize core power increase.

Inadvertent EGGS operation at Event precluded by safety injection system design.

power Maximum reactivity feedback is conservatively chosen for this CVCS malfunction event to maximize pressurizer filling. As such, the most negative MTC specified in the TS value is used.

Minimum MTC reactivity feedback is chosen for this event The Inadvertent RCS depressurization event is insensitive to MTC feedback, and as such, the least negative MTC of 0 is used to maintain consistency with the choice of MDC.

Steam generator tube rupture The selection of reactivity parameters does not affect the leakage rate and thus has no impact on steam releases and margin to (SGTR) overfill. Therefore, a least negative MTC of 0 is used.

Anticipated transients without scram Precluded by the presence of the DSS, DTT and DAFAS.

(ATWS)

L-2011-532 Attachment 1 Page 22 of 62 Table SRXB-49-3 Doppler Power Coefficient Justification for EPU Non-LOCA Safety Analyses Event DPC Value Justification*

Maximum reactivity feedback is conservatively modeled for this Decrease in feedwater temperature event since it results in a primary system cooldown. As such, the least negative DPC curve is used consistent with EOL conditions.

Maximum reactivity feedback is conservatively modeled for this Increase in feedwater flow rate event since it results in a primary system cooldown. As such, the least negative DPC curve is used consistent with EOL conditions.

Excessive increase in main steam This event is bounded by other events.

flow or alveThis saety event is bounded by other events.

Inaverentopeingof n S reief This event is bounded by other events.

or safety valve Reactivity feedback is conservatively chosen to maximize the pre-Pre-trip steamline break with failure trip power increase and thus maximize the heat flux. Therefore, of the fast bus transfer (FFBT) the least negative DPC curve corresponding to EOL conditions is chosen.

Reactivity feedback is conservatively chosen to maximize the pre-Pre-trip steamline break coincident trip power increase and thus maximize the heat flux. Therefore, with loss of offsite power (LOOP) the least negative DPC curve corresponding-to EOL conditions is chosen.

The DPC in the post-trip SLB event is overwritten by a general data table that models a conservative stuck-rod Doppler power Post-trip steamline break defect curve-chosen to maximize core energy transfer to the primary coolant and- thus maximize the possibility for a return to power.

Minimum reactivity feedback is conservatively used as the event Loss of condenser vacuum - results in a primary system heatup. The least negative DPC overpressure case curve for 100% power is shown in EPU LAR Attachment 5, Figure 2.8.5.0-5 and is used for this event.

Minimum reactivity feedback is conservatively used as the event Loss of condenser vacuum - results in a primary system heatup. The least negative DPC DNB case curve for 100% power is shown in EPU LAR Attachment 5, Figure 2.8.5.0-5 and is used for this event.

Loss of non-emergency AC to the This event is bounded by other events.

station auxiliaries Loss of normal feedwater flow This event is bounded by other events.

The FLB event is analyzed as a primary heatup event, and as Feedwater system pipe rupture - such, it is conservative to select minimum reactivity feedback.

RCS overpressure case Therefore a least negative DPC curve is conservatively chosen.

The FLB event is analyzed as a primary heatup event, and as Feedwa ster tem pipe rupture - such, it is conservative to select minimum reactivity feedback.

MS system overpressure case Therefore a least negative DPC curve is conservatively chosen.

Asymmetric steam generator A least negative DPC curve is conservatively chosen to maximize transient (ASGT) the core power increase during the ASGT event.

L-2011-532 Attachment 1 Page-23 of 62 Table SRXB-49-3 (continued)

Doppler Power Coefficient Justification for EPU Non-LOCA Safety Analyses Event DPC Value Justification*

A most negative DPC curve is conservatively chosen to maximize the energy transfer to primary coolant during this heatup event.

RCP seized rotor/shaft break - A most negative DPC curve is conservatively chosen to maximize DNB case the energy transfer to primary coolant during this heatup event.

RCP seized rotor/shaft break - A most negative DPC curve is conservatively chosen to maximize overpressure/PCT case the energy transfer to primary coolant during this heatup event.

A least negative Doppler Power Defect is conservatively chosen UcnrolledmE bank wto maximize the power peak reached during the initial part of the from subcritical taset transient.

This event considers both minimum and maximum reactivity Uontro feedback in an effort to minimize DNBR. As such, the minimum power and maximum DPC curves in Figure 2.8.5.0-5 are considered.

CEA misoperation (dropped rod) The most negative curve of the Doppler Power Coefficient in Figure 2.8.5.0-5 is used in an effort to minimize DNBR.

Startup of an inactive loop at an Event precluded by Plant Technical Specifications.

incorrect temperature CVCS malfunction that results in a Reactivity parameters are not considered in this analysis as no case runs-or simulations are performed. This analysis consists of inrcthe decreae orolant ca series of hand calculations used to determine time to criticality and monitoring frequencies.

A least negative Doppler Power Defect is conservatively chosen CEA ejection to maximize the power peak reached during the initial part of the transient.

Inadvertent ECCS Operation-at Event precluded by safety injection system design.

Power Maximum reactivity feedback is conservatively chosen for this CVCS malfunction event to maximize pressurizer filling. As such, the most negative DPC curve is used.

Minimum Doppler reactivity feedback is chosen for this event.

Inadvertent RCS Depressurization The event is insensitive to DPC feedback, and as such the least negative DPC curve corresponding to BOL conditions is used to maintain consistency with the choice of MDC.

Steam Generator Tube Rupture The selection of reactivity parameters does not affect the leakage StGena Trate and thus has no impact on steam releases and margin to (SGTR) overfill. Therefore, a least negative DPC curve is used.

Anticipated Transients Without Precluded by the presence of the DSS, DTT and DAFAS.

Scram (ATWS)

• The minimum and maximum DPC curves are shown in EPU LAR Attachment 5, Figure 2.8.5.0-5.

For simplicity, they are referred to as minimum (least negative) or maximum (most negative) in the justifications herein.

L-2011-532 Attachment 1 Page 24 of 62 SRXB-50 (RAI 2.8.5.0-3)

Page 2.8.5.0-18 indicates that ABORTVI is used in the analysis of the boron dilution event.

Discuss the ABORTVI code and address acceptability of the code for the analysis.

Response

The ABORTV1 program is an analytical tool used to perform mathematical iterations in the inadvertent boron dilution event. ABORTV1 uses the basic boron dilution equations presented in Section 15.4.6 of the Updated Final Safety Analysis Report (UFSAR). The ABORTVl program is performed in an iterative manner. That is, the program assumes critical boron concentration values over a range of initial boron concentration values and calculates the corresponding time from alarm to criticality, until the acceptance criterion is exactly satisfied. The end result is a limiting pair of initial to final critical boron concentrations that exactly satisfies the acceptance criterion for operator action for a given mode. This is the same method as one would perform by hand for a typical boron dilution analysis; however, it is automated efficiently through the use of the ABORTV1 program.

SRXB-51 (RAI 2.8.5.0-4)

Table 2.8.5.0-4 lists that the TS and analysis setpoints of the reactor coolant flow - low trip are 95.4% and 88.4% of the thermal design flow, respectively.

Specify the value of the thermal design flow (TDF) in the unit of gpm. Clarify the differences-of the TDF, the minimum reactor coolant flow specified-in Function 14 of-the proposed TS Table 2.2-1, and the lower limit of the reactor coolant flow rate listed in current TS Table 3.2-2. Provide a derivation of the TS trip setpoint from the analysis setpoint for the reactor coolant flow - low trip and address acceptability of the method deriving the setpoint.

Response

Thermal design flow (TDF) for EPU, which is the same as the minimum reactor coolant flow, is 375,000 gpm total or 187,500 gpm per hot leg loop. The current, pre-EPU Technical Specifications (TS) Table 3.2-2 lists a minimum value of 335,000 gpm for the lower limit of the reactor coolant flow and refers to the Core Operating Limits Report (COLR) for the cycle specific minimum reactor coolant flow. The EPU LAR was based on the minimum reactor coolant flow or TDF of 375,000 gpm being in the COLR and deleting the lower limit of the reactor coolant flow in TS Table 3.2-2. However, based on NRC RAIs SRXB-36 and SRXB-37 and FPL's response to these RAls in FPL letter L-2011-422, dated October 10, 2011, the minimum reactor coolant flow requirement of 375,000 gpm will be moved to TS Limiting Condition for Operation (LCO) 3.2.5 and deleted from the COLR. Also, the EPU LAR proposed change to TS Table 2.2-1 is revised by FPL letter L-2011-422, dated October 10, 2011, such that the minimum reactor coolant flow will refer to TS LCO 3.2.5 and not the COLR.

RCS Low Flow Trip Setpoint The trip setpoint is defined in the TS Table 2.2-1 as ->95.4% of TDF. The TDF, as stated above, is the same as the minimum reactor coolant flow or 375,000 gpm. The minimum measured flow (MMF) is obtained by applying an uncertainty of 15,000 gpm to the TDF. The MMF is thus equal to 390,000 gpm.

The analysis trip setpoint value is 91.9% of TDF (TDF = 375,000 gpm), which corresponds to 88.4% of MMF (MMF = 390,000 gpm).

L-2011-532 Attachment 1 Page 25 of 62 In setting the trip setpoint, the analysis value is assumed to be 92% of TDF (slightly conservative with respect to the analysis trip setpoint value of 91.9% of TDF). All the uncertainties related to the measured parameters are applied on top of the analysis setpoint value, including a calibration allowance, to obtain the trip setpoint value to be set at the plant. This setpoint is verified to be greater than 95.4% of TDF, thus meeting the TS requirement.

The measured parameters are:

RCS flow in gpm (F)

Each reactor protective system (RPS) channel signal in volts (V) - The lower limit is 1.0 volt for 0 gpm flow Cold leg temperature in OF (T)

From the measured flow F and the channel signal V, which is based on the steam generator pressure difference, the signal corresponding to the analysis flow value (92% of 375,000 gpm) is determined as (ITSPaI) using the correlation P as given below as a function of flow ratio f. The correlation P is not impacted by the EPU and thus remains unchanged from the current procedure. Although minor, a density correction factor D is applied to cover the impact of any difference between the measured temperature and the analysis value of 551 OF.

