L-2017-074, Redacted - St. Lucie, Unit 1, Updated Final Safety Analysis Report, Amendment No. 28, Chapter 6, Engineered Safety Features
Text
CHAPTER 6 LIST OF TABLES (Cont'd)
Table Title Page 6.2-5 I Reflood/Post
-Reflood Mass and Energy Release Rates for 9.82 Ft 2 Double Ended Discharge Leg Slot Break, Max SI 6.2-171c 6.2-5 J Spillage and Condensation Mass and Energy Release Rates 9.82 Ft 2 Double Ended Discharge Leg Slot Break, Max SI 6.2-171e 6.2-5 K Reflood/Post
-Reflood Mass and Energy Rele ase Rate s 9.82 Ft 2 Double Ended Discharge Leg Slot Break, Min SI 6.2-171g 6.2-5 L Spillage and Condensation Mass and Energy Release Rates for 9.82 Ft 2 Double Ended Discharge Leg Slot Break, Min SI 6.2-171i 6.2-5 M Blowdown Mass and Energy Release Rates for 9.82 Ft 2 Double Ended Suction Leg Slot Break 6.2-171k 6.2-5 N Reflood/Post
-Reflood Mass and Energy Release Rates for 9.82 Ft 2 Double Ended Suction Leg Slot Break, Min SI 6.2-171m 6.2-5 O Spillage and Condensation Mass and Energy Release Rates for 9.82 Ft 2 Double Ended Suction Leg Slot Break, Min SI 6.2-171o 6.2-5 P Blowdown Mass and Energy Release Rates for 19.24 Ft 2 Double Ended Hot Leg Slot Break 6.2-171r 6.2-5 Q Mass and Energy Release Rates for 100.3% Power MSLB With Failure of a Containment Spray Pump 6.2-171t 6-via Amendment No. 26 (11/13)
CHAPTER 6 LIST OF TABLES (Cont'd)
Table Title Page 6.2-6 Description of Assumptions Used in Shield Building Annulus Transient Analyses 6.2-172 6.2-6a Containment Pressure and Temperature vs. Time for the 6.2-172a Limiting LOCA Case 6.2-7 Containment Structure Pressure and Radiation Instrumentation Application 6.2-174 6.2-8 Design Data for Containment Spray System Components 6.2-175 6.2-9 Design Data for Containment Cooling System Components 6.2-178 6.2-9A NPSH Calculations for ECCS/CHR Pumps 6.2-179 6.2-10 Single Failure Analysis
- Containment Heat Removal System 6.2-189 6.2-11 Containment Spray System Instrumentation Application 6.2-191 6.2-12 Containment Cooling System Instrumentation Application 6.2-192 6.2-13 Design Data for Shield Building Ventilation System Components 6.2-193 6.2-13A Comparison of Safety Related Air Filtration Systems With Regulatory Positions of Regulatory Guide 1.52 6.2-196 6.2-14 Single Failure Analysis
- Shield Building Ventilation System 6.2-200 6.2-15 Shield Building Ventilation System Instrumentation Application 6.2-201 6.2-16 Containment Penetration and Isolation Valve Information 6.2-202 6.2-17 Design Data & Materials for Hydrogen Purge System 6.2-207 6.2-18 Single Failure Analysis
- Hydrogen Control and Sampling System 6.2-211 6.2-19 Comparison of MHA Hydrogen Generation Assumptions 6.2-21 2 6.2-20 Hydrogen Generated by Corrosion of Galvanized Surfaces 6.2-213 6.2-21 Containment Hydrogen Purge and Sampling System Instrumentation 6.2-214 6.2-22 Iodine Removal System Parameters 6.2-215 6.2-23 Nozzle Number 1C
-304 SS 6.3
- Test Data 6.2-218 UNIT 1 6-vii Amendment No. 27 (04/15)
CHAPTER 6 LIST OF TABLES (Cont'd)
Table Tit le Page 6.2-24 Design and Performance Data Specified for Hydrogen Analyzer System 6.2-219 6.3-1 Safety Injection System Process Data Point Tabulation 6.3-43 6.3-2 Component Design Parameters 6.3-4 4 6.3-2A Containment Heat Sinks for ECCS Analysis 6.3-46 6.3-3 Single Failure Analysis Safety Injection System 6.3-87 6.3-4 Administrative Error Analysis
