Text

Amendment 32 to Updated Final Safety Analysis Report, Chapter 15, Accident Analysis, Volume 2
	ML23096A039
Person / Time
Site:	Saint Lucie
Issue date:	04/01/2023
From:	; Florida Power & Light Co
To:	; Office of Nuclear Reactor Regulation
Shared Package
ML23096A089	List: ML23096A025; ML23096A026; ML23096A027; ML23096A028; ML23096A030; ML23096A031; ML23096A032; ML23096A033; ML23096A034; ML23096A035; ML23096A036; ML23096A037; ML23096A039; ML23096A040; ML23096A041; ML23096A042; ML23096A043; ML23096A044; ML23096A045;
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15.3 POSTULATED ACCIDENTS (CLASS 2 ACCIDENTS)

Class 2 accidents include those which (1) may induce fuel failures, (2) may lead to a breach of barriers and fission product release, (3) may require operation of engineered safety features, or (4) may result in offsite radiation exposures in excess of normal operational limits.

The events discussed in this section are assumed to occur infrequently and are not required to meet the SAFDLS. The ultimate criteria applied to these transients is a radiation exposure limit. Events in this category are:

15.3.1 Loss of reactor coolant from small ruptured pipes or from cracks in large pipes which actuates emergency core cooling system.

15.3.2 Minor secondary system pipe breaks.

15.3.3 Inadvertent Loading Operation of a fuel assembly into the improper position.

15.3.4 Seized Rotor Event.

Reanalysis for event 15.3.3 has not been required since the discussion presented in that section remains applicable.

Events 15.3.1 and 15.3.4 were reanalyzed for the extended power uprate.

15.3.1 LOSS OF REACTOR COOLANT FROM SMALL RUPTURED PIPES OR FROM CRACKS IN LARGE PIPES WHICH ACTUATES EMERGENCY CORE COOLING SYSTEM 15.3.1.1 Identification of Causes A loss of coolant accident is defined as a rupture of the reactor coolant system piping.

Should a small break occur, depressurization of the reactor coolant system causes the pressurizer to empty.

This results in a decrease of both the reactor coolant pressure and the pressurizer level. A reactor trip occurs when the low thermal margin trip setting is reached. Safety injection is then initiated by low reactor coolant pressure. The high containment pressure signal is used as a backup for a reactor trip and safety injection actuation signal. The safety injection system provides borated water to reflood and recover the reactor core to limit clad temperatures. When the reactor coolant system pressure falls below 245 psia, the safety injection tanks begin to inject water into the reactor coolant system.

15.3.1-1 Amendment No. 26 (11/13)

A containment isolation signal (CIS) is actuated by high containment pressure or radiation. The CIS will initiate closure of all non-essential containment isolation valves and will start the shield building ventilation system.

The actuation response time of the SIAS and the CIS instrumentation is discussed in Section 7.3.2.1.

15.3.1.2 Analysis of Effects and Consequences for Small Break LOCA The postulated SBLOCA event is defined as a break in the RCS pressure boundary which has an area of up to approximately 10% of the cold leg pipe area. The most limiting break location is in the cold leg pipe on the discharge side of the RCP. This break location results in the largest amount of inventory loss and the largest fraction of ECCS fluid being ejected out through the break. This produces the greatest degree of core uncovery, the longest fuel rod heatup time, and consequently, the greatest challenge to the 10 CFR 50.46(b)(1-4) criteria.

The SBLOCA event is characterized by a slow depressurization of the primary system with a reactor trip occurring on a Low Pressurizer Pressure signal. The SIAS occurs when the system has further depressurized.

The capacity and shutoff head of the HPSI pumps are important parameters in the SBLOCA analysis. For the limiting break size, the rate of inventory loss from the primary system is such that the HPSI pumps cannot preclude significant core uncovery. The primary system depressurization rate is slow, extending the time required to reach the SIT pressure or to recover core liquid level on HPSI flow. This tends to maximize the heatup time of the hot rod which produces the maximum PCT and local cladding oxidation. Core recovery for the limiting break begins when the Sl flow that is retained in the RCS exceeds the mass flow rate out the break followed by injection of SIT flow. For very small break sizes, the primary system pressure does not reach the SIT pressure.

EC292529 The Framatome (formerly AREVA) S-RELAP5 SBLOCA evaluation model for event response of the primary and secondary systems and hot fuel rod used in this analysis (Reference 113) consists of two computer codes. The appropriate conservatisms, as prescribed by Appendix K of 10 CFR 50, are incorporated. This methodology has been reviewed and approved by the NRC to perform SBLOCA analyses.

1. The RODEX2-2A code was used to determine the burnup-dependent initial fuel rod conditions for the system calculations.

2. The S-RELAP5 code was used to predict the thermal-hydraulic response of the primary and secondary sides of the reactor system and the hot rod response.

The RODEX2-2A gap conditions used to initialize S-RELAP5 are taken at EOC, consistent with an EOC top-peaked axial power distribution. The use of EOC fuel rod conditions along with an EOC power shape is bounding of BOC because (1) the gap conductance is higher at EOC, (2) the power shape is more top-skewed at EOC, and (3) the initial stored energy, although higher at BOC, has a negligible impact on the SBLOCA results since the stored energy is dissipated long before core uncovery.

15.3.1-2 Amendment No. 30 (05/20)

15.3.1.3 SBLOCA Results The SBLOCA analysis was performed with the EPU core power of 3020 MWt plus 0.3% measurement uncertainty. The analysis was performed to support 10% Steam Generator tube plugging with an asymmetry of

+/- 2% and an RCS flow rate of 375,000 gpm. The analysis supports a radial peaking factor (Fr) of 1.65 (1.749 with uncertainties), and a maximum Linear Heat Rate (LHR) of 15.0 kW/ft. The HPSI system was modeled to deliver the total Sl flow asymmetrically to the broken loop and three intact loops as described in Table 15.3.1-1.

Table 15.3.1-2 displays the parameter values assumed in the current analysis. Analysis of the limiting SBLOCA (3.70 in. diameter) with the parameters specified in Table 15.3.1-2 produced a peak cladding temperature (PCT) of 1828°F(1). The peak local oxidation (PLO) was 3.31%, which is for the 3.6 in. and 3.7 in. diameter break. The EC292529 maximum core-wide oxidation (CWO) was 0.041%, which is for the 3.6 in. diameter break.