ITSPal = 1.0 + P D (IVI- 1.0)

The total uncertainty, using the root sum square (RMS) method, is calculated to be 0.155 volts, which covers the flow measurement uncertainty (EF) of 15000 gpm, a conservative channel signal uncertainty (EV) of 0.094 volts and a calibration allowance of-0.016 volts.

The uncertainty Et' is calculated as follows:

(Et)2= TSPI/F) 2 EF2 + (61TSPI/61VI) 2 . EV 2 Ev = 0.094 volts (actual uncertainty is < 0.090 volts)

EF = 15,000 gpm Total uncertainty = Et' + 0.016 volts The final trip setpoint (in volts) thus becomes, ITSPI = 1.155 + P D (IVI- 1.0)

TSP is the Trip Setpoint in volts V = Channel Signal value corresponding to the measured flow (full flow conditions), in volts f = (0.92 e TS Fiow)/F P = 1.554 + f (2.54 f - 3.089)

F = Measured Flow, in gpm D = Density Correction Factor TS Flow = 375,000 gpm (TDF flow)

This method ensures compliance with the EPU analysis and TS requirements and is thus acceptable for operation at EPU conditions.

L-2011-532 Attachment 1 Page 26 of 62 SRXB-52 (RAI 2.8.5.1.1-1)

Page 2.8.5.1.1-6 indicates that the minimum SGTP is assumed in the analysis of an increase in feedwater event.

Specify the value of the SGTP level used in the analysis and explain why the value used is conservative, as claim on page 2.8.5.1.1-6 and acceptable.

Response

The level of steam generator tube plugging (SGTP) assumed for the event is 0%. The increase in feedwater event, a cooldown event, is conservatively analyzed to cover the effects of SGTP by assuming that the steam generator heat transfer characteristics are consistent with 0% SGTP and the reactor coolant system flow rate is equivalent to 10% SGTP. This modeling approach is conservative because it maximizes the heat transfer from the primary to secondary side which is more severe for a cooldown event.

SRXB-53 (RAI 2.8.5.1.1-2)

Section 2.8.5.1.1.2.1.3 indicates that the results from the RETRAN code are used to determine if the DNB safety analysis limits for excessive heat removal due to feedwater malfunction are met.

Discuss how the results of the RETRAN code are used in determining if the DNBR limits are met.

Response

For the excessive heat removal events described in EPU LAR Attachment 5, Section 2.8.5.1.1.2.1, Increase in Feedwater Flow, RETRAN is used to determine if the departure from nucleate boiling ratio (DNBR) safety analysis limit is met. Per Reference SRXB-53-1, RETRAN is an NRC approved code that includes capability to calculate DNBR for symmetric events. RETRAN DNBR calculations are conservative for symmetric events when compared to newer DNBR codes such as VIPRE. As described in Section 2.8.5.1.1.2.1, the minimum DNBR calculated by RETRAN for the Feedwater Malfunction event occurred at 140.6 seconds and had a value of 1.96. This value is well above the DNBR analysis limit of 1.42. Since considerable margin exists and there is no core asymmetry in this event, it was confirmed that the conditions at the time of minimum DNBR were within the range for which the conservative RETRAN derived DNBR estimation is valid. Considering the large margin to the limit, the RETRAN DNBR estimation is sufficient to show that the DNBR limit is not violated for this event.

Reference SRXB-53-1 WCAP-1 4882-P-A (Proprietary) and WCAP-1 5234-A (Non-Proprietary),

"RETRAN-02 Modeling and Qualification for Westinghouse Pressurized Water Reactor Non-LOCA Safety Analyses," April 1999.

L-2011-532 Attachment 1 Page 27 of 62 SRXB-54 (RAI 2.8.5.1.2-1)

Figure 2.8.5.1.2-18 shows the safety injection (SI) flow curve used in the post-trip steam line break (SLB) analysis for EPU application. This curve appears different from the SI flow curve in UFSAR Figure 15.1.6-3, which is used in the analysis of record (AOR) for the post-trip SLB case. For example, Figure 2.8.5.1.2-18 shows that at the RCS pressure of 200 psia, the SI flow rate is 16.5 Ibm/sec versus 70 Ibm/sec shown in UFSAR Figure 15.1.6.3.

Explain why different SI flow curves are used for the EPU and AOR analyses, and verify that the SI flow is Figure 2.8.5.1.2-18 represents the flow characteristics of the SI pump for EPU operation.

Response

The safety injection (SI) flow curve given in the Updated Final Safety Analysis Report (UFSAR)

Figure 15.1.6.3, is the total SI flow (summation of all four cold legs using one high pressure safety injection (HPSI) pump). The SI flow curve given in the EPU LAR Attachment 5, Figure 2.8.5.1.2-18 is the SI flow for one cold leg using one HPSI pump. Figure SRXB-54-1 below is Figure 2.8.5.1.2-18 converted to total SI flow using one HPSI pump. For example, at 200 psia the minimum SI flow is -16.5 Ibm/sec per cold leg, therefore the total SI flow is 67 Ibm/sec (-16.5 Ibm/sec

• 4). Thus, the SI flow curve used for the EPU post-trip steam line break analysis has a slightly lower total SI flow than the analysis of record SI flow curve. This is conservative as it results in less boron injection after SI actuation.

Figure SRXB-54-1 Total SI Flow Using One HPSI Pump 1200 ..............

1000 800 00 400 200 0

0 10 20 30 40 so 60 70 80 Total Safety Injection Flow Rate {ibn!sec)

L-2011-532 Attachment 1 Page 28 of 62 SRXB-55 (RAI 2.8.5.1.2-2)

Table 2.8.5.1.2-5 includes the sequence of events for the analysis of the limiting post-trip SLB case. This table shows that the criticality occurs at 27 seconds following the manual reactor trip, and the peak heat flux occurs at 31.25 seconds after criticality occurrence. A comparison with the post-trip SLB analysis in AOR, UFSAR Table 15.1.6-1 reveals that for the limiting AOR post-trip SLB case the core criticality occurs at 48.08 seconds following the manual reactor trip and peak heat flux occurs at 257.45 seconds after the core becomes critical.

Explain design differences and assumptions used in the analysis that contributes to a longer delay time to reach the peak heat flux for the AOR case (257.45 seconds) versus that for the EPU case (31.25 seconds) after re-criticality occurs.

Response

A sensitivity study was performed on the post-trip steam line break (SLB) analysis as described in the response to RAI SRXB-57. The study revealed that a vapor lock occurred in the affected steam generator (SG) which dramatically reduced the heat transfer from the primary to the secondary fluid (for additional information see the response to RAI SRXB-57). The sensitivity study revealed that without the vapor lock, the peak heat flux is 6.0% (the analysis of record (AOR) peak heat flux was 18.3%) and the time of peak heat flux occurs at 520.00 seconds which is later than the-AOR time of peak heat flux.

Table SRXB-55-1 Analysis of Record - Sensitivity Study*

AOR Sensitivity Study Time core-criticality attained (sec.) 48.05 182.0 Time of peak heat flux (sec.) 305.50 520.00

• Time values in seconds are not adjusted to reflect different T=0 times, 0.01 seconds for AOR and 10 seconds for sensitivity study.

The difference between the AOR and sensitivity study results is due to the integral flow restrictor in the exit nozzle of the replacement steam generators. The flow restrictor limits the effective break flow area to 1.910 ft2, which is significantly smaller than the AOR break flow area of 6.305 ft 2. The reduction in effective break flow area slows the cooldown rate delaying the time to criticality and minimizes the asymmetry between the faulted and non-faulted loops, which is a benefit to SLB events. The sequence of events from the sensitivity study is shown in Table SRXB-55-2 and a plot of Heat Flux vs. Time is presented in Figure SRXB-55-1.

L-2011-532 Attachment 1 Page 29 of 62 Table SRXB-55-2 Post-Trip Steam Line Break (SLB) Sequence of Events Event Time (sec) Value 2 10.0 ---

SLB (1.910 ft DER) transient initiated Manual reactor trip 10.0 ---

Main steam isolation valve (MSIV) / main feedwater isolation valve 21.6 487 psia (MFIV) closure signal on low steam generator pressure Safety injection actuation signal (SIAS) on low pressurizer pressure 26.1 1638 psia Feedwater isolation 26.8 5.15 sec. delay Steam line isolation (MSIV closure) on loops 1 and 2 28.4 6.75 sec. delay Core criticality attained 182.0 Peak heat flux reached 520.00 6.0%

Minimum departure from. nucleate boiling ratio (DNBR) reached 520.00 3.611 Peak linear heat rate reached 520.00 11.41 kW/ft

L-2011-532 Attachment 1 Page 30 of 62 Figure SRXB-55-1 Core Heat Flux vs. Time 0-5E-01 II

-- i 0.4E-Oi -

- /

0-2E-01 Iii CDC ItI

'O.2E-O-i 0--

l

-0iE-0 0 iC0 200 300 400 500 600 Time (s)

L-2011-532 Attachment 1 Page 31 of 62 SRXB-56 (RAI 2.8.5.1.2-3)

Figure 2.8.5.1.2-20 shows that at the SLB initiation (10 seconds), the break flow rates are about 7,510 Ibm/sec and 3,300 Ibm/sec for the unaffected and affected steam generators (SGs), respectively.

Discuss the effective break areas that are assumed for the unaffected and affected SGs at the SLB initiation. If the break flow are assumed for the unaffected SG is different from the cross-sectional area of the integral flow restrictor installed in the SG outlet nozzle, address acceptability of the break flow are assumed in the analysis for the unaffected SG.

Response

The outlet nozzle area of both steam generators (SGs) was modeled to be equal to the area of the integral flow restrictor (1.910 ft 2). The actual break size modeled for the post-trip steam line break (SLB) is equal to a double ended rupture of the steam line (6.305 ft2). When the break occurs, the steam in the steam line and steam header exits the break experiencing a break size equal to 6.305 ft2 because it has already passed through the integral flow restrictors. In this analysis, reverse steam flow, any flow along the path from the unaffected SG to the break, is considered to be the break flow from the unaffected SG. Because the flow from the steam line and steam header out the break is considered to be part of the unaffected SG break flow, the initial flow spike for the unaffected SG is significantly larger than the affected SG initial spike.

After the steam in the steam line and steam header exits the break, the steam from the unaffected SG flows from the SG experiencing a break flow area equal to 1.910 ft2 . For this reason, after a-few seconds the two SG break flow rates are approximately equal (both flows are restricted by the flow restrictors).

