L-2012-085, Response to Request for Additional Information Identified During Audit of the Safety Analyses Calculations for the Extended Power Uprate License Amendment Request

Response to Request for Additional Information Identified During Audit of the Safety Analyses Calculations for the Extended Power Uprate License Amendment Request

ML12068A371
Person / Time
Site:	Saint Lucie
Issue date:	03/06/2012
From:	Richard Anderson Florida Power & Light Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
L-2012-085
Download: ML12068A371 (17)

Text

0Florida FPL Power & Light Company, 6501 S. Ocean Drive, Jensen Beach, FL 34957 March 6, 2012 L-2012-085 10 CFR 50.90 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Re: St. Lucie Plant Unit 1 Docket No. 50-335 Renewed Facility Operating License No. DPR-67 Response To Request For Additional Information Identified During Audit Of The Safety Analyses Calculations for the Extended Power Uprate License Amendment Request

References:

(1) R. L. Anderson (FPL) to U.S. Nuclear Regulatory Commission (L-2010-259), "License Amendment Request (LAR) for Extended Power Uprate," November 22, 2010, Accession No. ML103560419.

(2) NRC Reactor Systems Branch Audit Conducted at AREVA NP Inc. Facilities in Lynchburg, VA, January 30 and 31, 2012.

By letter L-2010-259 dated November 22, 2010 [Reference 1], Florida Power & Light Company (FPL) requested to amend Renewed Facility Operating License No. DPR-67 and revise the St. Lucie Unit 1 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).

During the course of the NRC audit conducted at the AREVA NP Inc. facilities in Lynchburg, VA on January 30 and 31, 2012 [Reference 2], the NRC staff requested additional information to support the review of the safety analyses used in the St. Lucie Unit 1 EPU LAR. Additional information related to five events was requested. The events included: feedwater line break (FWLB), inadvertent opening of a power operated relief valve (IOPORV), chemical and volume control system (CVCS) malfunction, loss of electrical load (LOEL)/Ioss of condenser vacuum (LOCV), and realistic large break loss of coolant accident (RLBLOCA).

/ AOAL an FPL Group company

L-2012-085 Page 2 of 2 The attachment to this letter provides the requested information and the FPL response for the FWLB event. The response to the requested information for the other four events is being provided in separate correspondence.

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

This submittal does not alter the significant hazards consideration or environmental assessment previously submitted by FPL letter L-2010-259 [Reference 1].

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

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 1, - C)I Very truly yours, Richard L. Anderso Site Vice President St. Lucie Plant Attachment cc: Mr. William Passetti, Florida Department of Health

L-2012-085 Attachment Page 1 of 15 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION IDENTIFIED DURING AUDIT OF THE SAFETY ANALYSES CALCULATIONS 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 Extended Power Uprate (EPU) License Amendment Request (LAR) for St. Lucie Unit 1 submitted to the NRC by FPL via letter L-2010-259 dated November 22, 2010, Accession Number ML103560419.

The NRC Reactor Systems Branch conducted an audit of the St. Lucie Unit 1 EPU safety analyses calculations at the AREVA NP Inc. (AREVA) facility in Lynchburg, VA on January 30 and 31, 2012. The NRC identified five events that require additional information. The events are:

• Feedwater line break (FWLB),

" Inadvertent opening of a power operated relief valve (IOPORV),

• Chemical and volume control system (CVCS) malfunction,

• Loss of electrical load (LOEL) / loss of condenser vacuum (LOCV), and

" Realistic large break loss of coolant accident (RLBLOCA).

The response to RAIs for IOPORV, CVCS malfunction, LOEL/LOCV and-RLBBLOCA events is being provided in separate correspondence. The response to FWLB event is provided below.

Feedwater Line Break (FWLB)

Submit a feedwaterline break (FWLB) heatup analysis. Provide one case with offsite power available and one case without offsite power available.

Response

1.0 Introduction The current licensing basis for St. Lucie Unit 1 does not include an analysis for the FWLB event as a heatup event. The evaluation and results presented below:

Demonstrate the adequacy of the auxiliary feedwater (AFW) system to remove post-trip decay heat and maintain reactor coolant system (RCS) subcooling margin until RCS heatup is terminated with the AFW heat removal capacity exceeding the decay heat; and Verify the steam generator (SG) low level reactor trip setpoint to be sufficiently conservative to perform the reactor protection function, after accounting for the uncertainties associated with the harsh environment that could be created by the break of a feedwater line inside containment.