SBLOCA break spectrum calculations were performed for break diameters of 3.5, 3.6, 3.65, 3.7, 3.75 and 3.8 in.

The limiting break diameter was determined to be 3.70 in. From Figure 15.3.1-14, it can be observed that the increase in cladding temperature was being mitigated by HPSI flow just prior to the cladding being quenched by SIT flow. This typifies the limiting case. Break diameters larger than 3.8 in. are less limiting due to faster RCS depressurization and earlier timing of SIT flow. For smaller break diameters, the break flow becomes smaller such that the ability of the HPSI flow to maintain RCS mass and limit core uncovery becomes greater, which will result in lower PCTs.

The plant responses to the transient for the limiting break diameter case (3.70 in) are shown in Figures 15.3.1-1 through 15.3.1-14.

Additional calculations were performed to evaluate a break in the Safety Injection Tank (SIT) line, and to evaluate the impact of delayed reactor coolant pump (RCP) trip. The SIT line break results demonstrate that it is non-limiting compared to the break spectrum results.

RCA Trip Sensitivity Calculations

[A RCP trip study is performed to validate the conclusions of the earlier CEOG study (CEN-268, Revision 1 &

Supplement 1-P, Revision 1-P), approved by the NRC (ML031150282), for applicability to EPU operation.]

The SBLOCA break spectrum calculations conservatively assumed RCP trip at reactor trip due to an assumed loss of offsite power at reactor trip. However, a delayed RCP trip following loss of subcooling margin (or reactor coolant system pressure of 1600 psia) can potentially challenge the 10 CFR 50.46 criteria. Continued operation of the RCPs can result in more integrated mass lost out the break and also tends to maintain RCS pressure at a plateau until the RCPs are tripped. This could potentially result in a reduced HPSI flow rate early in the transient. The combined effect could result in less RCS and RV mass, and more core uncovery, challenging the PCT criterion.

Series of calculations using Appendix K models was performed for both cold leg and hot leg break cases with various RCP trip delay times. Results from the hot leg break cases were more limiting than the results from the cold leg break cases. The results of the hot leg break delayed RCP trip cases indicate that there is at least 2 minutes to trip all four RCPs after the RCS pressure reaches 1600 psia (loss of subcooling margin is lost prior to the RCS pressure reaching 1600 psia) in order to meet the 10 CFR 50.46 criteria.

A delayed RCP trip analysis was also performed using conservative best estimate models. Both cold leg and hot leg break cases with various RCP trip delay times were analyzed. The results indicate there is at least 15 minutes to trip all four RCPs after the RCS pressure reaches 1600 psia (loss of subcooling margin is lost prior to the RCS pressure reaching 1600 psia) in order to meet the 10 CFR 50.46 criteria.

It is seen that the RCP study, performed for St. Lucie Unit 1 EPU operation, supports the same conclusions as stated in the CEOG study and the corresponding NRC SE using similar approach. Thus, no changes to plant procedures, with respect to RCP trip, are needed.

(1) The PCT changes due to evaluation model errors/changes are documented in the 10 CFR 50.46 reports.

EC292529 These PCT changes are not (or may not be) reflected in the PCT documented here.

UNIT 1 15.3.1-3 Amendment No. 30 (05/20)

DELETED 15.3.1-3a Amendment No. 26 (11/13)

TABLE 15.3.1-1 HPSI FLOW RATE VS. RCS PRESSURE USED IN THE SBLOCA EVENT RCS Pressure Broken Loop Intact Loop (psia) (gpm) (gpm)

EC297691 15 160.6 151.9 315 138.4 130.97 615 110.6 104.6 815 88.6 83.73 1015 57.3 54.2 1115 32.0 29.17 1125 27.3 24.9 1135 17.8 16.2 1145 1.8 1.633 1145.5 0.0 0.0 UNIT 1 15.3.1-3b Amendment No. 32 (04/23)

Table 15.3.1-2 CURRENT SBLOCA ANALYSIS PARAMETERS Parameter Current Analysis Value Reactor Power, MWt 3020 + 0.3% measurement uncertainty Peak LHR, kW/ft 15.0 Radial Peaking Factor (1.65 plus uncertainty) 1.749 RCS Flow Rate, gpm 375000 Pressurizer Pressure, psia 2250 Core Inlet Coolant Temperature, °F 551 SIT Pressure, psia 244.7 SIT Fluid Temperature, °F 120 SG Tube Plugging Level, % 10 SG Secondary pressure, psia 830 MFW Temperature, °F 436 AFW Temperature, °F 111.5 Low SG Level AFAS Setpoint, % 5 HPSI Fluid Temperature, °F 104 Charging system delay time, sec 150 Reactor Scram Low Pressurizer Pressure Setpoint, psia 1807 Reactor Scram Delay Time on Low Pressurizer Pressure, sec 0.9 Scram CEA Holding Coil Release Delay Time, sec 0.5 SIAS Activation Setpoint Pressure for harsh conditions, psia 1520 HPSI Pump Delay Time on SIAS, sec 30 MSSV lift pressures Nominal + 3% uncertainty UNIT 1 15.3.1-3c Amendment No. 27 (04/15)

Reactor Power 120 110

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Amendment No. 27 (04/15)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 REACTOR POWER FOR 3.70 IN.

DIAMETER BREAK SBLOCA FIGURE 15.3.1-1

System Pressure 2400 0

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Amendment No. 27 (04/15)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 PRIMARY AND SECONDARY PRESSURES FOR 3.70 IN. DIAMETER BREAK SBLOCA FIGURE 15.3.1-2

r------:-:-, '

Break Void Fraction 1.00 0.90 1 - - - ---tt- + - - - - - - ' - - - - - - - - ' - - - -..---- + - - - - ---t Break Vo id Fractio n 0.80 1 - - - ----- + - - - - - - . - - - - - - - . - - - - - - + - - - - ---t 0.70 1------1---+-------+-------+---------+-------1

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0 500 1000 1500 2000 2500 Time (sec.)

Amendment No. 27 (04/15)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 BREAK VOID FRACTION FOR 3. 70 IN.