SRXB-57 (RAI 2.8.5.1.2-4)

Figure 2.8.5.1.2-23 shows that the cold leg temperature (CLT) decreases rapidly after the SLB initiation. For the affected SG, at about 25 seconds the CLT suddenly increases until 30 seconds, following with a decrease of 8 0 F. From 38 to 41 seconds, the CLT increases by about 20 F, following with a continued decrease until 93 seconds when the pressurizer is refilled with water. After the pressurizer is refilled, the CLT turns to increase until 150 seconds when the computer runs ends Explain thermal-hydraulic phenomena for the identified CLT increases during the above period of 0 to 150 seconds in response to applicable system actuations or operator actions.

Response

The increase in cold leg temperature from about 25 to 30 seconds and then again from about 38 to 41 seconds in EPU LAR Attachment 5, Figure 2.8.5.1.2-23 is caused by a decrease in heat transfer from the primary to the secondary side. About ten seconds into the steam line break (20 seconds into the figure), the rapid depressurization of the steam. generator (SG) causes the liquid (SLB) in the lower downcomer of the SG to flash to steam, forming a vapor bubble in the lower downcomer and lower bundle regions. Due to the high resistance of the evaporator region at this time, the vapor bubble is unable to move from the lower bundle and begins to degrade the heat transfer for that region of the SG U-tubes. The degradation in heat transfer reduces the amount of energy removed from the primary side; retarding the cooldown of the primary side.

This resulted in an appearance of the hot leg temperature in the cold leg. Hence, the initial cold leg temperature increase seen at about 25 seconds in Figure 2.8.5.1.2-23.

L-2011-532 Attachment 1 Page 32 of 62 Along with the temporary loss of heat transfer in that area of the bundle, the depressurization of the SG continues. Eventually, heat transfer from the primary to secondary sides at the lower bundle portion of the SG U-tubes is restored. At which time, cooldown of the reactor coolant system (RCS) recommences and the cold leg temperature begins to decrease again. This is seen at 30 seconds in Figure 2.8.5.1.2-23.

The second increase and decrease 38 to 41 seconds into Figure 2.8.5.1.2-23 is the re-appearance (with one RCS loop time delay) of the first temperature excursion seen between 25 to 30 seconds in the Figure. Between these times, the warmer water is passing through the cold leg once again, but at a cooler condition since heat transfer had been restored. After an additional cycle time, the block of warmer water had been sufficiently mixed and cooled down to see no further increase in the cold leg temperature until 93 seconds.

A sensitivity study was performed to eliminate the vapor lock condition thereby improving the primary to secondary heat transfer and increase the RCS cooldown. The study determined that when there is no vapor lock, the event is extended beyond that noted in the analysis of record (AOR) and the maximum heat flux is 6.0% (the EPU analysis maximum heat flux was 5.6%).

The EPU analysis calculated a minimum departure from nucleate boiling ratio (DNBR) of 4.307 with a limit of 1.30 whereas the sensitivity study calculated a minimum DNBR of 3.611. The other major assumptions remained the same between the AOR, EPU and sensitivity study. Those assumptions are that feedwater flow matches steam flow and the feedwater enthalpy is equal to that of the AFW so that the primary system cooldown is maximized. The cold leg temperature vs.

time plot from-the study is presented in Figure SRXB-57-1.

L-2011-532 Attachment 1 Page 33 of 62 Figure SRXB-57-1 Post-Trip SLB Cold Leg Temperature vs. Time FauIt F ed Unfaul ted r; P. .

• JU 450 - a ~N

• - 450-C-

C-J O)

_Ju' 4A 00 500 Timre (s')

SRXB-58 (RAI 2.8.5.1.2-5)

Section 2.8.5.1.2.2.1.2 discusses input parameters and assumptions used in the SLB with a failure of the fast bus transfer (FFBT) case. It lists seven assumptions that are consistent with the first seven assumptions used in the AOR documented in the latest version of the UFSAR, Section 15.1.5.2. However, the last four assumptions (8 through 11) in the AOR are missing. The four assumptions include conservatisms in the analysis in resolving the NRC's concern of thermal-hydraulic modeling of core inlet flow distribution during a 2-pump coastdown applicable to the SLB with the FFBT case.

Address acceptability of deletion of the four assumptions. If the same AOR conservatisms addressing the 2-pump coastdown model remain applicable, add the missing assumptions 8 through 11 to be updated AOR for EPU operation.

Response

Assumptions 8 through 11 listed in Updated Final Safety Analysis (UFSAR) Section 15.1.5.2 are still valid and applicable to the pre-trip steam line break (SLB) with a failure of the fast bus transfer (FFBT) analysis. The assumptions were not listed in EPU LAR Attachment 5,

L-2011-532 Attachment 1 Page 34 of 62 Section 2.8.5.1.2.2.1.2 because they are considered inherent to the approved methodology.

The assumptions are listed below for completeness.

8. In RETRAN, the transient nuclear power prediction does not credit a decrease in rod drop time due to a core flow reduction experienced during the two-pump coastdown.

9. In RETRAN, the transient nuclear power prediction assumes a minimum scram reactivity worth based upon the most bottom-peaked axial power distribution. In VIPRE, the departure from nucleate boiling ratio (DNBR) calculations are based on a top-peaked axial power distribution.

10. In VIPRE, the peak power assembly with the peak rod at the radial peaking factor (Fr) design limit and a low peak-to-average power ratio is modeled at the core location corresponding to the minimum flow assembly.

11. In estimating the number of rods in departure from nucleate boiling (DNB), the most limiting channel's local conditions at the time of minimum departure from nucleate boiling ratio (DNBR) are used to back-calculate Fr corresponding to the DNB specified acceptable fuel design limits (SAFDL). By presuming that every fuel pin in the core with a pin power above this peaking limit experiences DNB (via the pin census data), the entire core is modeled at the limiting channel conditions.

SRXB-59 (RAI 2.8.5.1.2-6)

Figure 2-8.5.1.2-1 includes the results of a sensitivity study showing the peak heat flux as a function of the break sizes of 0.1 to 6.31 ft 2, which represents the cross-sectional area of the steam line. The figure shows that the limiting break, resulting in a highest peak heat flux, is 1.9_1 ft 2, which is the cross-sectional area of the integral flow restrictor installed in the SG outlet nozzle. The break flow rates and the resulting-cooldown effect are limited by the flow area of-the integral flow restrictors. However, as shown-in the figure, break sizes greater than 1.91 ft 2 are also included for the sensitivity study in determining the limiting break.

Discuss the bases for the use of break sizes greater than 1.91 ft2 in the sensitivity study.

Response

The maximum area of the steam line is 6.31 ft2 ; however, the maximum effective break flow area is limited to 1.91 ft 2 because of the integral flow restrictors. Break sizes greater than 1.91 ft 2 were examined to assure that the most limiting steam generator steam flow was obtained. The driving force for steam flow through the integral flow restrictors is the difference in upstream and downstream pressure. Break sizes larger than 1.91 ft2 were analyzed to ensure that a lower downstream pressure would not result in a more severe transient.

L-2011-532 Attachment 1 Page 35 of 62 SRXB-60 (RAI 2.8.5.1.2-7)

Page 2.8.5.1.2-6 indicates that the least negative value of Doppler-only power coefficient (DPC), along with the most negative moderator temperature coefficient (MTC) limit, is used in the analysis of the pre-trip SLB with LOOP case in support of EPU application. For the pre-trip SLB with LOOP case in AOR, page 15.1.10 of the latest version of the UFSAR indicates that a conservative large absolute value of the DPC is used, along with the most-positive MTC limit. Although different values of the DPC (the least negative value vs. a conservative large absolute value) and MTC (the most negative limit vs. the most positive limit) are used in the EPU analysis and AOR, both analyses state that the use of above values of DPC and MTC would maximize the transient core power, resulting in an minimum DNBR.

Explain why a different set of DPC and MTC values (discussed above) used in the EPU analysis and AOR could result in a maximum core power for the pre-trip SLB with LOOP cases.

Response

The pre-trip steam line break (SLB) with loss of offsite power (LOOP) case is very different from a return to power SLB case. Because there is a LOOP at break initiation, the reactor trips on low reactor coolant system flow almost immediately. Therefore, the core does not experience a significant cooldown caused by the excess steaming of the affected steam generator until after the control rods begin to fall into the core. The core, however, experiences a slight heat up prior to the reactor trip.

The analysis of record (AOR) SLB with LOOP analysis showed that the moderator temperature coefficient (MTC) and Doppler power coefficient (DPC) have minimal impact on the calculated

-minimum departure from nucleate-boiling ratio (DNBR). Temperature driven-reactivity feedbacks, such as MTC and DPC have minimal impact on the results because the core does not experience a significant coolant temperature change due to the competing effects of the flow coastdown (heat up) due to the LOOP and the steam line break (cooldown). Since the impact of the reactivity feedback is minimal, a large- absolute value of DPC along with the most positive MTC was used, treating this as a heatup event.

Similar to the AOR analysis, since the impact of reactivity feedback on this event is minimal, the values used for the EPU analyses were based on maximizing any minor impact of cooldown subsequent to the reactor trip and insertion of rods. Thus, the values used for EPU were least negative DPC and most negative MTC.

Although different values of reactivity coefficients were used for AOR and EPU to maximize effects during a portion of the event progression, the overall impact of these coefficients is not significant to this event.

SRXB-61 (RAI 2.8.5.2.2-1)

Page 2.8.5.2.2.-3 indicates that with respect to long-term cooling (LTC) for the event initiating from a loss of non-emergency AC power to the station auxiliaries (LOAC), the ability of the auxiliary feedwater (AFW) system to remove decay following reactor trip is demonstrated by the analysis in UFSAR Chapter 10. Page 2.8.5.2.2-5 also states LTC analysis for the LOAC is presented in LR Section 2.5.4.5.

Discuss the applicable Chapter 10 and LR Section 2.5.4.5 analyses that are used to demonstrate adequacy of the capability of the AFW system for LTC. Address acceptability

L-2011-532 Attachment 1 Page 36 of 62 of both analyses in terms of the applicable acceptance criteria and the analytical results, methods used, initial conditions and assumptions utilized, equipment relied upon for consequence mitigation and the applicability of the analyses of the LOAC event for LTC.

The RAI regarding the LR Section 2.5.4.5 is also applicable to the LTC analyses referred in the analyses of a loss of normal feedwater event (page 2.8.5.2.3-5) and the feedwater line break (page 2.8.5.2.4-4).