1.1 Summary of Findings Key analysis inputs for this representative case are consistent with those that are typically limiting for Combustion Engineering (CE) plants with feedring-type SGs. These inputs include modeling the largest double-ended break possible for the St. Lucie Unit 1 SG model and minimum reactivity feedback parameters.

L-2012-085 Attachment Page 2 of 15 The evaluation demonstrates that a FWLB event under EPU conditions, with input assumptions typical of limiting analyzed cases, affords adequate margin to hot leg saturation. This information provides reasonable assurance that the consequences of a FWLB event do not present a safety concern for operation of St. Lucie Unit 1 at EPU conditions.

2.0 Event Description The FWLB incident is defined as a break in a feedwater pipe large enough to prevent the addition of sufficient feedwater to maintain shell-side fluid inventory in the SGs. If the break is postulated in a feedline between the check valve and the SG, fluid from the SG will be discharged through the break. (In contrast, if a break occurred upstream of the feedline check valve, the transient would progress as a loss of normal feedwater event.) Furthermore, because the AFW piping connects to the main feedline, a break between the check valve and the SG could preclude the subsequent addition of AFW to the affected SG. Depending upon the size of the break and the plant operating conditions at the time of the rupture, the break first causes a cooldown (by excessive energy discharge through the break), followed by a heatup of the RCS. Because the consequences of an RCS cooldown resulting from a FWLB are bounded by the cooldown consequences of a steam system piping failure, the FWLB event was analyzed with respect to RCS heatup effects.

As the subcooled feedwater flow to the SGs is reduced by a FWLB, the long-term capacity of the secondary system to remove heat from the RCS is diminished. The feedwater flow reduction can cause RCS temperatures to increase prior to reactor trip. -Additionally, fluid inventory of the faulted SG may be discharged through the break, which will reduce the heat sink volume available for decay heat removal following a reactor trip. The FWLB event is analyzed to demonstrate the ability of the AFW system to adequately remove long-term decay heat and prevent excessive heatup of the RCS.

In the analysis performed, the break was assumed to be located in a feedline between the check valve-and the SG. A break in this location results in the discharge of fluid from the associated SG.

The size of the break and the functionality of the main feedwater (MFW) control system are two important factors during a FWLB transient. Some breaks may be small enough that a properly functioning MFW control system will be able to completely make up for the resultant inventory loss. In contrast, larger feedline breaks can cause a sizeable blowdown (inventory loss) that prevents the MFW control system from being able to supply enough feedwater to maintain shel-side fluid inventory in the SGs. This then leads to a SG low level reactor trip and AFW actuation. Another important factor during a FWLB transient is the shell-side fluid inventory in the intact SG at the time of reactor trip. It is conservative to employ analysis assumptions that minimize this fluid inventory because it minimizes the heat removal capability of the SG, which in turn maximizes the RCS heatup. For this purpose, the analysis performed assumes that MFW is completely terminated (to both SGs) at the time the break occurs. Furthermore, the initial water level in the faulted SG is assumed at its highest level consistent with full-power conditions (to delay reactor trip on SG low level), while the initial water level in the intact SG is at its lowest (to minimize inventory available for long-term heat removal).

Early in the event, there is a rapid decrease in reactor coolant temperature as over-cooling temporarily occurs in the faulted SG. When the SG water level in the affected SG reaches the analysis-assumed conservative SG low level reactor protection system (RPS) setpoint, a reactor trip occurs. A turbine trip shortly after reactor trip causes a sudden reduction in steam flow and a further reduction in the heat removal capacity of the SG. The steam bypass control system (SBCS) was modeled in the offsite power available case to deplete the SGs of inventory slightly faster. With the reduced steam flow, the steam pressure in the intact SG rapidly increases to the

L-2012-085 Attachment Page 3 of 15 setpoint of the first (lowest setpoint) main steam safety valves (MSSVs), and remains there until the RCS heatup ceases, i.e., until the heat removal capability of the intact SG being fed AFW is sufficient to remove the decay heat generated in the core (also known as the time of event turnaround). During the heatup period after reactor trip, the pressurizer pressure increases to, and is maintained near, the pressurizer power operated relief valve (PORV) setpoint. At event turnaround, the RCS temperature and pressure, and the pressurizer water level begin to decrease again, and the heatup transient is over. Subsequently, the plant operators can follow the applicable emergency operating procedures (EOPs) to bring the plant to a stabilized condition.