DIAMETER BREAK SBLOCA FIGURE 15.3.1-3

Break Flow Rate

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Amendment No. 27 (04/15)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 BREAK FLOW RATE FOR 3.70 IN.

DIAMETER BREAK SBLOCA FIGURE 15.3.1-4

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Amendment No. 27 (04/15)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 LOOP SEAL VOID FRACTIONS FOR 3.70 IN. DIAMETER BREAK SBLOCA FIGURE 15.3.1-5

RCS Loop Flow Rate 110 100 Loop 1A Loop Flow Rate 90 Loop 1B Loop Flow Rate Loop 2A Loop Flow Rate 80 - ~ - Loop 28 Loop Flow Rate 70

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Amendment No. 27 (04/15)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 RCS LOOP FLOW RATE FOR 3.70 IN.

DIAMETER BREAK SBLOCA FIGURE 15.3.1-6

SG MFW Flow Rate 110 100 90 80

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Amendment No. 27 (04/15)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 MFW FLOW RATE FOR 3.70 IN.

DIAMETER BREAK SBLOCA FIGURE 15.3.1-7

SG AFW Flow Rate 50~--------------------------------------------------,

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Amendment No. 27 (04/15)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 AFW FLOW RATE FOR 3.70 IN.

DIAMETER BREAK SBLOCA FIGURE 15.3.1-8

SG Total Mass 200000~----------------------------------------------~

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Amendment No. 27 (04/15)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 STEAM GENERATOR TOTAL MASS FOR 3.70 IN. DIAMETER BREAK SBLOCA FIGURE 15.3.1-9

Total HPSI Flow Rate 100 90 Total HPSI Flow Rate 80 70 u

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Amendment No. 27 (04/15)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 TOTAL HPSI MASS FLOW RATE FOR 3.70 IN. DIAMETER BREAK SBLOCA FIGURE 15.3.1-10

Total SIT Flow Rate 100 90 Total SIT Flow Rat e 80 70 u

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Amendment No. 27 (04/15)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 TOTAL SIT MASS FLOW RATE FOR 3.70 IN. DIAMETER BREAK SBLOCA FIGURE 15.3.1-11

RCS and RV Mass 500000~----------------------------------------------~

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Amendment No. 27 (04/15)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 RCS AND REACTOR VESSEL MASS INVENTORIES FOR 3.70 IN.

DIAMETER BREAK SBLOCA FIGURE 15.3.1-12

Hot Assembly Collapsed Liquid Level and Mixture Level

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Amendment No. 27 (04/15)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 HOT ASSEMBLY COLLAPSED LIQUID LEVEL FOR 3.70 IN.

DIAMETER BREAK SBLOCA FIGURE 15.3.1-13

Hot Spot Cladding and Coolant Temperature 2200.-------------------------------------------------.

Hot Spot Cladding Temperature 2000

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Amendment No. 27 (04/15)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 HOT SPOT CLADDING TEMPERATURE AND COOLANT TEMPERATURE FOR 3.70 IN. DIAMETER BREAK SBLOCA FIGURE 15.3.1-14

15.3.2 MINOR SECONDARY SYSTEM PIPE BREAKS 15.3.2.1 Identification of Causes A minor secondary system pipe break is defined as one which results in steam blowdown rates equivalent to a 6 inch diameter break outside the containment.

15.3.2.2 Analysis of Effects and Consequences A separate analysis is not required for minor secondary system pipe breaks. The break area is less than the full steam line area for the main steam line break event presented in Section 15.4.6, and any fuel failure predicted for the main steam line break event will bound this event. Therefore, this event is bounded by the main stem line break event.

15.3.2-1 Amendment No. 26 (11/13)

15.3.3 INADVERTENT LOADING OF A FUEL ASSEMBLY INTO THE IMPROPER POSITION 15.3.3.1 Identification of Causes There are two accidents considered in this section; first, the erroneous loading of fuel pellets or fuel rods of different enrichment in a fuel assembly, and second, erroneous placement or orientation of fuel assemblies.

An error in assembly, fabrication or core loading is considered to be extremely unlikely. The extensive quality control and quality surveillance programs employed during the fabrication process, along with the strict procedural control used during core loading, will preclude the possibility of such errors. However, even if fuel rods or assemblies were incorrectly placed, these would either be detectable from the results of the startup testing program or would lead to a minimal number of rods at excessive power during operation.

15.3.3.1.1 Erroneous Loading of Fuel Pellets or Fuel Rods of Different Enrichment in a Fuel Assembly The probability of manufacturing a fuel assembly with an incorrect enrichment is remote. The extensive quality control and quality surveillance programs in effect during the manufacture of the fuel pellets, in the pellet loading of the fuel rods, and in the fuel rod installation in the fuel assembly precludes the possibility of manufacturing a fuel assembly with incorrect enrichments.

During the manufacture and assembly of the fuel rods, numerous check points and assay tests ensure that the enrichment is as specified and that the fuel rods and fuel assemblies are properly loaded and assembled. An assay is made of each lot of UO2 powder to ensure that the enrichment is as required by the fuel specification. During the manufacture of the pellets each powder lot is isolated during processing. In addition to batch identification, each pellet is identified with an imprinted number or letter identifying the enrichment. After sintering, an additional enrichment check of the fabricated pellets is made by random sampling. Assembly of the fuel rods is performed by loading the fuel pellets into cladding onto which one end cap has been welded. The end cap is marked prior to welding to identify the enrichment to be loaded into the fuel rod.

During fuel rod assembly the quality control procedures require verification of each fuel rod in the assembly. Each fuel assembly is identified by a serial number which is engraved on the upper end fitting as shown on Figure 4.2-4.

A record of all operations performed on each fuel rod and each poison rod up to and including final fuel assembly is recorded on computer punch cards, one for each fuel rod and each poison rod. This procedure permits a rapid check at completion of fabrication to ensure that each rod within the fuel assembly has completed all of the required steps within the fabrication process. The computerized record keeping system also has the advantage of 15.3.3-1 Amendment No. 24 (06/10)

providing a mechanism by which an accurate record of all fuel rods within a fuel assembly can be defined as well as the enrichment, weight of uranium U-235 and UO2, and lot number of the fuel within each fuel rod.