Response

The following EPU LR Attachment 5, Section 2.5.4.5 analyses performed in accordance with the Updated Final Safety Analysis Report (UFSAR) Section 10.4.9A are used to assess the adequacy of the auxiliary feedwater (AFW) system for LTC:

" UFSAR Chapter 10 Loss of Normal Feedwater

= UFSAR Chapter 10 Feedwater Line Break Summaries for these events follow.

UFSAR Chapter 10 Loss of Normal Feedwater The loss of normal feedwater (LNF) analysis described in EPU LAR Attachment 5, Section 2.5.4.5 is performed consistent with the UFSAR Chapter 10.4.9A. The analysis performed ensures that the AFW system is sized sufficiently for the EPU. According to UFSAR Section 10.4.9A.1, the AFW design bases are-to ensure:

1. Sufficient capability exists for removal of decay heat from the reactor core;

2. The ability to reduce reactor coolant system (RCS)-temperatures to entry temperatures for activating-the shutdown cooling (SDC) system; and

3. Prevent lifting of the pressurizer safety-valves (PSVs) when considered in conjunction with the power operated relief valves (PORVs).

Item 1 above is satisfied by assuring that the steam generators (SGs) do not loose heat transfer capability during the event and are able to reduce the RCS temperature. As such, as long as inventory remains in the SGs, the AFW system is proven to provide sufficient capability for decay heat removal. Item 2 above is satisfied by demonstrating that subcooling margin is maintained throughout the entire event and inventory remains in the SGs. Item 3 above is satisfied by assuring the maximum pressurizer pressure remains below the PSV opening setpoint.

In addition to the three requirements listed above, an additional criterion is imposed on the LNF analysis. Maximum pressurizer water volume must remain less than 1519 ftW, thus ensuring a water solid state is not reached in the pressurizer and the accident does not propagate into a more severe event.

Consistent with the analyses performed in UFSAR Section 10.4.9A, the LNF analysis performed for the EPU includes cases with and without offsite power thus bounding the loss of non-emergency AC power (LOAC) event for long term cooling (LTC). Table SRXB-61-1 illustrates the key analysis parameters for cases with and without offsite power available.

L-2011-532 Attachment 1 Page 37 of 62 Table SRXB-61-1 Key Analysis Parameters for Loss of Normal Feedwater (LNF)

Parameter LNF LNF +

Loss of Offsite Power (LOOP)

Core Power 100% + uncertainty 100% + uncertainty (3030 MWt) (3030 MWt)

Loop Flow Rate Thermal Design Flow Thermal Design Flow (187500 gpm) (187500 gpm)

Reactor Coolant System (RCS) High & Low Nominal High & Low Nominal temperature (578.5 & 5630 F) (578.5 & 563 0 F)

Initial pressure Nominal (2250 psia) Nominal (2250 psia)

Initial water level Nominal (63%) Nominal (63%)

Pressurizer Charging/letdown Available Unavailable Heaters Available Unavailable PORVs Available Available Sprays Available Available Initial water level Nominal (65%) Nominal (65%)

Tube conditions & Fouled Fouled Steam steam generator tube 10% 10%

Generator plugging (SGTP)

(SG) Modeled to mimic steam Conservatively modeled-to Atmospheric dump bypass, SG pressure minimize SG inventory, SG valve (ADV) controlled to 900 psia pressure controlled to 900 psia*

Pumps 2AFW motorpumps driven 2 motor driven AFWpumps Auxiliary Flowrate ** 275 gpm per 275 gpm per Feedwater motor driven AFW pump motor driven AFW pump (AFW) Delay # 330 sec 330 sec Nominal - uncertainty Nominal - uncertainty Trip setpoint (13.0 % NRS) (13.0 % NRS)

Loss of offsite power Not assumed Assumed on reactor trip Pressurizer high 2370 psia 2370 psia Reactor pressure Trip Nominal - uncertainty Nominal - uncertainty Setpoint Low-low SG level (14.5 % narrow range (14.5 % NRS) scale (NRS))

Reactivity Beginning of cycle (BOC) BOC w/ max. value of 13 w/max. value of 13

• During a LOOP, the steam bypass control system (SBCS) is unavailable. ADVs are modeled in the LOOP case to conservatively minimize SG inventory.

• • Flowrate listed is for a degraded AFW pump.

AFW delay accounts for diesel generator startup and electrical load sequencing. A longer delay puts greater strain on the AFW system and is assumed for both cases.

L-2011-532 Attachment 1 Page 38 of 62 The LNF analysis performed in accordance with UFSAR Section 10.4.9A shows that more than 10% of the initial SG mass exists in either SG at the end of the transient. Sufficient SG heat transfer capability is proven through the reduction in RCS temperature shown in Figure SRXB-61 -1. The pressurizer water volume remains below 1519 ft 3, and as such, the pressurizer does not reach a water solid condition. Pressurizer pressure, despite rising initially, remains below the PSV setpoint and the PSVs do not open during the event. Subcooling margin is maintained throughout the entire event.

The sequence of events for the limiting LNF case (offsite power available) is presented in Table SRXB-61-2. Plots for the LNF case with offsite power available are presented in Figures SRXB-61-1 through SRXB-61-5. Consistent with the current design basis, this analysis has been run conservatively for one hour with no operator action.

Table SRXB-61-2 Loss of Normal Feedwater with Offsite Power Available Sequence of Events Time Event SetpointlValue (sec) ________________________ _________

0 - 20.0 Steady state period 20.0 Loss of feedwater to both SGs 57.8 Reactor trip signal on high pressurizer pressure 2370 psia 57.8 PORV actuates 58.2 Reactor trip 60.2 Turbine trip*

63.7 Low SG level auxiliary feedwater actuation signal 13.0 % (NRS)

(AFAS) setpoint reached 393.7 AFW flow reaches the SGs 275 gpm/SG 1162.5 Maximum pressurizer level 1512.2 ft3 1222.5 Minimum SG inventory 14,444 Ibm/SG 3620.0 Operator takes action to commence plant cooldown (1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> from start of event)

• Turbine trip is not credited in the transient analysis.

L-2011-532 Attachment 1 Page 39 of 62 Figure SRXB-61-1 Loss of Normal Feedwater with Offsite Power Available Hot and Cold Leg Temperature vs. Time U-590 580-m 570'

- 560 E

- 550 Of, 530-0 1000 2000 3000 4000 Time (s)

Figure SRXBý61-2 Loss of Normal Feedwater with Offsite Power Available Steam Generator Mass vs. Time---

140000 E" 120000-

c. 100000-80000 60000 I E 40000-U') 20000-111 U

0 1000 2000 3000 4000

-ime (s)

L-2011-532 Attachment 1 Page 40 of 62 Figure SRXB-61-3 Loss of Normal Feedwater with Offsite Power Available Pressurizer Pressure vs. Time 2400

-*o

.I 2350

? 2300

=3 co 2250

" _ 22200 S2150 2100 0 1000 2000 3000 4000 rime (s)

Figure SRXB-61-4 Loss of Normal Feedwater with Offsite Power Available Pressurizer Water Volume vs. Time 1600 1400 E 1200 0

1000 800 Ul)

CD 600 400 0 1000 2000 3000 4000 Time (s)

L-201-1-532 Attachment 1 Page 41 of 62 Figure SRXB-61-5 Loss of Normal Feedwater with Offsite Power Available Hot Leg Subcooling Margin vs. Time 1

110-

.~100, g80'

~70'

~60-5 0 -I .'1 . I ' I 1 0 1000 2000 3000 4000 lime (s)

UFSAR Chapter 10 Feedline Break The feedline break (FLB) analysis described in UFSAR Section 10.4.9A is an auxiliary analysis performed to ensure that the AFW system is sized sufficiently for the EPU. The AFW design bases are to ensure:

1. Sufficient capability exists for removal of decay heat from the reactor core.

2. The ability to reduce RCS temperatures to entry temperatures for activating the SDC system.

3. Prevent the passage of water through the PSVs such that a more serious plant-condition will not be generated without other faults occurring independently.

Item 1 above is satisfied by assuring that the SGs do not loose heat transfer capability during the event. As such, as long as inventory remains in the SGs, the AFW system provides sufficient capability for decay heat removal. Item 2 above is satisfied by demonstrating that subcooling margin is maintained throughout the entire event and inventory remains in the SGs. Item 3 is satisfied by ensuring that the PSVs do not pass water by showing that the pressurizer does not become water solid.

Consistent with the analyses performed in UFSAR Section 10.4.9A, the FLB AFW applicability analysis performed for the EPU is a best estimate analysis with some parameters biased in the conservative direction. Thus, nominal initial parameters were considered. Cases with and without offsite power were considered. Table SRXB-61-3 illustrates the key analysis parameters for cases with and without offsite power available.

L-2011-532 Attachment 1 Page 42 of 62 Table SRXB-61-3 Key Analysis Parameters for Feedline Break (FLB)

Parameter FLB With AC Power FLB with LOOP Core Power 100% + uncertainty 100% + uncertainty (3030 MWt) (3030 MWt)

Thermal Design Flow Thermal Design Flow Loop Flow Rate (187500 GPM) (187500 GPM)

High & Low nominal High & Low nominal Vessel Inlet Temperature (551OF & 535 0 F) (551OF & 535 0 F)

Initial Pressure Nominal (2250 psia) Nominal (2250 psia)

Initial Water Level Nominal (63% NRS) Nominal (63% NRS)

Pressurizer Charging/Letdown Available Unavailable Heater Available Unavailable PORV Available Available Spray Available Available Nominal Nominal Initial Water LevelNoiaNmnl (65% span) (65% span)

Steam Tube Conditions & Fouled, Fouled, Generator SGTP 10% 10%

ADV Unavailable Unavailable SBCS Available- Unavailable Pumps 1 motor driven AFW pump 1 motor driven AFW pump Flowrate

• 275 GPM 275 GPM-Auxiliary Feedwater Delay ** 420 seconds 420 seconds Nominal - harsh environment Nominal - harsh environment Trip Setpoint (4.0% NRS) (4.0% NRS)

Loss of Offsite Power Not assumed Assumed on reactor trip High Pressurizer 2460 psia 2460 psia Reactor Trip Pressure Setpoint Low Steam PressurePrsue546 psia 546 psia Reactivity II13BOC w/ max. value of 13 BOC w/ max. value of 13

• Flowrate listed is for a degraded AFW pump.