- Safety Injection System Valves 6.3-96 6.3-5 Analysis Input Parameters 6.3-98 6.3-6 Containment Physical Parameters 6.3-100 6.3-7 Times of Interest (Seconds) 6.3-104 6.3-7a Clad Rupture Times 6.3-105 6.3-8 Variables Plotted as a Function of Time for Each Large Break in the Spectrum 6.3-106 6.3-8a Additional Variables Plotted as a Function of Time for the Large Break Having the Highest Clad Temperature 6.3-107 6.3-9 Isolated Safety Injection Tank General System Parameters 6.3-108 6.3-10 Isolated Safety Injection Tank Variables Plotted for the 0.8 x Double-Ended Guillotine Break in Pump Discharge Leg (0.8 x DEG/PD) 6.3-109 6.3-11 Isolated Safety Injection Tank Rupture Time, Peak Clad Temperature and Oxidation Percentages 6.3-110 6.3-12 Blowdown Mass and Energy Release 1.0 DEG/PD Break 6.3-111
UNIT 1 6-viii Amendment No. 27 (04/15)
CHAPTER 6 LIST OF TABLES (Cont'd)
Table Title Page 6A-1 Defining Variables for SGNIII Steam Generator Secondary Model 6A-47 6A-2 Moody Critical Flow Rates (fL/D=0.0) 6A-48 6A-3 Moody Critical Flow Rates (fL/D=5.0) 6A-49 6A-4 Moody Critical Flow Rates (fL/D=10.0) 6A-50 6B-1 Off-site Atmospheric Dilution Factors 6B-24 6B-2 Physical Properties of Charcoal Adsorber 6B-25 6C-1 Failure Mode Effects Analysis
- Mini Flow Isolation Valve Power Interruption 6C-13b 6C-2 Plant Design Data Used in the Pre-EPU Boric Aci d Precipitation Analysis 6C-13 c 6C-2a Plant Design Data Used in the EPU Boric Acid Precipitation 6C-13ca Analysis 6C-3 Summary of Results Pre-EPU 6C-13 d 6C-3a Summary of Results for the EPU Boric Acid Precipitation Analysis 6C-13e
6-ix Amendment No. 26 (11/13)
ENGINEERED SAFETY FEATURES CHAPTER 6 LIST OF FIGURES Figure Title 6.2-1 Reactor Pressure Nodes 6.2-1A Containment Pressure vs Time for M in SI, DEHLS 6.2-1B Containment Temperature vs. Time for M in SI, DEDLS 6.2-1C Component Cooling Water Temperature vs. Time for Min SI, DEHLS
6.2-1D Deleted
6.2-1E Deleted
6.2-1F Deleted
6.2-2A Deleted
6.2-2B Deleted
6.2-2C Deleted
6.2-3A Deleted
6.2-3B Deleted 6.2-3C Deleted 6.2-4A Deleted
6.2-4B Deleted
6.2-4C Deleted
6.2-5A Deleted
6.2-5B Deleted
6.2-5C Deleted
6-x Amendment No. 26 (11/13)
CHAPTER 6 LIST OF FIGURES (Cont'd)
Figure Title 6.2-6A Deleted
6.2-6B Deleted
6.2-6C Deleted
6.2-7A Deleted
6.2-7B Deleted
6.2-8A Del eted 6.2-8B Deleted
6.2-9A Deleted
6.2-9B Deleted
6.2-10A Deleted
6.2-10B Deleted
6.2-11A Deleted
6.2-11B Deleted 6.2-12 Containment Pressure Response 10 0.3% Power Limiting Peak Pressure Case Steamline Break 6.2-13 Containment Temperature Response 10 0.3% Power Limiting Peak Temperature Case Steamline Break
6.2-14 Deleted
6.2-15 Area of Flow Guillotine Break of Reactor Coolant Pipe into Reactor Cavity 6.2-16 Slot Break of Reactor Coolant Pipe (Historical)
6-xi Amendment No. 26 (11/13)
CHAPTER 6 LIST OF FIGURES (Cont'd)
Figure Title 6.2-17A Reactor Cavity Model (Historical) 6.2-17B Reactor Cavity Model (Historical) 6.2-17C Relief Dampers Model (Historical) 6.2-17D Insulation and Restraints for Piping through Shield Wall Primary (Historical) 6.2-17E Reactor Cavity Plan and Sections (Historical) 6.2-17F Reactor Cavity Cutaway Isometric (Historical) 6.2-18A 4.91 ft 2 Cold Leg Slot Break (Historical) thru 6.2-18R 6.2-19A 4.0 ft 2 Cold Leg Guillotine Break (Historical) thru 6.2-19R 6.2-20A 3.44 ft 2 Hot Leg Guillotine Break (Historical) thru 6.2-20R 6.2-21 Secondary Shield Wall Compartment Differential Pressure Transient for Hot Leg Guillotine Break (Historical) 6.2-22 Annulus Pressure vs. Time for a 9.82 ft 2 Double Ended Suction Leg Break 6.2-22a Shield Building Annulus Pressure Transient for the Limiting LOCA Case (DEHLS) 6.2-23 Condensing Heat Transfer Coefficient vs Time for the Limiting LOCA Case (DEHLS) 6.2-24 Shield Building Annulus Temperature Transient for the Limiting LOCA Case (DEHLS) 6.2-25 Deleted 6.2-26 Deleted 6.2-27 Containment Pressure vs. Time for 2.04 ft 2 Break with Only One Spray or Four Fans Operating