The intent of the analysis was to maximize the potential for reaching saturated conditions in the RCS hot legs. Some of the key characteristics of the analysis are described below.

3.0 Analytical Methodology The FWLB transient is analyzed by employing the S-RELAP5 computer code. The code simulates the neutron kinetics, RCS, pressurizer, pressurizer PORVs and safety valves, pressurizer spray, SG, and MSSVs. The code computes pertinent plant variables including temperatures, pressures, and power level.

Normal reactor control systems are not required to function. The RPS functions to trip the reactor on the appropriate signal, while the engineered safeguards features actuation system (ESFAS),

primarily the auxiliary feedwater actuation signal (AFAS), is actuated to provide long-term decay heat removal capability via AFW. No single active failure will prevent-the RPS from functioning properly. A limiting single active failure in the AFW system was included to minimize the available AFW flow to. the intact SG.

Inputs-were modeled to maximize the potential for reaching saturated conditions in the hot and/or cold legs, as provided in Table 3-1 below.

The analysis of this event was performed with the reactor initially operating at the EPU rated thermal power plus uncertainty. This is bounding because the stored energy of the primary system is maximized at full power conditions, and therefore the disparity between the heat generated in the RCS and the heat removal capacity of the SGs is maximized.

The cases analyzed investigated the largest possible break size, i.e., 1.12 ft2, which is consistent with a break occurring at the SG nozzle. For smaller breaks, the MFW system would tend to result in MFW penetrating the intact SG, thus mitigating the loss of heat sink. The largest break size possible will result in the most MFW being diverted away from the intact SG, through the piping network to the break.

Cases were analyzed for both (a) offsite power available and (b) loss of offsite power (LOOP) following reactor trip. Reactor trip was assumed to occur on a faulted SG low level signal received when level reached 5% of the narrow range span (NRS). Additional available RPS trips include the high pressurizer pressure (HPP) and SG low pressure RPS trips. All RPS trips setpoints included allowance for harsh containment conditions and maximum signal processing time delays. Also, a maximum holding coil release time was assumed to conservatively delay the initiation of rod motion upon scram.

It was assumed that the flow from the motor-driven AFW pump supplying the faulted SG was lost through the break. The other motor-driven AFW pump (supplying the intact SG) is capable of supplying a minimum flow of 296 gpm following a 330-second delay. (This delay was assumed for both the offsite power available and LOOP cases.) No credit was taken for operator action to re-direct the other motor-driven AFW pump supplying the faulted SG to the intact SG. Since the AFW control logic would isolate the faulted SG, the turbine-driven AFW pump was assumed to be

L-2012-085 Attachment Page 4 of 15 the single active failure because that pump would otherwise feed the intact SG with a higher capacity than the single motor-driven pump. AFW flow was assumed to be at the maximum temperature of 100°F plus 4 0 F uncertainty. SG blowdown was assumed to be on for 30 minutes at 65 gpm.

Table 3-1 Analysis Parameters Parameter Bias Biased Value Comment Maximum core power increases the the mismatch RCsmand Initial reactor power Rated thermal power 3029.06 MWt betwee plus uncertainty (3020 MWt + 0.3%) between the RCS and intact SG. Decay heat is also maximized.

Initial core inlet Technical Specification 554 0 F Initial value does not tempeatureplus temperature (TS) uncertainty maximum (551 + 30 F) significantly affect results.

Initial pressurizer Low 2185 psia Initial value does not pressure (2225 - 40 unc.) significantly affect results.

Initial pressurizer High 68.6% (65.6 + 3 unc.) Initial value does not level significantly affect results.

Initial reactor coolant Decreases heat transfer flow rate TS minimum 375,000 gpm between the RCS and the intact SG.

Faulted: 70% High faulted SG level Faulted: high (65 + 5 unc.) delays reactor trip; low Intact: low Intact: 60% intact SG level limits heat (65 - 5 unc.) removal capability.

Decreases heat transfer SG tube plugging High 10% area between the RCS and the intact SG.

+ actnides Conservatively heat. high decay Decay heat Per methodology ANS 73 + actinides Moderator Moderator TS most-positive Increases core power temperature +2prior to trip.

coefficient (MTC) HFP limit Minimum setpoint delays Nominal = 20.5% reactor scram.