• • • AFW delay accounts for diesel generator startup and electrical load sequencing.

A longer delay puts greater strain on the AFW system and is therefore assumed for both cases.

The FLB analysis performed in accordance with UFSAR Section 10.4.9A shows that there is greater than 7800 Ibm in either generator at the end of the transient. The pressurizer water volume remains below 1519 ft3, and as such, the pressurizer does not reach a water solid condition. Lastly, subcooling margin is maintained in all cases throughout the entire event.

Although the pressurizer empties during the high Tavg case with AC power, the analysis shows that there is no voiding in the upper head or hot legs and subcooling margin is maintained throughout the entire event. Table SRXB-61-4 provides analysis results.

L-2011-532 Attachment 1 Page 43 of 62 The sequence of events for the two limiting FLB cases are presented in Tables SRXB-61-5 and SRXB-61-6. Plots of the two limiting cases are presented in Figures SRXB-61-6 through SRXB-61-13. High Tavg with AC power available is limiting with respect to minimum unfaulted SG mass and low Tavg without AC power available is limiting with respect to maximum pressurizer liquid volume. Both analyses maintain more than 45 0 F of subcooling during the entire event.

Consistent with the current design basis, this analysis has been run for 30 minutes with no operator action.

Table SRXB-61-4 Feedline Break (FLB) Results AFW AFW Maximum Minimum Case AC Tavg Flow Delay Pressurizer Unfaulted Power? (OF) Rate Time Volume SG Mass (GPM) (sec) .(ft 3) (Ibm)

SAC-hi Yes 578.5 275 420 1429 7864 AC-Io Yes 563.0 275 420 1422 8500 LOOP-hi No 578.5 275 420 1336 15940 LOOP-Io No 563.0 275 420 1444 15941 Table SRXB-61-5 Sequence of Events for Feedline Break High Tavg Case with AC Power Time Event Setpoint-IValue (sec)

Instantaneous complete loss of feedwater to the affected SG; 20.00 FLB occurs in the main feedwater (MFW) line between the 0.375 ft 2

_Loop 1 SG and the last check valve 54.73 High pressurizer pressure setpoint reached 2460 psia 55.13 Reactor trip 0.40 second delay 55.87 Control element assembly (CEA) release 0.74 second delay 57.13 Turbine trip 2.0 seconds delay 62.28 Unaffected SG MFW isolation valve (MFIV) closes ---

185.83 Safety injection actuation system (SIAS) generated on low 1638 psia pressurizer pressure 246.15 Loop 2 SG level reaches AFAS setpoint 4.0% NRS 252.50 Minimum pressurizer volume* 0 ftW 296.01 Loop 2 SG reaches main steam isolation setpoint 487 psia 302.76 Main steam isolation valves (MSIVs) completely closed ---

377.50 Loop 1 SG dryout < 500 Ibm 665.00 Loop 2 SG minimum inventory 7864 Ibm 666.15 AFW reaches Loop 2 SG 420 sec 1820.00 Maximum pressurizer volume 1429 ftW 1820.01 Operator takes actions to commence plant cooldown ---

(1800 sec. after transient initiation)

• Although the pressurizer empties during the transient, the analysis shows that there is no voiding in the upper head or hot legs and subcooling margin is maintained.

L-2011-532 Attachment 1 Page 44 of 62 Table SRXB-61-6 Sequence of Events for Feedline Break Low Tavg Case with LOOP Time Event Setpoint / Value (sec)

Instantaneous complete loss of feedwater to the affected SG; 20.00 FLB occurs in the MFW line between the Loop 1 SG and the 0.375 ft 2 last check valve 55.24 High pressurizer pressure setpoint reached 2460 psia 55.64 Reactor trip 0.40 second delay 56.38 CEA release 0.74 second delay 57.64 Turbine trip 2.0 seconds delay 62.80 Unaffected SG MFIV closes ---

57.65 Loss of offsite power ---

208.69 Loop 2 SG reaches main steam isolation setpoint 487 psia 215.44 MSIVs completely closed ---

275.00 Minimum pressurizer volume 553 ftW 290.00 Loop 1 SG dryout < 500 Ibm 904.86 Loop 2 SG level reaches AFAS setpoint 4.0% NRS 1324.86 AFW reaches Loop 2 SG 420 sec 1325.00 Loop 2 SG minimum inventory 15941 Ibm 1820.00 Maximum pressurizer volume 1444 ft" 1820.01 Operator takes actions to commence plant cooldown ---

(1800-sec. after transient initiation)

L-2011-532 Attachment 1 Page 45 of 62 Figure SRXB-61-6 Feedline with AC, High T.,g Steam Generator Inventory vs. Time Foul ted

. . .Unfoul ted I AnnrV) .

120000-100000-CL) 80000-60000" E 4000 C3 4

U")

20000- -

t -- ,-------------f I -

0 500 1000 1500 2000 Time (s)-

Figure SRXB-61-7 Feedline with AC, High Tavg Pressurizer Pressure vs. Time LO W

V)

(n 0)

M U) 0 500 1000 1500 2000 Time (s)

L-2011-532 Attachment 1 Page 46 of 62 Figure SRXB-61-8 Feedline with AC, High Tavg Pressurizer Volume vs. Time E

0' U*)

Figure SRXB-61-9 Feedline with AC, High Tavg Core Exit Subcooling Margin vs. Time

-- Foul ted

. . .Unfoul ted C)"

0 U)

C/')

0 1000 1500 1500 2000 Time (s)

L-2011-532 Attachment 1 Page 47 of 62 Figure SRXB-61-10 Feedline with Loss of Offsite Power, Low Tavg Steam Generator Inventory vs. Time

-- Faulted UnfutI F. ted I AInnnf 120000" 100000" 80000-E0 0

60000-C/')

40000" 20000-I 0 500 1000 1500 2000 Time (s)

Figure SRXB-61-11 Feedline with Loss of Offsite Power, Low Tavg Pressurizer Pressure vs. Time a

U)

U)

U) 0)

0)

U)

U) 0)

a-1000 2000 Time (s)

. L-2011-532 Attachment 1 Page 48 of 62 Figure SRXB-61-12 Feedline with Loss of Offsite Power, Low Tavg Pressurizer Volume vs. Time Z3 0)

M~

(n U) a)-

0 500 1000 1500 2000 Time (s)

Figure SRXB-61-13 Feedline with Loss of Offsite Power, Low Tavg Core Exit Subcooling Margin vs. Time Foul ted

. . .Unfoulted 90 80

• 70 0

~0 cn60-0 500 1000 1500 2000 Time (s)

L-2011-532 Attachment 1 Page 49 of 62 SRXB-62 (RAI 2.8.5.2.4-1)

Page 2.8.5.2.4-7 specifies that the break sizes considered in the RCS over-pressurization analyses are 0.21 ft 2 - 0.375 ft 2 and 0.15 ft2 - 0.20 ft2 for large and small feedwater line break (FLB), respectively.

Discuss rationale for classification of the FLB into large and small breaks, and discuss the basis for selecting the above ranges of break sizes for the small and large FLBs. Explain why the upper break size is limited to 0.375 ft2 .

Response

The largest break possible is a double ended rupture (DER) of the feedwater pipe. The largest analysis break size for the steam generators (SGs) is assumed to be 0.375 ft2 . This is an acceptable assumption because the analysis of record results show that as the break size increases beyond 0.300 ft2 , the event becomes more benign and therefore, analyzing breaks larger than 0.375 ft2 would not produce more limiting results. A break size range of 0.10 ft 2 to 0.375 ft 2 is analyzed in the EPU analysis for this event. The EPU analysis also shows that break sizes close to 0.375 ft 2 are less limiting than the limiting case presented in the LAR (0.21 ft2). The range of break sizes is broken down into two categories, small breaks and large breaks, which are determined based on probability of occurrence. A small break (0.10 ft2 to < 0.20 ft 2) has a low probability of occurring while a large break (> 0.20ft2 to 0.375 ft 2) has an even lower probability of occurring. This classification and range of break sizes is consistent with the current design basis in the Updated Final Safety Analysis-Report (UFSAR) Section 15.2.8. The reactor coolant system (RCS) pressure acceptance criterion for low probability feedwater line breaks, defined as any break with offsite power available, break sizes < 0.20 ft2 with failure of the fast bus transfer (FFBT), or break sizes > 0.20 ft2 without FFBT, is that the pressure must remain less than 110%

of the design pressure. The RCS pressure acceptance criterion for very low probability feedwater line breaks, which are defined as any break with the loss of offsite power or breaks greater than 0.20 ft2 with FFBT, is that the pressure must remain less than 120% of the design pressure.

SRXB-63 (RAI 2.8.5.3.2-1)

Page 2.8.5.3.2-5 indicates that "coolable core geometry is ensured by showing that the peak cladding temperature and maximum oxidation level for the hot spot are below 23750 F and 16.0 percent by weight, respectively."

Discuss the technical basis for the above discussed acceptance criteria and address acceptability of the bases used for ensuring "coolable core geometry" during a locked rotor event.

Response

The locked rotor peak cladding temperature (PCT) calculation confirms that the coolable core geometry is ensured during the locked rotor accident, when the hot spot PCT remains below 2375 0 F and the local oxidation remains below 16%. Both acceptance criteria and the technical bases are discussed in the safety evaluation report enclosed in WCAP-12610-P-A &

CENPD-404-P-A Addendum 1-A, "Optimized ZirloTM',, July 2006 (Accession No. ML080390451).

WCAP-1 261 0-P-A & CENPD-404-P-A Addendum 1-A specifies a maximum cladding oxidation limit of 17%. However, the locked rotor event has historically been analyzed to the more conservative 16% maximum cladding oxidation limit. As such, 16% maximum oxidation level limit was used for this analysis.

L-2011-532 Attachment 1 Page 50 of 62 SRXB-64 (RAI 2.8.5.4.1-1)

Table 2.8.5.4.1-2 indicates that the peak centerline temperature is limited to 4717°F for the analysis of the uncontrolled CEA withdrawal from a subcritical condition.

Discuss the basis for the above temperature limit.

Response

The melting temperature value is calculated using the equation from Reference SRXB-64-1, Section 2.2.1, for predicting the melting point of U0 2 - Gd 20 3 solutions. This is an NRC approved document for use in license applications.