6-xii Amendment No. 26 (11/13)
CHAPTER 6 LIST OF FIGURES (Cont'd)
Figure Title 6.2-28 Flow Diagram Containment Spray and Refueling Water Systems
6.2-29 Containment Spray Pumps Performance Characteristics
6.2-30 Containment Cooling System Fan Characteristics 6.2-31 Post-LOCA Sequence of Operation of SBVS (Historical)
6.2-32 Shield Building Ventilation System Fan Characteristics
6.2-33 Deleted
6.2-33A Total Hydrogen Production Reanalysis Results Including NAOH Sprays; Zinc Base Paint and Others
6.2-34 Total Radiolytic Hydrogen Production - Applicant Model
6.2-35 Total Radiolytic Hydrogen Production - AEC Safety Guide 7 Model
6.2-36 Total Hydrogen Production (Reference Case) - Applicant Model
6.2-37 Total Hydrogen Production - Applicant Model
6.2-38 Total Hydrogen Production (Reference Case) - AEC Safety Guide 7 Model
6.2-39 Total Hydrogen Production - AEC Safety Guide 7 Model
6.2-40 Containment Sump Suction Strainers
6.2-41 SBVS Charcoal Decay Heating vs Time Following DBA
6.2-42 SBVS Charcoal Absorber Air Temperature Rise at Time of Maximum Delay Heating Following DBA vs. Cooling Air Flow
6.2-43 Deleted
6.2-44 Deleted
6.2-45 Deleted 6.2-45A Electric Hydrogen Recombiner Cutaway 6.2-46 Deleted
6-xiii Amendment No. 26 (11/13)
CHAPTER 6LIST OF FIGURES (Cont'd)FigureTitle6.2-47Instrument Air to Vacuum Relief Valves6.2-48AIntentionally Deleted thru 48D6.2-49aPressure Multinode Analysis Model 6.2-49bPressurizer Relief Line Break-Pressure Response 6.2-49cPressurizer Spray Line Break-Pressure Response 6.2-50Containment Spray Piping Plan 6.2-51Containment Spray Piping Sections 6.2-52Intentionally Deleted 6.2-53Spray Analyzer 6.2-54Flow Coefficient vs. Disc Angle and Opening Time 6.2-55Vacuum Relief Flow Rate vs. Differential Pressure 6.2-56Differential Pressure vs. Time 6.3-1Flow Diagram Safety Injection System6.3-2Flow Diagram Safety Injection System6.3-2AECCS Operational Analysis Diagram 6.3-3Low Pressure Safety Injection Pump Performance 6.3-4High Pressure Safety Injection Pump Performance 6.3-5Deleted6.3-5aDeleted6.3-5bDeleted6.3-5cDeleted6.3-5d.1Deleted6.3-5d.2Deleted6-xivAmendment No. 16 (1/98)
CHAPTER 6LIST OF FIGURES (Cont'd)FigureTitle6.3-5eDeleted6.3-5fDeleted6.3-5gDeleted6.3-5hDeleted6.3-6Deleted6.3-6aDeleted6.3-6bDeleted6.3-6cDeleted6.3-6d.1Deleted6.3-6d.2Deleted6.3-6eDeleted6.3-6fDeleted6.3-6gDeleted6.3-6hDeleted6.3-7Deleted6-xvAmendment No. 16 (1/98)
CHAPTER 6LIST OF FIGURES (Cont'd)FigureTitle6.3-7aDeleted6.3-7bDeleted6.3-7cDeleted6.3-7d.1Deleted6.3-7d.2Deleted6.3-7eDeleted6.3-7fDeleted6.3-7gDeleted6.3-7hDeleted6.3-8Deleted6.3-8aDeleted6.3-8bDeleted6.3-8cDeleted6.3-8d.1Deleted6-xviAmendment No. 16 (1/98)
CHAPTER 6LIST OF FIGURES (Cont'd)FigureTitle6.3-8d.2Deleted6.3-8eDeleted6.3-8fDeleted6.3-8gDeleted6.3-8hDeleted6.3-8iDeleted6.3-8jDeleted6.3-8kDeleted6.3-81Deleted6.3-8mDeleted6.3-8nDeleted6.3-8oDeleted6.3-8pDeleted6.3-8qDeleted6.3-8rDeleted6-xviiAmendment No. 16 (1/98)
CHAPTER 6LIST OF FIGURES (Cont'd)FigureTitle6.3-8sDeleted6.3-8tDeleted6.3-8uDeleted6.3-9Deleted6.3-9aDeleted6.3-9bDeleted6.3-9cDeleted6.3-9d.1Deleted6.3-9d.2Deleted6.3-9eDeleted6.3-9fDeleted6.3-9gDeleted6.3-9hDeleted6.3-10Deleted6.3-10aDeleted6-xviiiAmendment No. 16 (1/98)
CHAPTER 6 LIST OF FIGURES (Cont'd)
Figure Title 6B-5 Post-LOCA Doses (Function of Time and Distance) Backfit Design
6C-1 Post-LOCA Reactor Vessel Boric Acid Concentration
6C-2a Solubility of Boric Acid in Water vs. Temperature
6C-2b Solubility of Boric Acid in Water vs. Temperature 6C-3 Reactor Vessel Regions (Historical) 6C3a Reactor Vessel Regions