15.3.3.1.2 Erroneous Placement or Orientation of Fuel Assemblies The fuel enrichment within a fuel assembly is identified by a coded serial number marked on the exposed surface of the upper end fitting of the fuel assembly. This serial number is used as a means of positive identification for each assembly in the plant. A status board is provided in the refueling control center that shows a schematic representation of the reactor core, spent fuel pool and new fuel storage area. During the period of core loading, the location of each CEA, fuel assembly and source is shown by its identification number on this status board.

The status board in the refueling control center will be constantly updated by a designated member of the reactor operations staff whenever a fuel assembly is being moved. The staff member in the refueling control center will be in constant communication with each area where this is occurring. Also, a senior licensed operator will be present during alteration of the core to directly supervise the activity and ensure that the assemblies are moved to the correct locations. Fuel assemblies will not be moved unless these lines of communication are available. In addition to these precautions, periodic independent inventories of components in the reactor core, spent fuel, and new fuel storage areas will be made to ensure that the status board is correct. Also, at the completion of core loading, the exposed surfaces of the upper end fittings are inspected to verify that all assemblies are correctly located. These precautions are included in the core loading procedures which are to be reviewed by appropriate plant personnel.

15.3.3.2 Analysis of Effects and Consequences 15.3.3.2.1 Erroneous Loading of Fuel Pellets or Fuel Rods of Different Enrichment in a Fuel Assembly When the power distribution is peaked in a peripheral high enrichment C- assembly it is expected that replacing single batch C-fuel rod (2.82 w/o U235) by lower enriched fuel from batches A (1.93 w/o U235) or B (2.33 w/o U235) would not cause any peaking problems. In order to increase peaking in the periphery, fuel rods of a higher enrichment than the highest (2.82 w/o) used in batch C would have to be inserted into a C-assembly. This is not considered to be credible.

Another possible combination would be the replacement of A-fuel rods by C-fuel rods. The magnitude of the local peaking factor increase would depend on several conditions that must be arbitrarily postulated, such as the number of A-fuel rods replaced by C-fuel rods and the location of these rods with respect to the water holes. At one end of the scale of postulated situations, the increased local peaking would be too small to adversely affect core performance. These situations may go undetected. Fuel loading errors that cause local power peaking increases large enough to adversely affect core performance will be detectable through the use of incore instrumentation during startup testing.

15.3.3-2 Amendment No. 25 (04/12)

15.3.3.2.2 Erroneous Placement or Orientation of Fuel Assemblies If, in spite of the above precautions to prevent misloading a fuel assembly into the reactor core, it is assumed that an assembly is placed in the wrong core position, then many combinations may exist.

Probably the worst combination would be the interchange of two assemblies of different reactivities. This would tend to maximize the induced power tilt. Figures 15.3.3-2, 15.3.3-3 and 15.3.3-4 for a similar rated plant (Maine Yankee Docket 50-309) show examples of postulated interchanges of fuel assemblies in the core. Relative power densities are displayed for each fuel assembly in a quarter core together with maximum fuel rod peaks. The data should be compared with the unperturbed power distribution of BOL shown in Figure 15.3.3-1. Figures 15.3.3-2 and 15.3.3-3 indicate interchanges of unshimmed and shimmed batch C assemblies. Figure 15.3.3-4 shows the effect of an interchange of an unshimmed batch C assembly with the central batch A fuel assembly. The examples chosen yield appreciable radial peaking. These analyses were performed with standard design calculational tools similar to those described in Section 4.3.

As has been shown, the incorrect location of fuel assemblies can lead to an appreciable departure from the expected BOL power distribution. However, if this occurs, there will be an attendant change in the core characteristics. More specifically, the resultant core will have an asymmetric power distribution which would be detected by the incore (Section 4.3.5) and/or out-of-core (Section 7.2.1) instrumentation during startup testing. (This would be true even if the central assembly were interchanged with another.)

Another means of detecting tilts induced by misplacement of fuel assemblies may be provided by the measurement of individual reactivity worths for symmetrically located CEAs during startup testing.

Assembly misorientation would not be a problem on the first core since each assembly is of itself symmetric.

15.3.3.3 Extended Power Uprate Evaluation The UFSAR considers two sub-events:

Erroneous Loading of Fuel Pellets or Fuel Rods of Different Enrichment in a Fuel Assembly

Erroneous Placement or Orientation of Fuel Assemblies Aside from the administrative and surveillance programs specifically designed to prevent a fuel assembly mislead, several redundant systems are present to detect power maldistributions. It has been determined that with the incore detector monitoring system operable per UFSAR Sections 4.2.2.2.8 and 13.8.1.2, the detection of misloaded assemblies is not adversely impacted by EPU.

With 75% of the detectors operational during startup, the core remains adequately monitored.

Neither of the two identified events are affected by the EPU; therefore, the current licensing analysis given in the UFSAR Sections 15.3.3.2.1 and 15.3.3.2.2 bounds the EPU.

Additionally, neither of these events are affected by placing certain irradiated fuel assemblies into dry storage casks. The Updated FSAR analyses bound Unit 1 operation with irradiated fuel in dry storage.

15.3.3-3 Amendment No. 26 (11/13)

H K

c 0.61 C-12 0.77 c

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1. 07 . 1. 09 0.76 1.14 1.02 1. 03 I. 07 4 1.19 1. 28 1.09 1.13 1.13 1.18 1.14 c C-12 B-16 1.02 A

1. 05 B-16

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1.09 B-16 A 1.11 1.10 0.61 1. 06 5 1.00 I. 21 1.09 1.15 1.14 1.19 1.16 I. 21 C-12 B-16 A B-16 A B-16 A B-16 0.77 0. 94 1. 03 1. 08 1. 09 1.12 1.12 1.13 6

1. 06 1.13 1.14 1. 20 1. 22 1. 22 1.18

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15.3.3-2

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FLORIDA POWER & LIGHT CO.