[ ]a,c The starting temperature [ ]a,c represents the melting temperature of U0 2 at zero burnup. A conservative melting temperature [ ]a,c is assumed for this event. The same burnup reduction would apply to the gadolinia doped fuel rods. Therefore, the starting temperature is reduced [ ]a,c and with the maximum gadolinia content of 8 w/o, the equation becomes:

[ ]a,c References SRXB-64-1 CENPD-275-P-SUPP 1-P-A (CENPD-275-NP-Supplement 1-NP-A), "C-E Methodology for PWR Core Designs Containing Gadolinia-Urania Burnable Absorbers."

SRXB-65 (RAI 2.8.5.4.2-1)

Page 2.8.5.4.2-5 indicates that ANC documented in WCAP-1 0965-P-A is used to calculate the peak linear-heat rate based on the nuclear-power and temperature, and core flow from RETRAN, which is documented in WCAP-14882-P-A. In INSERT 9 of the proposed TS (Attachment 3 to Licensing Report), WCAP-14882-P-A is added to TS 6.9.1.11.b.

Explain why WCAP-10965-P-A is not added to the referred TS.

Response

WCAP-1 0965-P-A, ANC: A Westinghouse Advanced Nodal Computer Code, Liu Y. S., et al.,

September 1986, does not appear in the referred Technical Specification because the ANC reference is covered under WCAP-1 1596-P-A, Qualification of the PHOENIX-P/ANC Nuclear Design System for Pressurized Water Reactor Cores, June 1988 ,and this reference appears as Reference 1 in Attachment 3 to the licensing report. Since WCAP-1 0965-P-A is a referenced portion of WCAP-1 1596-P-A, the more appropriate ANC reference for clarity is WCAP-1 1596-P-A.

The following sections reference WCAP-1 0965-P-A and have been superseded by WCAP-1 1596-P-A:

• Section 2.8.2, Reference 3,

• Section 2.8.5, Reference 10,

• Section 2.8.5.1.2, Reference 6, and

• Section 2.8.5.4.2, Reference 3.

L-2011-532 Attachment 1 Page 51 of 62 SRXB-66 (RAI 2.8.5.4.2.1-2)

Tables 2.8.5.4.2-2 and 2.8.5.4.2-3 show the results of an uncontrolled control rod withdrawal at power for the RCS over-pressurization and DNB cases. The results of the main steam system (MSS) over-pressurization cases are missing.

Explain why the results of MSS over-pressurization are not discussed for this event.

Response

The uncontrolled control rod assembly withdrawal at power main steam (MS) system over-pressurization results are bounded by the loss of condenser vacuum (LOCV) event in EPU LAR Attachment 5, Section 2.8.5.2.1, due to the more significant reduction in heat removal capability of the steam generators (SGs). The uncontrolled control rod assembly withdrawal at power event assumes the secondary side operates normally with the turbine still relieving steam flow and pressure prior to the reactor trip. The LOCV event combines a loss of normal feedwater with a turbine trip which results in a total loss of secondary heat sink with the reactor still operating at full power, causing a greater challenge to secondary overpressure. Therefore, the MS system over-pressurization results have not been discussed.

For completeness, the results of the uncontrolled control rod assembly withdrawal at power MS system over-pressurization are presented in Table SRXB-66-1 below. Note that the 100% power, maximum feedback, 2 pcm/sec case yields the most limiting MS system over-pressurization results for all power levels for the uncontrolled control rod assembly withdrawal at power event.

Per EPU LAR Attachment 5, Table 2.8.5.2.1-3, the limiting LOCV MS system over-pressurization results are 1093.97 psia.

Table SRXB-66-1 Uncontrolled Control Rod Assembly Withdrawal at Power Event Limiting Main Steam System Over-Pressurization Results Limiting Analysis Analysis Case Value Limit 100% power, Maximum secondary 1090.0 1100.0 maximum feedback, pressure (psia) 2 pcm/sec SRXB-67 (RAI 2.8.5.4.3-1)

Page 2.8.5.4.3-4 states the "peak RCS pressure and peak steam generator pressure conditions are not challenged (non-limiting) during the CEA mis-operation event.

Explain why the RCS and SG over-pressurization cases for the CEA mis-operation event are not the limiting cases.

Response

In the phrase "peak reactor coolant system (RCS) pressure and peak steam generator (SG) pressure conditions are not challenged (non-limiting) during the control element assembly (CEA) mis-operation event," the words "non-limiting" refer to the CEA misoperation event not being the limiting RCS or SG overpressure event. The CEA misoperation event results in an overall depressurization of the system and utilizes the thermal margin/low pressure trip if a lower temperature/pressure equilibrium cannot be reached. A result of this transient response is that CEA misoperation does not challenge overpressure-stress limits and is only analyzed for a departure from nucleate boiling (DNB) response. The loss of condenser vacuum (LOCV)

L-2011-532 Attachment 1 Page 52 of 62 analyses result in a rapid heatup due to the loss of secondary load and will trip on high pressurizer pressure. LOCV is the limiting Condition II RCS and SG overpressure analysis.

Therefore, the CEA misoperation event is bounded by the more adverse LOCV event for overpressure described in EPU LAR Attachment 5, Section 2.8.5.2.1 and was not analyzed specifically for the RCS and SG over-pressurization criteria.

SRXB-68 (RAI 2.8.5.4.3-2)

Page 2.8.5.4.3-4 indicates that the transient conditions calculated for a CEA drop event are analyzed with nuclear models to obtain a hot channel factor.

Discuss the nuclear models used for the analysis and address acceptability of the models.

Response

Transient conditions for the control element assembly (CEA) misoperation event, such as the primary system conditions and reactor power, are calculated using the Westinghouse RETRAN-02W computer code (Reference SRXB-68-1). These transient conditions are then analyzed with the Westinghouse VIPRE-W computer code (Reference SRXB-68-2) to determine the hot channel factor at the departure from nucleate boiling (DNB) specified acceptable fuel design limit (SADFL). The VIPRE-W calculated hot channel factor is then compared against the cycle-specific, dropped-rod, hot channel factor, calculated using the ANC computer code, to verify that the transient meets safety analysis limits. ANC is described and approved in Reference SRXB-68-3. These codes have been previously approved and used for this application.

References:

SRXB-68-1 WCAP-1 4882-P-A (Proprietary) and WCAP-1 5234-A (Non-Proprietary);

RETRAN-02-Modeling and Qualification for Westinghouse Pressurized Water Reactor Non-LOCA Safety Analyses, April 1999.

SRXB-68-2 WCAP-14565-P-A (Proprietary) and WCAP-15306-NP-A (Non-Proprietary),

VIPRE-01 Modeling and Qualification for Pressurized Water Reactor Non-LOCA Thermal-Hydraulic Safety Analysis, October 1999.

SRXB-68-3 WCAP-1 1596-P-A (Proprietary), Qualification of the Phoenix-P/ANC Nuclear Design System for Pressurized Water Reactor Cores, June 1988.

L-2011-532 Attachment 1 Page 53 of 62 SRXB-69 (RAI 2.8.5.4.5)

For each of the boron dilution cases, please provide a sequence of events table, identifying the alarm or trip that is actuated, indicating the time at which it occurs, and showing that there is adequate time available, for operator actions, beginning at the time of the alarm or trip.

Response

The sequence of events for each of the boron dilution event cases is given below.

Time from Time Time Alarm Until Tmet A Alarm or Loss of Event Description Event Alarm or Trip Trip Shutdown Begins that Occurs Occurs Margin (minutes) (minutes) (SDM)

(minutes)

High Mode 1 0.0 Pressurizer 5.0* 89.1 Pressure (HPP)

High Rate of Mode 2 0.0 Change of 100.3 Power Mode 3 Boron Dilution (Results-for the limiting case, 0.0 51.69 18.T4 3 charging pumps operating) Alarm (BOA)

Mode 4 (1 reactor coolant pump operating) 0.0 BDA 51.02- 18.92 (Results for the limiting case, 3 charging pumps operating)

Mode 4 on shutdown cooling (Results for the limiting case, 0.0 BDA > 30*** 15.25 3 charging pumps operating)

Mode 5 (water level to hot leg centerline) 0.0 BDA > 30*** 15.25 (Results for the limiting case, 3 charging pumps operating)

Mode 6 ARO (water level to hot leg centerline) 0.0 BDA > 30*** 30.25 (Results for the limiting case, 3 charging pumps operating)

Actual value -2 minutes, however the time was rounded up to 5.0 minutes for added conservatism in the available operator action time calculation.

If a boron dilution event were to occur during Mode 2, the alarm would sound almost instantaneously. Thus, the time the alarm sounds is set to 0.0 minutes.

Initial boron concentrations in combination with critical boron concentration, as specified in LR Tables 2.8.5.4.5-3 through 5, gives the operators exactly enough time to mitigate a boron dilution event (15.25 minutes for Modes 4 and 5 and 30.25 minutes for Modes 6).

The time at which the alarm occurs is different for each case depending on the initial boron concentration. The time to alarm is greater if less than 3 charging pumps are in operation.

L-2011-532 Attachment 1 Page 54 of 62 SRXB-70 (RAI 2.8.5.5-1)

Assumption 5 on page 2.8.5.5-4 states that to maximize pressurizer mixture volume the initial pressurizer level is conservatively set to 60 percent, based on the nominal level minus the level uncertainty.

Specify the values of the nominal pressurizer water level and associated measurement uncertainty. Explain why the maximum pressurizer level, based on the upper range of the pressurizer level in TS 3/4.4.3 plus measurement uncertainty, would not result in a maximum pressurizer mixing volume during the RCS inventory increase events.

Response

Nominal pressurizer water level is 63% with a +/- 3% uncertainty (i.e., 60% to 66%). The nominal level minus uncertainty is used to delay the time to the pressurizer high level alarm (PHLA) setpoint, and thus maximize the charging flow injected priorto operator actions. The operators are alerted to a reactor coolant system (RCS) inventory increase event by either a high pressurizer pressure trip (HPPT) or by the "safety grade" PHLA. Twenty (20) minutes after either HPPT or the PHLA, it is assumed that the operators mitigate the event by reducing/stopping charging flow and/or restoring letdown flow. If the upper range of the pressurizer level Technical Specification (68%) with added uncertainty was used, the PHLA would actuate at event initiation and the same operator action (and associated action time) would occur, resulting in no change in maximum pressurizer level. An early PHLA would change the timing of the PHLA, but will not result in a worse maximum pressurizer level since, in either case, the operator action would occur within 20 minutes from the actuation of the PHLA given the same charging flow injection.