6C-6 Mini-Flow Isolation Valve Control Room Power Control 6C-7 Comparison of Core Boiloff Rate and Hot Side Injection Flow Rate of 190 gpm (Historical) 6C-7a Comparison of Core Boiloff Rate and Hot Side Injection Flow Rate of 229 gpm 6C-8 Core Boric Acid Concentration vs. Time (Historical) 6C-8a Core Boric Acid concentration vs. Time
6-xx Amendment No. 26 (11/13)
CHAPTER 6ENGINEERED SAFETY FEATURES6.1GENERALThe types of engineered safety features provided to mitigate the consequences of accidents which release largeamounts of energy within the containment structure are the following:a)Containment Structure b)Containment Spray System (including Iodine Removal System) c)Containment Cooling System d)Shield Building Ventilation System e)Containment Isolation System f)Hydrogen Control System g)Safety Injection System6.1.1CONTAINMENT STRUCTUREThe containment structure is a steel containment vessel surrounded by a reinforced concrete shield building. Thetwo structures are separated by an annular air space. The containment vessel is a low leakage cylindrical steel shell with hemispherical dome and ellipsoidal bottom. The vessel is designed to contain the radioactive material that could be released from a loss of integrity of the reactor coolant pressure boundary. The shield building is a medium leakage concrete structure which protects the containment vessel from external missiles, provides biological shielding, and provides a means of controlling radioactive fission products that leak from the containment if an accident should occur. Detail design information for the containment structure is presented in Section 3.8.2.6.1.2CONTAINMENT SPRAY SYSTEM The containment spray system removes heat from the containment by spraying a borated water and sodiumhydroxide solution through the containment atmosphere. The spray system is automatically initiated by the containment spray actuation signal (CSAS) which requires a coincidence of the safety injection actuation signal (SIAS) and the high-high containment pressure signal.The containment spray system consists of two redundant 100 percent capacity subsystems each consisting of aspray pump, shutdown heat exchanger and spray header. The spray system does not operate during normal operation. The Iodine Removal System is described in Section 6.2.6.6.1.3CONTAINMENT COOLING SYSTEM The containment cooling system removes heat by passing containment air over coils cooled by the componentcooling water system.The system consists of four cooling units each of which consists of a cooling coil served by the component cooling system and a centrifugal exhaust fan. During normal operation, three of the four units are in service. On receipt of SIAS, the fourth unit is automatically energized6.1-1Amendment No. 17 (10/99)
assumptions regarding the amount of moisture carryover in the steam release, the MSLB can also produce containment temperatures well in excess of the LOCA. These elevated temperatures, however, are typically of short duration and in most cases will not impact the operation of in-containment equipment or challenge the design structural temperature limit. The duration of the MSLB is also short, relative to the LOCA, and does not have the potential for a significant radiological release. As a result, the requirements for operation of post-accident safety related equipment are limited when compared to the long term cooldown associated with the LOCA. For these reasons, the post-accident requirements for a LOCA were typically used as the basis for engineered safety feature equipment design, integrated leakage rate testing (ILRT) limits, and long term EQ requirements.