St. lucie Plant Unit l Power Distribution for Postulated Interchange of Two C Assemblies MAINE YANKEE 15.3.3-3

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St. Lucie Plant Unit 1 Power Distribution for Postulated Interchange of an A and C Assembly MAINE YANKEE 15. 3. 3-4

15.3.4 SEIZED ROTOR EVENT 15.3.4.1 Identification of Causes The seized rotor event is analyzed to demonstrate that the RCS pressure limit of 2750 psia will not be exceeded and only a small fraction of fuel pins are predicted to fail during this event.

The single reactor coolant pump shaft seizure is postulated to occur as a consequence of a mechanical failure. The single reactor coolant pump shaft seizure results in a rapid reduction in the reactor coolant flow to the three-pump value. A reactor trip for the seized rotor event is initiated by a low coolant flow rate as determined by a reduction in the sum of the steam generator hot or cold leg pressure drops. This signal is compared with a setpoint.

15.3.4.2 Analysis of Effects and Consequences The Reactor Coolant Pump Rotor Seizure (also known as Locked Rotor) event is postulated as the instantaneous seizure of a (single) reactor coolant pump rotor. Flow through the faulted RCS loop rapidly decreases, causing a reactor trip on a Low RCS Flow signal within 1 to 2 seconds and a turbine trip on the reactor trip. Furthermore, a loss of offsite power is assumed to occur at that time, which causes the remaining reactor coolant pumps to begin coasting down.

Following the reactor trip, heat stored in the fuel rods continues to be transferred to the reactor coolant.

The combination of the relatively high fuel rod surface heat fluxes, decreasing core flow, and increasing core coolant temperatures challenges the DNBR safety limit and may result in fuel failure.

At the same time, the steam generator primary-to-secondary heat transfer rate decreases because (1) the decreasing primary coolant flow degrades the steam generator tube primary side heat transfer coefficients and (2) the turbine trip causes the secondary-side temperature to increase. Decreasing rate of heat removal in the steam generators combined with decreasing flow of coolant removing heat from the reactor core cause the reactor coolant to heat up. The resultant reactor coolant expansion causes fluid to surge into the pressurizer and an increase in RCS pressure. This will actuate the automatic pressurizer spray system and may even open the pressurizer PORVs and safety valves. The event may challenge the RCS overpressure criterion.

Since the systems designed to mitigate this event (namely, the RPS) are redundant, there is no single active failure that will adversely affect the consequences of the event. There are also no relevant operator actions within the (short term) time period of this analysis.

Detailed analyses were performed with approved methodologies using the S-RELAP5 and XCOBRA-IIIC codes (References 117, 108, and 109). The S-RELAP5 code was used to model the key system components and calculate neutron power, fuel thermal response, surface heat transport, and fluid conditions (such as coolant flow rates, temperatures, and pressures) and produce an estimated time of MDNBR. The core fluid boundary conditions and average rod surface heat flux were then input to the XCOBRA-IIIC code, which was used to calculate the MDNBR using the HTP CHF correlation (Reference 110).

A single case was analyzed at BOC HFP initial conditions, maximum Technical Specifications core inlet temperature and minimum Technical Specifications RCS flow rate. The factors affecting scram time were chosen to maximize the scram delay with the trip signal delay and holding coil delay times set to their maximum values. This produced the most significant challenge to the DNB limit. Note that only the DNB case is presented because the maximum RCS pressure case is not limiting. Steam release data were calculated to cool the plant down to 212°F based on an assumed operator action time of up to 45 min.

15.3.4-1 Amendment No. 26 (11/13)

The input parameters and biasing for the analysis of this event are shown in Table 15.3.4-1. The input parameters and biasing were consistent with the approved methodology.

Initial Conditions - HFP initial conditions, maximum Technical Specifications core inlet temperature and minimum Technical Specifications RCS flow rate were assumed in order to minimize the initial margin to DNB.

Core Inlet Flow Distribution - A conservatively biased inlet flow rate to the limiting fuel assembly and a highly limiting gradient flow distribution were used in the DNB calculation to account for cross flow into the affected quadrant in the lower plenum caused by the seized RCP rotor.

Reactivity Feedback - Since the event involves an increase in the core coolant temperature, the event was assumed to occur at BOC with a maximum TS MTC at full power. However, this event occurs quickly and is generally not sensitive to neutronics parameters. A minimum HFP scram worth was used to conservatively prolong the degradation in flow while maintaining relatively high core power.

Reactor Protection System Trips and Delays - The event is primarily protected by the low flow RPS trip. The reactor protection system trip setpoints and response times were conservatively biased to delay the actuation of the trip function. In addition, a maximum CEA holding coil delay was assumed.

Loss of Offsite Power - Loss of offsite power at the time of turbine trip (resulting from reactor trip) was assumed. The remaining three RCPs were assumed to begin to coast down with the loss of offsite power which conservatively reduced the flow for the calculation of DNB. The coastdown characteristics of the RCPs were conservatively bench marked to plant data.

Gap Conductance - Gap conductance was set to a conservative BOC value to delay the transfer of heat from the fuel rod to the coolant allowing the primary system flow to decay further thus leading to a conservative prediction of DNBR.

This event is classified as a Postulated Accident. The principally challenged acceptance criterion for this event is with respect to radiological consequences. The extent of fuel failure was determined by the S-RELAP5 and XCOBRA-IIIC analyses. In addition, steam releases were calculated based on a plant cooldown to 212°F.

This event does not represent a significant challenge to fuel centerline melting because there is no large power increase and no significant adverse power redistribution within the core. Also, the increase in RCS pressure for this event is much less severe than the result of the Loss of External Electrical Load (see Section 15.2.7).

15.3.4-1a Amendment No. 26 (11/13)

DELETED 15.3.4-2 Amendment No. 26 (11/13)

15.3.4.3 Results The sequence of events is given in Table 15.3.4-2. Plots of key system parameters are shown in Figure 15.3.4-1 to Figure 15.3.4-6. The MDNBR was statistically calculated and compared to the 95/95 limit for EC292761 the HTP DNB correlation. The fuel failure due to DNB remains below the limit used in the radiological consequences analysis.