SG low level RPS trip Low Analysis value = 5 Value used of 20.5% has condition uncertainty) margin to the TS setpoint value of 35%.

Maximum instrumentation SG low level RPS trip High 0.9 s actuation delays reactor circuit delay trip.

Biased low because it 2320 psia uses same signal as High preSsurizer Low (2400 -80 psi harsh PORV. (Lower RCS pressure RPS trip condition uncertainty) pressure provides challenge to subcooling.)

High pressurizer Maximum instrumentation pressure RPS trip High 0.9 s actuation delays reactor delay I trip.

L-2012-085 Attachment Page 5 of 15 Table 3-1 (continued)

Analysis Parameters Parameter Bias Biased Value Comment SG Low pressure 400 psia Minimum setpoint delays SGLwpr r Low (600-200 psi for RPS trip harsh conditions) reactor trip.

Maximum instrumentation RPS trip circuit delay High 0.9 s actuation delays reactor trip.

Maximum holding coil Scram delay High 0.5 s release time delays reactor power reduction.

Main Steam Isolation 400 psia with 6.9 s 600-200=400 psia System (MSIS) SG low pressure valve stroke time (See SG low pressure above.)

5.0%

SG low level (19.0% - 14% Biased low setpoint Slow Low nominal less harsh delays AFW to the intact AFAS trip conditions SG.

uncertainty)

Diesel generator starting 330 s and sequence loading SG low level High (irrespective of delays included.

AFAS trip delay time availability of offsite Maximum time delays power) availability of AFW to the intact SG.

No credit was taken for re-296 gpm direction of flow from AFW flow rate Minimum (one motor driven motor driven AFW pump pump) associated with the faulted SG.

TS maximum 104°F Slightly reduces the heat AFW temperature plus uncertainty (100°F + 4°F unc. removal capability of the AFW.

MFWdeivey ndInstantaneously Conservative that maximizesassumption the MFW delivery and Conservative isolated at event termination initiation (both SGs). challenge to the AFW in the intact SG.

AFW isolation logic would divert all turbine driven pump flow to the intact SG. Turbine driven flow rates are much greater Loss of turbine- than motor driven, Single-failure driven AFW pump >600 gpm vs. 296 gpm.

Thus, a failure of the turbine driven pump is worse than a failure of the motor driven pump to the intact SG.

L-2012-085 Attachment Page 6 of 15 Table 3-1 (continued)

Analysis Parameters Parameter Bias Biased Value Comment The setpoint was biased High pressure safety Modeled to actuate low to prevent HPSI Injection pressue s y at 1520 psia injection (which would Injection (HPSI) Low (1600-80 psi for benefit subcooling). HPSI actuation pressure harsh conditions) did not actuate due to the high RCS pressures.

Charging would provide a Charging Not modeled Not modeled benefit to the subcooling margin by cooling the RCS.

Bank 2 tolerance is +2%,

Bank 1: however, for this analysis MSSV setpoints Nominal plus tolerance 1,000 psia + 3% the opening setpoint was Bank 2: determined using a 1,040 psia +3% conservatively large +3%

tolerance.

Reactor coolant 217MWttlf Maximum RCP heat pump (RCP) heat High toaor increases the heat load on generation 4 RCPs the intact SG.

Heat addition to the Pressurizer heaters N/A Not modeled pressurizer would benefit subcooling by raising the saturation temperature.

RCS pressure controlled by the PORVs during time period that challenges PORV setpoint Nominal less Open: 2320 psia subcooling. The setpoints euncertainty Reset: 2296 psia were biased low to minimize the pressure and, consequently, the saturation temperature.

153,000 valve Ibm/hr

+ 10%

per PORV capacity maintains POVcpctmanis valve+

10% pressure at the opening PORV flow rate Design valueDesignvaluesetpoint

+ 10% Analysis value: se during at theoening the heatup 168,300 Ibm/hr per period.

valve at 2400 psia

L-201.2-085 Attachment Page 7 of 15 Table 3-2 Reactor Trip Status Parameter Assumed Status Thermal margin/low pressure (TM/LP) Disabled High pressurizer pressure (HPP) Available Reactor trip on turbine trip Disabled Steam generator low level Available Low primary flow Disabled Steam generator low pressure Available Steam generator differential pressure ] Disabled Table 3-3 Equipment Status Equipment / System Assumed Status Rod position controller Manual Pressurizer heaters Disabled Pressurizer spray Available Pressurizer PORVs Available SG blowdown flow Available Steam dump and bypass valves Modeled (no LOOP case)