As can be inferred by the above discussion, the analysis of the LOCA requires a greater level of detail than the MSLB. While the MSLB transient largely consists of the blowdown phase, the LOCA is represented by four distinct phases. As described in greater detail in subsequent sections, these are characterized by the blowdown, reflood, post-reflood, and long term phases. As a result, the LOCA analysis requires the use of three different computer codes versus one for the MSLB.
The original analysis of the LOCA for the St. Lucie 1 plant was split by Combustion Engineering and EBASCO. A parametric study of break sizes was analyzed by Combustion Engineering using the early version of the NRC approved CEFLASH and FLOOD-MOD2 computer codes. These codes provided data from the initiation of the event through the end of blowdown for the hot leg breaks and end of post-reflood for the cold leg breaks. The mass and energy release data associated with a sample of breaks was provided to EBASCO for the containment pressure and temperature response calculation. The long term phase was also conducted by EBASCO utilizing the primary and secondary conditions present at the end of these intervals.
The assumptions associated with these analyses were based on plant conditions and Regulatory requirements present at that time. The most significant of these was the initial power level of 2560 MWt.
Following the initial FSAR writeup, a number of plant changes, Regulatory requirements, and methodology and modelling enhancements occurred. While these changes were addressed, they had been performed on a piecemeal basis. A pre-EPU analysis, discussed below, was performed to consolidate prior updates and changes. This included a recalculation of all mass and energy release data and both the short and long term containment pressure and temperature response. While many enhancements in methodology, computer codes, and inputs were incorporated, the bounds of the analysis were also extended. This extension was the modelling of the Component Cooling Water (CCW) and Intake Cooling Water (ICW) systems.
The CCW/ICW modelling was developed to address limiting CCW/ICW parameters for the St. Lucie 2 plant.
As described in subsequent sections, this modelling was an extension of ABB C-E's NRC approved CONTRANS containment code. While past containment analyses have assumed a fixed CCW temperature , this model simulated the transfer of containment heat through the CCW and ICW loops back to the ultimate heat sink. This model was developed and tested using FPL supplied data for St. Lucie Units 1 & 2. In this manner, fan cooler heat and shutdown cooling heat exchanger (SDCHX) capacity was a time varying function based on the transient calculation of Component Cooling Water temperature. For St. Lucie 1, the additional heat loads of High Pressure Safety Injection (HPSI), Low Pressure Safety Injection (LPSI), and containment spray pumps were also added to the CCW loop. The prior considerations of peak accident heat load required for the conservative hand calculations of the past were no longer necessary or considered to be a critical parameter.
With this approach, the analysis took on a more realistic quality by coupling the old analysis bounds with those plant components and systems commonly assumed in the past as fixed inputs. Important items such as the ICW heat exchanger overall heat transfer coefficients, which addressed fouling and tube pluggage, along with more accurate ICW flow rates and ultimate heat sink temperature all served as design inputs to 6.2-2 Amendment No.
26 (11/13) the analysis. Therefore, along with the typical plant analysis criteria of peak containment pressure and EQ temperature, the peak CCW temperature was also added.