15.3.4.3.3 Radiological Analysis 15.3.4.3.3.1 Background This event is caused by an instantaneous seizure of a primary reactor coolant pump rotor. Flow through the affected loop is rapidly reduced, causing a reactor trip due to a low primary loop flow signal. Fuel damage may be predicted to occur as a result of this accident. Due to the pressure differential between the primary and secondary systems and assumed steam generator tube leakage, fission products are discharged from the primary into the secondary system. A portion of this radioactivity is released to the outside atmosphere from the secondary coolant system through the steam generator via the ADVs and MSSVs. In addition, radioactivity is contained in the primary and secondary coolant before the accident and some of this activity is released to the atmosphere as a result of steaming from the steam generators following the accident. The St. Lucie Unit 1 AST dose analysis methodology is presented in Reference 117.

15.3.4.3.3.2 Compliance with RG 1.183 Regulatory Positions The revised Locked Rotor dose consequence analysis is consistent with the guidance provided in RG 1.183, Appendix G, "Assumptions for Evaluating the Radiological Consequences of a PWR Locked Rotor Accident," as discussed below:

UNIT 1 15.3.4-2a Amendment No. 30 (05/20)

The Locked Rotor dose consequence analysis followed the guidance provided in RG 1.183, Appendix G, "Assumptions for Evaluating the Radiological Consequences of a PWR Locked Rotor Accident," as discussed below:

1. Regulatory Position 1 - The total core inventory of the radionuclide groups utilized for determining the source term for this event is based on RG 1.183, Regulatory Position 3.1, and is provided in Table 15.4.1-1e. The inventory provided in Table 15.4.1-1e is adjusted for the fraction of fuel damaged and a radial peaking factor of 1.65 is applied. The fraction of fission product inventory in the gap available for release due to fuel breach is consistent with Table 3 of RG 1.183. Gap release fractions have also been increased to account for high burnup fuel.

2. Regulatory Position 2 - Fuel damage is assumed for this event.

3. Regulatory Position 3 - Activity released from the damaged fuel is assumed to mix instantaneously and homogeneously throughout the primary coolant.

4. Regulatory Position 4 - The chemical form of radioiodine released from the damaged fuel is assumed to be 95% cesium iodide (CsI), 4.85% elemental iodine, and 0.15% organic iodide. Iodine releases from the SGs to the environment are assumed to be 97% elemental and 3% organic. These fractions apply to iodine released as a result of fuel damage and to equilibrium iodine concentrations in the RCS and secondary system.

5. Regulatory Position 5.1 - The primary-to-secondary leak rate is apportioned between the SGs as specified by TS 6.8.4.l (0.5 gpm total, 0.25 gpm to any one SG). Thus, the tube leakage is apportioned equally between the two SGs.

6. Regulatory Position 5.2 - The density used in converting volumetric leak rates to mass leak rates is based upon RCS conditions, consistent with the plant design basis.

7. Regulatory Position 5.3 - The primary-to-secondary leakage is assumed to continue until after shutdown cooling has been placed in service and the temperature of the RCS is less than 212°F.

8. Regulatory Position 5.4 - The analysis assumes a coincident loss of offsite power in the evaluation of fission products released from the secondary system.

9. Regulatory Position 5.5 - All noble gas radionuclides released from the primary system are assumed released to the environment without reduction or mitigation.

10. Regulatory Position 5.6 - Regulatory Position 5.6 refers to Appendix E, Regulatory Positions 5.5 and 5.6. The iodine transport model for release from the steam generators is as follows:

Appendix E, Regulatory Position 5.5.1 - Both steam generators are used for plant cooldown. A portion of the primary-to-secondary leakage is assumed to flash to vapor based on the thermodynamic conditions in the reactor and secondary immediately following plant trip when tube uncovery is postulated. The primary-to-secondary leakage is assumed to mix with the secondary water without flashing during periods of total tube submergence.

Appendix E, Regulatory Position 5.5.2 - The portion of leakage that immediately flashes to vapor is assumed to rise through the bulk water of the SG, enter the steam space, and be immediately released to the environment with no mitigation; i.e., no reduction for scrubbing within the SG bulk water is credited.

Appendix E, Regulatory Position 5.5.3 - All of the SG tube leakage that does not flash is assumed to mix with the bulk water.

15.3.4-2b Amendment No. 26 (11/13)

Appendix E, Regulatory Position 5.5.4 - The radioactivity within the bulk water is assumed to become vapor at a rate that is a function of the steaming rate and the partition coefficient. A partition coefficient of 100 is assumed for the iodine. The retention of particulate radionuclides in the SGs is limited by the moisture carryover from the SG. The same partition coefficient of 100, as used for iodine, is assumed for other particulate radionuclides. This assumption is consistent with the SG carryover rate of less than 1%.

Appendix E, Regulatory Position 5.6 - Steam generator tube bundle uncovery in the SGs is postulated for up to 45 minutes following a reactor trip for St. Lucie Unit 1. During this period, the fraction of primary-to-secondary leakage which flashes to vapor is assumed to rise through the bulk water of the SG into the steam space and is assumed to be immediately released to the environment with no mitigation. The flashing fraction is based on the thermodynamic conditions in the reactor and secondary coolant. The leakage which does not flash is assumed to mix with the bulk water in the steam generator. A conservative uncovery time of 60 minutes was assumed in the analysis.

15.3.4.3.3.3 Other Assumptions

1. RG 1.183, Section 3.6 - The assumed amount of fuel damage caused by the non-LOCA events is analyzed to determine the fraction of the fuel that reaches or exceeds the initiation temperature of fuel melt and to determine the fraction of fuel elements for which fuel clad is breached. This analysis assumes DNB as the fuel damage criterion for estimating fuel damage for the purpose of establishing radioactivity releases. For the Locked Rotor event, Table 3 of RG 1.183 specifies noble gas, alkali metal, and iodine fuel gap release fractions for the breached fuel.

2. The initial RCS activity is assumed to be at the TS 3.4.8 limit of 1.0 µCi/gm Dose Equivalent I-131 and 518.9 µCi/gm DE XE-133 gross activity. The initial SG activity is assumed to be at the TS 3.7.1.4 limit of 0.1 µCi/gm Dose Equivalent I-131.

3. The steam mass release rates for the SGs are provided in Table 15.3.4-5.

4. The RCS fluid density used to convert the primary-to-secondary leakage from a volumetric flowrate to a mass flow rate is consistent with the RCS cooldown rate applied in the generation of the secondary steam releases. The high initial cooldown rate conservatively maximizes the fluid density. The SG tube leakage mass flow rate is provided in Table 15.3.4-6.