Steam atmospheric dump valves Not modeled (Manual)

Reactor coolant pumps Operating per Mode 1 Main feedwater Isolated at event initiation Auxiliary feedwater Available, consistent with single-failure assumptions Charging pumps Not modeled Letdown flow Not modeled Rod block system Disabled Turbine control valve Automatic Operational mode Mode 1, Full Power

L-2012-085 Attachment Page 8 of 15 The PORVs were activated at nominal pressure less uncertainty for the analysis herein. This was done because the RCS pressure is controlled by the PORV for a significant period in this transient. The pressure (and the figure of merit subcooling) would be higher during that period if the PORVs were disabled.

For the no-loss of offsite power (LOOP) case, it was assumed that the operator trips all four RCPs at 15 minutes after reactor trip in accordance with the EOPs, with expected SIAS on high containment pressure. For the LOOP case, the RCPs are assumed to trip at the time of turbine trip on reactor trip.

4.0 Summary of Results In this analysis, two scenarios were considered:

" Offsite power available (no LOOP), and

• Loss of offsite power (LOOP).

This evaluation demonstrates that a FWLB event, with input assumptions typical of the limiting analyzed case, affords adequate margin to hot leg saturation under EPU conditions. This information provides reasonable assurance that the consequences of a FWLB event do not present a safety concern for operation at EPU conditions.

The sequence of events and selected graphical results are provided below in Table 4-1, Table 4-2, and Figures 4-1 through-4-12. Table 4-3 provides a summary of the analysis.

Table 4-1 Sequence of Events for FWLB with Offsite Power Available Event Time (s) Comment Double ended guillotine break (DEGB) of MFW nozzle occurred, resulting in assumed complete loss of MFW 0 Area = 1.12 ft2 to both SGs SG low level setpoint reached 11.0 5%NR in faulted SG SG low level trip occurred 11.9 Rod motion began 12.4 High SG differential pressure (DP) trip setpoint reached (not credited) 20.7 335 psid SG low pressure trip setpoint reached(1) 24.2 400 psia AFAS setpoint reached in intact SG 38.7 5% NR in intact SG High pressurizer pressure trip and PORV setpoint 364 2320 psia reached(')

AFW began to intact SG 369 Signal plus 330 s delay RCPs tripped by operator 912 15 minutes after reactor trip AFW heat removal matched core decay heat and peak 2090 9'F subcooling at that time RCS temperature occurred I I Calculation terminated 3000 (1)

Reactor trips on SG low level RPS trip, which occurs earlier.

L-2012-085 Attachment Page 9 of 15 Table 4-2 Sequence of Events for FWLB with Loss of Offsite Power Event Time (s) Comment DEGB of MFW nozzle occurred, resulting in assumed 0 Area = 1.12 ft2 complete loss of MFW to both SGs SG low level setpoint reached 11.0 5%NR in faulted SG SG low level trip occurred; RCPs began coastdown 11.9 based on assumed loss of offsite power Rod motion began 12.4 High SG DP trip setpoint reached (not credited) 17.0 335 psid SG low pressure trip setpoint reached(1 ) 24.5 400 psia AFAS setpoint reached in intact SG 33.7 5% NR High pressurizer pressure trip and PORV setpoint reached(2) 116 2320 psia AFW began to intact SG 364 Signal plus 330 s delay AFW heat removal matched core decay heat and peak 2276 28°F subcooling at that time RCS temperature occurred Calculation terminated 3000 (1)

Reactor trips on SG low level RPS trip, which occurs earlier.

Table 4-3 Summary of Results AFW Heat Removal Matched Decay Heat (1)

Case Time (s) (2) Subcooling (fF)

No LOOP 2090 9 LOOP 2276 28 (1) The time that AFW heat removal capability matched decay heat production was defined as the time at which RCS temperature peaked.

(2) In each case, the calculation was run to 3000 seconds to provide an estimate of available time for additional operator action.