The results of the EPU analysis and EPU are presented in the transient analysis sub-section of the containment analysis section. The analysis has been done in general accordance with the SRPs, with enhanced methods and inputs, resulting in the results showing a less severe response than those originally predicted. A summary table of past LOCA containment results has been included for historical referral. The coupled modeling of mass and energy release to containment and CCW/ICW response has provided a unique analysis of the overall plant performance during a design basis LOCA. .
c) Contribution of Engineered Safety Featur es The accident analysis is based on Regulatory models such as those prescribed in the NRC's Standard Review Plan. Assumptions regarding safety injection and containment active heat removal devices have been incorporated into the analysis, within the standard methods for single failure assumptions. The containment is equipped with the following ESF equipment to mitigate the consequences of an inside containment break.
- Safety Injection - 4 safety injection tanks
- 2 high pressure safety injection pumps
- 2 low pressure safety injection pumps
- Primary Containment Cooling (Operational during Injection and Recirculation modes)
- 4 containment fan coolers
- 2 containment spray pumps
- 2 shutdown cooling heat exchangers
- Containment Cooling Heat Sink - 2 Component Cooling Water loops - 2 CCW/ICW heat exchangers
- 2 Intake Cooling Water trains The SL-1 accident analyses assume the most limiting combination of the above equipment for the loss of offsite power scenario with component and train failures considered. For the EPU LOCA analysis, the assumptions related to the CCW and ICW systems produced more restrictive single failure assumptions than that previously analyzed. For consistency with the original SL-1 design basis analyses, the LOCA event was analyzed with minimum safety injection. Minimum SI refers to the operation of one HPSI and one LPSI without offsite power. For each scenario, the loss of the limiting containment active cooling device (component or train) was assumed.
Following a LOCA, heat in the containment is rejected to the CCW by the air/water heat transfer in the containment fan coolers. The containment sprays take suction from the refueling water tank (RWT) and remove energy from the vapor space as the atomized spray water is heate
- d. During the injection mode, the spray pump is aligned to the RWT. The spray pump mini recirculation line back to the RWT is closed to prevent introduction of sodium hydroxide into the aluminum RWT. As the pump start signal and containme nt isolation valve open signal are generated by the same source, the pump is protected from operating against a closed valve during the normal alignment for accident mitigation.
Following the generation of the recirculation actuation signal (RAS), the spray pump suction is aligned to the containment sump. The generation of the RAS is based on the technical specification minimum water level. Following RAS, containment heat is rejected to the CCW via the water/water heat transfer in the shutdown cooling heat exchangers.
6.2-3 Amendment No. 26 (11/13)
Other equipment such as the HPSI, LPSI, and containment spray pumps also transfer heat to the CCW. This heat is then transferred to the ultimate heat sink via the ICW heat exchanger. While not modelled in the containment P/T analysis, each of the two shield building ventilation system fan sub-systems is capable of removing the post-LOCA energy increase in the shield building annulus.
d) Analysis Assumptions
The assumptions of the accident analyses are summarized in Section 6.2.1.3.2.B.
e) Compartment Differential Pressures Shield building annulus pressurization and compartmental pressure differentials were considered in the original containment design. Since then, however, the NRC revised General Design Criteria (GDC) 4 to eliminate the consideration of dynamic effects of a loss of coolant accident from the plant design bases. The dynamic effects of a LOCA include the effects of missiles, pipe whipping, discharging fluid (i.e., jet impingement), decompression waves within the ruptured pipe and dynamic or nonstatic pressurization in cavities, compartments, and subcompartments. The specific pressurization events that were considered in the original and latter design are described below. The mechanical/structural loading effects of compartment pressurization from circumferential (guillotine) or longitudinal (slot) breaks in RCS hot leg or cold leg piping are no longer considered a design basis (Reference 12 NRC acceptance letter). The environmental qualification design basis for safety related equipment inside containment remains unchanged.
Shield building annulus pressurization considers the effects of energy flow into the annulus air space during a LOCA. Energy is added to the annulus from leakage, convection from the hot steel containment, and from the concrete shield building after it has been heated by radiant heat transfer from the steel.
The relative amounts of energy and mass of air and water vapor in the annulus as a function of time determines the annulus pressure, temperature and humidity transients. The results of the calculations are presented in Section 6.2.1.3.
Pressure transients resulting from a reactor coolant system piping rupture within the reactor cavity, between the reactor vessel and the primary shield wall, and within the enclosed volume inside the secondary shield wall below the operating floor have been calculated. The calculations are based on conservation of mass, momentum and energy. The blowdown mass is assumed to flash to the cavity or compartment pressure. As the pressure builds up within the compartment, the steam-air mixture flows through openings into the main containment. The maximum pressure differential depends on the number and shape of the openings between the compartments, the volume of each compartment and the blowdown rate from the broken pipe.