5. This RCS mass is assumed to remain constant throughout the event.

6. For the purposes of determining the iodine concentrations, the SG mass is assumed to remain constant throughout the event. However, it is also assumed that operator action is taken to restore secondary water level above the top of the tubes within a conservative time of one hour following a reactor trip.

7. This analysis assumes that the DNB fuel damage is limited to 19% breached fuel assemblies.

15.3.4-2c Amendment No. 26 (11/13)

15.3.4.3.3.4 Methodology Input assumptions used in the dose consequence analysis of the Locked Rotor event are provided in Table 15.3.4-4. This event is caused by an instantaneous seizure of a primary reactor coolant pump rotor. Flow through the affected loop is rapidly reduced, causing a reactor trip due to a low primary loop flow signal. Following the reactor trip, the heat stored in the fuel rods continues to be transferred to the reactor coolant. Because of the reduced core flow, the coolant temperatures will rise. The rapid rise in primary system temperatures during the initial phase of the transient results in a reduction in the initial DNB margin and fuel damage.

For the purpose of this dose assessment, a total of 19% of the fuel assemblies are assumed to experience DNB. The activity released from the fuel is assumed to be released instantaneously and homogeneously through the primary coolant. The source term is based upon release fractions from Appendix G of RG 1.183 with a radial peaking factor of 1.65. Primary coolant is released to the SGs as a result of postulated primary-to-secondary leakage. Activity is released to the atmosphere via steaming from the steam generator ADVs until the RCS is cooled to 212°F. These release assumptions are consistent with the requirements of RG 1.183.

For this event, the Control Room ventilation system cycles through three modes of operation:

Initially the ventilation system is assumed to be operating in normal mode. The air flow distribution during this mode is 920 cfm of unfiltered fresh air and an assumed value of 460 cfm of unfiltered inleakage.

After the start of the event, the Control Room is isolated due to a high radiation reading in the Control Room ventilation system. A 50-second delay is applied to account for diesel generator start time, damper actuation time, instrument delay, and detector response time. After isolation, the air flow distribution consists of 0 cfm of makeup flow from the outside, 460 cfm of unfiltered inleakage, and 1760 cfm of filtered recirculation flow.

At 1.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months into the event, the operators are assumed to initiate makeup flow from the outside to the control room. During this operational mode, the air flow distribution consists of up to 504 cfm of filtered makeup flow, 460 cfm of unfiltered inleakage, and 1256 cfm of filtered recirculation flow.

The Control Room ventilation filter efficiencies that are applied to the filtered makeup and recirculation flows are 99% for particulate, 95% elemental iodine, and 95% organic iodine.

15.3.4.3.3.5 Radiological Consequences The atmospheric dispersion factors (/Qs) used for this event for the Control Room dose are based on the postulated release locations and the operational mode of the control room ventilation system. The release-receptor point locations are chosen to minimize the distance from the release point to the Control Room air intake.

Releases are assumed to occur from the ADV that produces the most limiting /Qs. When the Control Room Ventilation System is in normal mode, the most limiting /Q corresponds to the worst air intake to the control room. When the ventilation system is isolated, the limiting /Q corresponds to the midpoint between the two control room air intakes. The operators are assumed to reopen the most favorable air intake at 1.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months . Development of control room atmospheric dispersion factors is discussed in Appendix 2J. These /Qs applied in the Seized Rotor analysis are summarized in Table 15.3.4-7.

15.3.4-2d Amendment No. 26 (11/13)

The EAB and LPZ dose consequences are determined using the /Q factors provided in Appendix 2I for the appropriate time intervals. For the EAB dose analysis, the /Q factor for the zero to two-hour time interval is assumed for all time periods. Using the zero to two-hour /Q factor provides a more conservative determination of the EAB dose, because the /Q factor for this time period is higher than for any other time period.

The radiological consequences of the Locked Rotor event are analyzed using the RADTRAD-NAI code and the inputs/assumptions previously discussed. As shown in Table 15.3.4-8, the results for EAB dose, LPZ dose, and Control Room dose are all within the appropriate regulatory acceptance criteria.

15.3.4-2e Amendment No. 24 (06/10)

DELETED 15.3.4-3 Amendment No. 18, (04/01)

DELETED 15.3.4-4 Amendment No. 18, (04/01)

TABLE 15.3.4-1 INITIAL CONDITIONS AND BIASING FOR REACTOR COOLANT PUMP ROTOR SEIZURE EVENT Parameter Value Core Power 3,020 MWt + 0.3%

Core Inlet Temperature 551°F RCS Flow Rate 375,000 gpm Pressurizer Pressure 2,250 psia Scram Reactivity 5000 pcm (bounding HFP minimum)

Moderator Temperature Coefficient +2 pcm/°F Doppler Reactivity Coefficient -0.80 pcm/°F Gap Conductance Bounding BOC value Pressurizer PORV Available Pressurizer Spray Available Pressurizer Heaters Disabled Low RCS Flow RPS Trip Credited Pressurizer Safety Valve Setpoint 2,500 psia + 3%

SG Tube Plugging 10%

15.3.4-5 Amendment No. 26 (11/13)

TABLE 15.3.4-2 SEQUENCE OF EVENTS FOR REACTOR COOLANT PUMP ROTOR SEIZURE EVENT Event Time Seizure of Pump 1A 0.0 Low RCS flow trip setpoint reached 0.168 Reactor scram (including trip response delay) 1.193 CEA insertion begins 1.693 MDNBR occurs 3.1 15.3.4-6 Amendment No. 26 (11/13)

DELETED 15.3.4-7 Amendment No. 26 (11/13)

TABLE 15.3.4-4 Reactor Coolant Pump Shaft Seizure (Locked Rotor) - Inputs and Assumptions Input/Assumption Value Core Power Level 3030 MWth (3020 + 0.3%)

Core Average Fuel Burnup 49,000 MWD/MTU Fuel Enrichment 1.5 - 5.0w/o Maximum Radial Peaking Factor 1.65 Percent of Fuel Rods in DNB 19%