Analysis of the RCS inventory increase event performed using nominal pressurizer level minus uncertainty is-acceptable and conservative.

SRXB-71 (RAI -2.8.5.5-2)_

Assumption 12 on page 2.8.5.5-4 states that operator action to mitigate the CVCS malfunction event by reducing charging flow and/or restoring letdown flow is assumed 20 minutes after either a pressurizer pressure trip, or the high level alarm (PLHA) occurs.

Discuss the basis for use of the operator action time of 20 minutes, and describe a plant specific program that is used to assure that operators can complete the action credited in the analysis within the required action times.

Response

The response is being provided in a separate submittal.

SRXB-72 (RAI 2.8.5.6.1-1)

Page 2.8.5.6.1-4 indicates that to minimize the DNBRs during an accidental depressurization event the analysis assumes a conservative MTC of 0 pcm/°F at hot full power conditions.

Explain why use of the MTC of 0 pcm/°F is conservative, resulting in a minimum DNBR.

Response

The accidental depressurization is a very quick transient which is analyzed for minimum departure from nucleate boiling ratio (DNBR). The core nuclear parameters are chosen to minimize the resulting DNBR. To calculate a limiting minimum DNBR, minimum reactivity feedback is used and a least negative moderator temperature coefficient (MTC) is typically

L-2011-532 Attachment 1 Page 55 of 62 chosen. The least negative MTC is the typical value modeled because departure from nucleate boiling (DNB) events usually result in a temperature heatup. This depressurization transient results in a slight temperature decrease (about 1OF). Since the event is a rapid depressurization and pressure is the driving force for the transient, utilizing a negative MTC as opposed to a zero MTC will have a negligible adverse impact on the minimum DNB results. The depressurization analysis results show a 17.9% margin to the minimum DNB limit. When taking into account the effect of a 1OF cooldown, the margin to DNB decreases to 17.7%, which is why the MTC is said to have a negligible impact on results for a depressurization analysis.

SRXB-73 (RAI 2.8.5.6.1-2)

The titles for Figure 2.8.5.6.1-1 and Figure 2.8.5.6.1-2 are nuclear power and pressurizer pressure vs. time, respectively, while the respective plots show the pressurizer pressure and vessel average temperature vs. time.

Clarify the inconsistencies and provide correct figures for review.

Response

In EPU LAR Attachment 5, Figure 2.8.5.6.1-1 was inadvertently omitted from the document, but the correct title of Nuclear Power vs. Time was maintained. Figure 2.8.5.6.1-2 Pressurizer Pressure vs. Time was replaced with Figure 2.8.5.6.1-3 Vessel Average Temperature vs. Time.

However, the correct title of Pressurizer Pressure vs. Time was maintained. EPU LAR Figure 2.8.5.6.1-3 Vessel Average Temperature vs. Time was repeated as Figure 2.8.5.6.1-3, aligning the remaining Figures 2:8.5.6.1-3 through 2.8.5.6.1-5 with the correct title.

Figure 2.8.5.6.1-1 and Figure 2.8.5.6.1-2 are provided below. Figures 2.8.5.6.1-3 through 2.8.5.6.1-5 of Section 2.8.5.6.1 remain as presented and are correct.

L-2011-532 Attachment 1 Page 56 of 62 E

C0 25 30 35 05 10 Tli me (s)

Figure 2.8.5.6.1-1 RCS Depressurization Nuclear Power vs. Time

L-2011-532 Attachment 1 Page 57 of 62 V1)

CV, V)

Cl-0 5 10 15 20 25 30 35 Time (s)

Figure 2.8.5.6.1-2 RCS Depressurization Pressurizer Pressure vs. Time

L-2011-532 Attachment 1 Page 58 of 62 SRXB-74 (RAI 2.8.5.7-1)

Discuss systems, components, and procedures that are used to provide long-term shutdown capability following the anticipated transient without scram (ATWS).

Response

The limiting anticipated transient without scram (ATWS) events are the loss of load (LOL) and the loss of main feedwater (LOFW). For the St. Lucie Unit 2 class of plants, analyses demonstrated that a diverse scram system (DSS) with a 2450 psia trip setpoint and a 2-second response time would maintain the peak reactor coolant system (RCS) pressure to less than 3200 psig for the limiting anticipated operational occurrences (AOOs). The sequences of events for the LOL and LOFW ATWS analyses credit the following systems and components for short term mitigation of the ATWS pressurization up until and shortly after reactor trip on the high pressurizer pressure DSS setpoint of 2450 psia.

" The presence and activation of the DSS, diverse turbine trip (DTT) and diverse auxiliary feedwater actuation system (DAFAS);

" Steam dump and bypass control system;

• Auxiliary feedwater (AFW) system;

• Pressurizer spray activation;

• Main steam safety valves (MSSVs);

" Power operated relief valves (PORVs); and

• Pressurizer safety valves (PSVs).

The analyses performed to demonstrate DSS applicability are only run until the RCS pressurization turns around. As pressure falls due to reactor trip on DSS and minimal contributions from moderator temperature coefficient (MTC) effects, the PSVs and PORVs both close and the pressurizer sprays deactivate at the respective pressurizer pressure setpoints.

Following the reactor trip on the high pressure DSS setpoint of 2450 psia, the post-trip event progression is similar to one that would occur in any of the other overpressurization events.

As described in EPU LAR Attachment 5, Section 2.8.5.7.2.2, the DSS, DTT and DAFAS reduce the likelihood of a failure to shutdown the reactor following anticipated transients, and mitigate the consequences of anticipated transients followed by a failure of the reactor protective system (RPS). Following actuation of these systems to shutdown the reactor, cooldown and long-term cooling are maintained by normal system operation. Thus-, the systems and components used following reactor trip on DSS would be no different than those used in normal post-trip procedures.

The procedure used to ensure long term shutdown capability following a reactor trip is St. Lucie Unit 2 Emergency Operating Procedure 2-EOP-01 (EOP-1), Standard Post Trip Actions.

Main and auxiliary feedwater are used to feed the steam generators. Steam bypass control system dumping to the condensers (if available) or atmospheric dump valves to atmosphere are used to reduce RCS temperature and pressure. When shutdown cooling system (SDC) entry temperature and pressure conditions are achieved, the SDC is used to maintain long-term cooling.

L-2011-532 Attachment 1 Page 59 of 62 EOP-1, Standard Post Trip Actions, provides the actions to ensure the reactor is shutdown, and establishing a stable, safe plant conditions until transition to EOP-2, Reactor Trip Recovery.

EOP-2 provides the actions to establish the plant in Mode 3 Hot Standby and to minimize any releases to the environment, until transition to the General Operating Procedure (GOP) Reactor Plant Cooldown - Hot Standby to Cold Shutdown. This GOP provides the instructions for cooldown and depressurization of the reactor coolant system and transitions to the Normal Operating Procedure (NOP) for shutdown cooling.

SRXB-75 (RAI 2.8.5.7-2)

ATWS, or failure of control rod insertion, can be attributed to common mode failures such as (1) failure of the sensors that feed the reactor trip system, (2) failure of the reactor trip breakers to open and (3) a mechanical failure which prevents control insertion. The following questions pertain to the mechanical common mode failure.

Assess the credibility of an ATWS caused by mechanical common mode failure, and discuss the applicability of ATWS analyses in cases in which a mechanical common mode failure is assumed.

Response

Per Standard Review Plan (SRP) 15.8, an anticipated transient without scram (ATWS) is an anticipated operational occurrence (AOO) as defined in Appendix A to 10 CFR 50, followed by the failure-of the reactor trip portion of the protection system. Since protection systems must satisfy the single-failure criterion, multiple failures or a common mode failure must cause the assumed failure of the reactor trip. The probability of an AOO, in coincidence with multiple failures or a common mode failure, is-much lower than the- probability of any of the other events that are evaluated under SRP Chapter 15. Therefore, an ATWS event cannot be classified as either an AOO or a design-basis accident.

Under the requirements of 10 CFR 50.62 (ATWS Rule), St. Lucie Unit 2 has a diverse scram system (DSS) that assures diversity within the Reactor Protection -System (RPS) from the sensor output to the interruption of power to the control rods. St. Lucie Unit 2 also complies with the requirements for a diverse turbine trip (DTT) and a diverse auxiliary feedwater actuation system (DAFAS).

Thus, St. Lucie Unit 2 complies with the failure modes consistent with the ATWS rule and has installed systems and equipment, which provide reasonable assurance that unacceptable plant conditions do not occur in the event of an ATWS.

The evaluation transmitted via FPL letter L-2011-273 R. L. Anderson (FPL) to US Nuclear Regulatory Commission, "Information Regarding Anticipated Transient Without Scram (ATWS)

Provided In Support of the Extended Power Uprate License Amendment Request," dated July 22, 2011 (Accession No. ML11207A455) discusses the applicability of the DSS setpoints for EPU and demonstrates that, at EPU conditions with the DSS installed, there is adequate protection to prevent RCS pressurization to 3200 psig, which is the ASME Service Level C limit applicable to ATWS events.

L-2011-532 Attachment 1 Page 60 of 62 SRXB-76 (RAI 2.8.7.1-1)

Table 2.8.7.1 -1 indicates in the last column that the maximum allowable reactor vessel pressurization to avoid core uncover is 3 psig during a loss of RHR at mid-loop conditions.

Provide the basis for use of the reactor vessel pressurization limit of 3 psig.

Response

The reactor coolant system (RCS) hot legs must remain adequately vented during mid-loop operations to avoid pressurizing the reactor vessel upper plenum during core boiling if the cold leg is open to atmosphere. Under these conditions, pressurizing the vessel to greater than 3.0 psig could result in loss of coolant inventory and subsequent core uncovery. The 3.0 psig value used in the current evaluation is based on a calculated value from the historical supporting Combustion Engineering (CE) Owners Group (CEOG) evaluation, performed on a generic basis.

The generic analysis is applicable to CE plants and a specific value is provided for St. Lucie Unit 2. The value represents the pressure drop necessary to depress the water level to the top of the active core to vent out a postulated vent path of an open RCS. For St. Lucie Unit 2 plant configuration, this represents the elevation head between the top of the active core and the top of the cold leg.