L-2012-085 Attachment Page 10 of 15 30OO 2500

-a 2000 ca 1000 500 0

3000 Time (s)

ID28248 gFebM212 10:23:36 sla_fwlb_112ft2no_loop_15min_5_.dmx Figure 4-1 No LOOP Case: Pressurizer and SG Pressures 3000 L

... PSV 2500 R 2000 ME

.S --.

......... Pressurizer 1500 SG-1 (faulted) 2 - - -. SG-2 1000 -I-- - - - - - - - - - - - - ---- --. ------ ---- ----- ------- ----- -.. --- ---------- ------ -------- .

5oo

.. . . . . . . . . . . . . . . . . .G.

. . . . . . . . . . . . . . . .. . . . . . . . . .. . . . . .. . . . . . . . . . . . . . . . .. .t . . . . . . . .. . . . . . . .

0 500 1000 1500 2000 2500 3000 Time (s)

ID58444 9FM2012 10-28:31 sla_fwtb_I.12f51_oop15min_5_.dm Figure 4-2 LOOP Case: Pressurizer and SG Pressures

L-2012-085 Attachment Page 11 of 15 680 670 660 650

• 640 830 6'j /

/

620

//

610

- 600 590

/ -. Saturation

• / HL-1 (faulted) 580 -HL-2 570 560 0 500 1000 1500 2000 2500 3000 Time (s)

ID28248 gFeb2012 10*:23:38 sla_fwý_1.12f82_no_loop_15min 5_.dmx Figure 4-3 No LOOP Case: Hot Leg Temperatures 680 670 660 650 640 630 0 620 C 610 E

F- 600

.-...... Saturation HL-1 (faulted) 590 580 - - -- HL-2 570 560 0 500 1000 1500 2000 2500 3000 Time (s)

ID:58444 Feb2012 10:28:31 sohfwýb_1.12f2_loop_15min_5_d=

Figure 4-4 LOOP Case: Hot Leg Temperatures

L-2012-085 Attachment Page 12 of 15 100

.0 0 1 1 1 1 1 0 500 1000 1500 2000 2500 3000 Time (s)

ID28248 FebM212 1023:36 slafwlb 1.12ft2_no IooplS1ni5_.dmx Figure 4-5 No LOOP Case: Hot leg Subcooling

-100 80 60 240 20 0 500 1000 1500 2000 2500 3000 Time (s)

ID:58444 9Feb2012 1028:31 sla_fwb 1.12f2_loop_15min 5 .dmx Figure 4-6 LOOP Case: Hot Leg Subcooling

L-2012-085 Attachment Page 13 of 15 120 100 80 60

-j 40 20 0

0 500 1000 1500 2000 2500 3000 Time (s) 1D28248 FeM2012 10:23:36 slafwMb_1.1262_nooop_15min_5_.dmx Figure 4-7 No LOOP Case-: Pressurizer Liquid Level 120 100o 80 4

60 32

-7I 40 20 0 500 1000 1500 2000 2500 3000 Time (s)

ID:58444 QFebM2O1210:28:31 siafw-_1.12f2_loop_15min_5_.dmx Figure 4-8 LOOP Case: Pressurizer Liquid Level

L-2012-085 Attachment Page 14 of 15 140000 100000 E0 80000 0a 60000 40000 00O 0 500 1000 1500 Time (s)

ID28248 gFeb2012 10-23:36 slafwb_1.12f2 noloop_15mm 5 .dmx Figure 4-9 No LOOP Case: SG Inventories 140000 120000 100000 Ea 80000 60000 40000 20000 0 500 1000 1500 2000 2500 3000 Time (s)

ID58444 9Feb201210-28:31 siafb_1.12f2b loop 1Snn-5_.drn Figure 4-10 LOOP Case: SG Inventories

L-2012-085 Attachment Page 15 of 15 400 200 LL E

0

> 100 0

1500 3000 Time (s) 1028248 9Feb2012 10:23:38 sla fw* 1.12ft2_no_loop_15minS5.dmx Figure 4-11 No LOOP Case: AFW Flow-Rates 400 300 F ........... -..... ....................................................... .. .. . .. ... .. .. .. .. .. .. . . . .. .. .. .. .. .. a o,

LL 200 v E

-o SG-1 (faulted) 100 k . SG-2 500 1000 1500 2000 2500 3000 Time (s)

ID:58444 9Feb2012 10:28:31 slafwb_1.12f12_loop_15mIn._5.dmx Figure 4-12 LOOP Case: AFW Flow Rates