Core Fission Product Inventory Table 15.4.1-1e 1.0 Ci/gm DE I-131 and 518.9 Ci/gm DE Initial RCS Equilibrium Activity XE-133 gross activity (Table 15.4.1-9)

Initial Secondary Side Equilibrium Iodine Activity 0.1 Ci/gm DE I-131 (Table 15.4.6-8)

Release Fraction from Breached Fuel RG 1.183, Section 3.2 Steam Generator Tube Leakage 0.5 gpm (Table 15.3.4-6)

Time to Terminate SG Tube Leakage 12.4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Secondary Side Mass Releases to Environment Table 15.3.4-5 SG Tube Uncovery Following Reactor Trip Time to tube recovery 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Flashing Fraction 5%

Steam Generator Secondary Side Partition Flashed tube flow - none Coefficient Non-flashed tube flow - 100 Time to Reach 212oF and Terminate Steam Release 12.4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 406,715 lbm Minimum mass used for fuel failure dose RCS Mass contribution to maximize SG tube leakage activity.

minimum - 120,724 lbm (per SG) maximum - 226,800 lbm (per SG)

Minimum used for primary-to-secondary SG Secondary Side Mass leakage to maximize secondary nuclide concentration. Maximum used for initial secondary inventory release to maximize secondary side dose contribution.

Atmospheric Dispersion Factors Offsite Appendix 2I Onsite Tables 15.3.4-7 Control Room Ventilation System Time of Control Room Ventilation System 50 seconds Isolation Time of Control Room Filtered Makeup Flow 1.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months Control Room Unfiltered Inleakage 460 cfm Breathing Rates Offsite RG 1.183 Section 4.1.3 Onsite RG 1.183 Section 4.2.6 Control Room Occupancy Factor RG 1.183 Section 4.2.6 15.3.4-8 Amendment No. 26 (11/13)

TABLE 15.3.4-4a DELETED EC292761 TABLE 15.3.4-5 LOCKED ROTOR STEAM RELEASE RATE Intact Steam Generator Time SteamRelease Flow Rate (hours)

(lbm/min) 0 5486 0.50 2821 0.75 2821 1.39 2821 2.00 2846 4.00 2846 6.00 2846 8.00 2846 10.50 2846 12.40 0.00 15.3.4-9 Amendment No. 30 (05/20)

TABLE 15.3.4-6 LOCKED ROTOR SG TUBE LEAKAGE Time Total SG Tube Leakage Flow Rate (lbm/min) 0 3.103 0.50 3.361 0.75 3.428 1.00 3.536 1.39 3.565 2.00 3.657 4.00 3.756 8.00 3.945 10.50 4.012 12.40 0.000 TABLE 15.3.4-7 CONTROL ROOM /Qs Time (hours) /Q (sec/m3) 0 6.30E-3 0.013889 2.84E-3 1.5 1.62E-3 2.0 1.32E-3 8.0 5.06E-4 24.0 3.88E-4 96.0 3.30E-4 720.0 3.30E-4 15.3.4-10 Amendment No. 26 (11/13)

TABLE 15.3.4-8 LOCKED ROTOR DOSE CONSEQUENCES EAB Dose (1) LPZ Dose (2) Control Room Dose (2)

Case (REM TEDE) (REMTEDE) (REM TEDE)

Locked Rotor 0.37 0.87 4.38 Acceptance Criteria 2.5 2.5 5 (1)

Worst 2-hour dose (2)

Integrated 30-day dose 15.3.4-11 Amendment No. 26 (11/13)

Reactor Power - Seized Rotor Event 120 100 ,...- -

80 r- -

a..

I-0:::

-;:R 0

60 r- -

Q) 3:

0 a..

40 r- -

20 t- -

0 0 5 10 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 REACTOR POWER SEIZED ROTOR EVENT FIGURE 15.3.4-1

Total Core Heat Flux Power- Seized Rotor Event 4000

~

3000 -

<1>

~

0 a..

X LL ro 2000

+-'

<1>

I

<1>

(.)

~;:,

(/)

"'C 0

0:: 1000 -

0 0 5 10 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 TOTAL CORE HEAT FLUX POWER SEIZED ROTOR EVENT FIGURE 15.3.4-2

Pressurizer Pressure - Seized Rotor Event 2400

~ 2300 en

(/)

~

a..

2200 2100 ~--~----~----~----~----~--~----~----~----~--~

0 5 10 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 PRESSURIZER PRESSURE SEIZED ROTOR EVENT FIGURE 15.3.4-3

RCS Loop Temperatures- Seized Rotor Event 640 620 -----------

~ 600

~ --Avg . Thot

s

~

(])

Avg . Tcold c..

E

~ 580 560 I --- ------------------- ----- ----- -- ------------------ il------------ --------------------- --- -- ----- -- -------

540 0 5 10 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 RCS LOOP TEMPERATURES SEIZED ROTOR EVENT FIGURE 15.3.4-4

RCS Total Loop Flow Rate- Seized Rotor Event 40000

-u (1)

(/)

E

.0 2

~ 30000

~

0 LL

(/)

ctl

2:

20000 10000 ~--~----~----~----~--~----~----~----~--~----~

0 5 10 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 RCS TOTAL LOOP FLOW RATE SEIZED ROTOR EVENT FIGURE 15.3.4-5

Reactivity Feedback- Seized Rotor Event 2.0 ~----~----~----~----~----~ ~ ----~----~----~----~--~

0.0 - - - -- - - "-'"'--~---; : :;.-"';,; :-****"'-;: -***.:- *:; * ,-~-"'-~--~------~-"-~--::-::.:ri.::-~--~-~-~--~-~-~--~-~--~--~-~--~--~-~--~--~-*******-***-**---------------****************-

-. - 2.0 E:i7

* T ota I

-*****---*-*-* Moderator

- - - -

Doppler I - - --.Scram

- 6.0

-8.0 L _ __ _ . . _ __ . _ __ __ . _ __ ___.___ _

' - __ J___ _ _ _ _ _____J_ '---

_ -_-.--=--_-_.-_

_ -_-_- _,-_-_-_-____J -

0 5 10 Time (s)

Amendment No. 26 (11/13)

FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 REACTIVITY FEEDBACK SEIZED ROTOR EVENT FIGURE 15.3.4-6