SRXB-77 (RAI 2.8.7.2-1)

Table 2.8.7.2-2 includes the results of the natural circulation cooldown (NCC) analysis using the CENTS based on cooldown rates of 30°Flhr and_50°F/hr.

Provide-the following information in support of the results in Table 2.8.7.2-2

1. a discussion addressing acceptability of use of CENTS for the NCC analysis, and justifying adequacy of any changes to the NRC-approved version of CENTS

2. a discussion to show acceptability of the assumptions used and worst single failure considered in the NCC analysis

3. a discussion of the results of the NCC analysis to show that the predicted thermal-hydraulic response-is within the range approved by the NRC for use of the CENTS code, and there is no unexplainable thermal-hydraulic phenomena for parameters

4. justification for use of the decay heat rates based on ANI/ANS-5.1-1979

5. a derivation of the required CST water volume for the NCC analysis to show that the required CST water volume is within the TS limits

6. a discussion of compliance with the branch positions F and G in BTP RSB 5-4 (SRP, Revision 3).

Response

1. The CENTS code is not used in the current licensing basis (CLB) natural circulation cooldown (NCC) analysis, but is an approved code that is acceptable for referencing in licensing applications for Combustion Engineering (CE) design pressurized water reactors (PWRs). There are no changes to the CENTS code as used in the St. Lucie Unit 2 analysis. The only limitation of the CENTS code as applied in this analysis is related to the bounds of the fluid property tables. The temperature and pressure conditions considered in the NCC analysis are within the bounds of the CENTS code; therefore it is appropriate to use CENTS for the NCC analysis.

L-2011-532 Attachment 1 Page 61 of 62

2. The plant conditions and assumptions used in the NCC analysis are listed below.

• Plant power is initially at 100.5% of rated. power to account for indicated power uncertainty.

• 1979 ANS 5.1 Standard Decay Heat Curve including long term actinides is used.

0 One charging pump is operating following the plant trip.

• Letdown is disabled.

• Main feedwater is disabled.

• Main steam safety valves (MSSVs) provide the initial heat removal path.

• Safety injection system (SIS) is not used.

• RCS heat losses to containment are set to zero.

• Reactor vessel upper head heat losses to containment are set to zero.

• Main steam isolation valves (MSIVs) are closed.

• The auxiliary feedwater (AFW) flow is set to maintain steam generator level to match boiloff during the cooldown.

As required, charging -is controlled to maintain pressurizer level within acceptable range.

The most -limiting single failure for the NCC analysis is a loss of one direct current (DC) emergency power train. A loss of one DC emergency train would prevent alternating current (AC) from one-emergency diesel generator (EDG) from being transferred to the onsite electrical system. The single failure disables one train of components associated with the atmospheric dump valves (ADVs), Chemical and Volume Control System (CVCS), AFW system, and shutdown cooling (SDC) system. Only two of the four DC powered ADVs (one per steam generator) are used in the NCC analysis. This scenario demonstrates that the plant can be cooled down to SDC entry conditions using only safety grade equipment and maintaining pressure control (holding a 20 degree subcooling margin in the reactor vessel upper head (RVUH)) for a loss of offsite power (LOOP) event with the most limiting single failure.

3. The temperature and pressure conditions considered in the NCC analysis are within the bounds of the CENTS code. The reactor coolant system (RCS) is kept above the saturation pressure corresponding to the RVUH temperature; therefore, no two-phase conditions are present during the NCC analysis and no unexpected thermal-hydraulic phenomena are predicted.

4. The decay heat table in the St. Lucie Unit 2 CENTS code is based on the 1979 ANS 5.1 Standard Decay Heat Curve including 2a uncertainty and accounts for the affects of neutron capture and long term actinides. The decay heat curve bounds fuel designs with up to: 5 weight percent fuel enrichment; fuel burnups to 73,000 MWd/MTU; and operating cycles up to 24 months in duration. Therefore, the basis for the decay heat curve used in the NCC analysis bounds the fuel design and operating cycle lengths anticipated as part of the St. Lucie Unit 2 EPU design.

5. The required condensate storage tank (CST) inventory for NCC is calculated as 178,200 gallons using the CENTS code and is based on the feedwater pump flow during cooldown. This volume is within the TS requirement of 307,000 gallons.

L-2011-532 Attachment 1 Page 62 of 62

6. The NCC analysis assumes that the operators do not depressurize the RVUH below a 20 degree subcooling margin (to preclude drawing a void in the upper head). The analysis demonstrates that the plant can be cooled to shutdown cooling entry conditions using only safety grade equipment.

L-2011-532 Attachment 3 ATTACHMENT 3 Response to NRC Reactor Systems Branch and Nuclear Performance Branch Request for Additional Information Regarding Extended Power Uprate License Amendment Request Westinghouse Electric Company Affidavit for Withhold -Proprietary Information from Public Disclosure This coversheet plus 7 pages

Westinghouse Electric Company Nuclear Services S)Westinghouse 1000 Westinghouse Drive Cranberry Township, Pennsylvania 16066 USA U.S. NLuclear Regulatory Commission Direct tel: (412) 374-4643 DocuIiient Control Desk Direct fax: (724) 720-0754 11555 Rockville Pike e-mail: greshaja @ westinghouse.con Rockville. MD 20852 Proj letter: FPI-1 1-297 CAW-1 1-33 15 November 18, 2011 APPLICATION FOR WITHHOLDING PROPRIETARY INFORMATION FROM PUBLIC DISCLOSURE

Subject:

"Response to Requests for Additional Information (RAI SRXB-64) for the St. Lucie Unit 2 Extended Power Uprate License Amendment Request" (Proprietary)

References:

1. NRC E-Mail, T. Orf(NRC) to C. Wasik (FPL), "St. Lucie 2 EPU - Draft RAIs Reactor Systems Branch and Nuclear Performance Branch (SRXB and SNPB)," September 6, 2011, 12:19 PM.

The proprietary information for which withholding is being requested is that inclided in the response to the Request for Additional Information (RAI) designated as "SRXB-64" transmitted by Reference 1, and further identified in Affidavit CAW- 11-33 15 signed by the owner of the proprietary information, Westinghouse Electric Company LLC. The affidavit, which accompanies this letter, sets forth the basis on which the information may be withheld from public disclosure by the Commission and addresses with specificity the considerations listed in paragraph (b)(4) of 10 CFR Section 2.390 of the Commission's regulations.

Accordingly, this letter authorizes the utilization of the accompanlyillg affidavit by Florida Power and Light.

Correspondence with respect to the proprietary aspects of the application for withholding or the Westinghouse affidavit should reference this letter, CAW-1 1-3315, and should be addressed to J. A. Gresham, Manager, Regulatory Compliance, Westinghouse Electric Company LLC, Suite 428, 1000 Westinghouse Drive, Cranberry Township, Pennsylvania 16066.

Very truly yours, SJ. A. Gresham, Manager

ý Regulatory Compliance Enclosures

CAW- 11-33 15 AFFIDAVIT STATE OF CONNECTICUT:

30Ko'Z ack-'

"/

COUNTY OF HARTFORD:

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

C. M. Molnar, Senior Engineer Regulatory Compliance Sworn to and subscribed before me thIs Z__ay 2011 Subscricc-23 '&a'ibfP['V; a Notary Public, i and -_'o un of ,flprd and 't' of" Cnnnectrft. this / ,day f- , 20L2...

(J/

JOAN GRAY NO.otary Pub ic My Commission Expires January 31, 2012

2 CAW-1 1-3315 (1) I am Senior Engineer, Regulatory Compliance, in Nuclear Services, Westinghouse Electric Company LLC (Westinghouse), and as such, I have been specifically delegated the function of reviewing the proprietary information sought to be withheld from public disclosure in connection with nuclear power plant licensing and rule making proceedings, and am authorized to apply for its withholding on behalf of Westinghouse.

(2) 1 am making this Affidavit in conformance with the provisions of 10 CFR Section 2.390 of the Commission's regulations and in conjunction with the Westinghouse Application for Withholding Proprietary Information firom Public Disclosure accompanying this Affidavit.

(3) 1have personal knowledge of the criteria and procedures utilized by Westinghouse in designating information as a trade secret, privileged or as confidential commercial or financial information.

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

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

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

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

(a) The information reveals the distinguishing aspects of a process (or component, structure, tool, method, etc.) where prevention of its use by any of

3 CAW-1 1-33 15 Westinghouse's competitors without license I'rom Westinghouse constitutes a competitive economic advantage over other companies.

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

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

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

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

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

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

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

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

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

4 CAW-l 1-3315 (d) Each component of proprietary information pertinent to a particular competitive advantage is potentially as valuable as tile total competitive advantage. 1f competitors acquire components of proprietary information, any one component may be tile key to the entire puzzle, thereby depriving Westinghouse of a competitive advantage.

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

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

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

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

(v) The proprietary information sought to be withheld in this submittal is that which is appropriately marked in the response to Request for Additional Information (RAI) "SRXB-64", for submittal to the Commission, being transmitted by Florida Power and Light letter and Application for Withholding Proprietary Information from Public Disclosure, to the Document Control Desk. The RAI identified above is included in NRC E-Mail, T. Orf (NRC) to C. Wasik (FPL), "St. Lucie 2 EPU - Draft RAIs Reactor Systems Branch and Nuclear Performance Branch (SRXB and SNPB)," September 6, 2011, 12:19 PM. The proprietary information as submitted by Westinghouse is that which supports the St. Lucie Unit 2 Extended Power Uprate (EPU) License Amendment Request (LAR), and may be used only for that purpose.

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

5 CAW- 1-3315 (a) Support the St. Lucie Unit 2 EPU LAR by justifying the calcLIlated peak centerline temnperature for the subcritical uncontrolled CEA withdrawal event under ETU Conditions.

Further this information has substantial commercial value as follows:

(a) The information reveals aspects of Westinghouse analytical methodology that could facilitate competitors' future analyses.

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

The development of the technology described in part by the information is the resuLlt of applying the results of many years of experience in an intens~iv'e Westinghouse effort and the expenditure of a considerable sum of money.

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

Further the deponent sayeth not.

Proprietary Information Notice Transmitted herewith are proprietary and/or non-proprietary versions of documents furnished to the NRC in connection with requests for generic and/or plant-specific review and approval.

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

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