For the secondary shield wall compartment, only the double-ended guillotine break in the hot leg is considered, since it provides the largest rate of mass and energy into the compartment. Compartments adjacent and opening to the secondary shield wall, such as the pressurizer cavity, are designed to the same pressure loads as the secondary shield wall.
Structural design criteria for the containment structure are provided in Section 3.8.2.
f) Non-Seismic Class I Equipment in Containment All non-seismic Class I equipment located in the containment has been analyzed for the effects of their failure on safety related equipment.
6.2-4 Amendment No.
26 (1 1/13)
In each case the criterion adopted was that the failure of the equipment could not affect safety related equipment. Where this could not be demonstrated the component was either moved, specified as seismic Class I or restrained with seismic Class I restraints. See Table 6.2-1A for a list of typical non-seismic Class equipment inside the containment.
Typical non-seismic Class I components located inside containment are communications handsets, speaker signal lamps, lighting panels, lighting fixtures, toggle switches, control box stations, power receptacles, stairs, sump pumps and various small size tanks.
6.2.1.2 System Design
The containment vessel is a low leakage steel shell, including all its penetrations, designed to confine the radioactive materials that could be released by accidental loss of integrity of the reactor coolant pressure boundary. Physically, the containment vessel is a right circular cylinder with hemispherical dome and ellipsoidal bottom which houses the reactor pressure vessel, the reactor coolant piping and pumps, the steam generators, the primary coolant pressurizer and pressurizer quench tank, and other branch connections of the reactor coolant system including the safety injection tanks.
The shield building is a medium leakage reinforced concrete structure surrounding the containment vessel and is designed to provide biological shielding during normal operation and LOCA conditions, environmental protection for the containment vessel from adverse atmospheric conditions and external missiles, and a means for collection and filtration of fission product leakage from the containment vessel following a LOCA.
Physically, the shield building is a right circular cylinder with a shallow dome roof.
The cylindrical walls of the containment vessel and the shield building are separated by a 4.0 f eet annular space. A minimum clearance of 4.0 f eet is also provided between the containment vessel and the dome of the shield building. The volume contained within the annulus is approximately 543,000 cubic f eet. The containment structure general arrangement is shown in Figure 1.2-
- 8.
Both the containment vessel and the shield building are supported on a common foundation slab. There are no other structural ties between the containment vessel and the shield building with the exception of the concrete base under the containment vessel. The absence of structural ties assures freedom for differential movement between the two main components of the containment structure.
The containment vessel is designed in accordance with the ASME Code Section III, Class MC. The "maximum internal pressure" as defined in Article NE-3112 of the code is 44 psig. The coincident temperature is 264°F. The design internal pressure referred to as "maximum calculated peak internal pressure" as defined in Article NE-3112 is 42.77 psig. The calculated maximum containment vessel liner temperature is 245.69 o F.
An analysis was performed to determine the maximum probable temperature and pressure inside containment during a Station Blackout (SBO) of a four (4) hour duration. Combustion Engineering's CONTRANS code was utilized for this analysis and factors such as solar heat load, heat transferred from hot equipment and structures and an energy transfer from RCS leakage were accounted for. It was assumed that no active containment heat removal systems were operating during the postulated event. The factor that most affected the heat-up and pressurization of the containment was determined to be the Reactor Coolant System (RCS) leak rate. The analysis assumed an initial RCS leakage rate of 120 gpm; the leakage is pressure dependent and therefore decreasing with RCS pressure. This is conservative with respect to the Station Blackout analysis assumptions provided in Section 15.2.13. The calculated peak temperature is 144.15 oF and peak
6.2-5 Amendment No. 26 (11/13)
- 6. An accepted Jens Lottes two phase heat transfer correlation is used for the core to coolant heat transfer whenever the flow through the core is not pure steam.
- 7. A maximum core inlet temperature (including uncertainty) and Technical Specification minimum core flowrate are assumed to maximize the available stored energy in the RCS.
- 8. The core is modelled as 1 radial zone and 5 axial zones. This allows sufficient nodal detail for containment related blowdown calculations.
- 9. Heat transfer across the steam generator tubes during the transient is modelled with the initial steady state full power overall heat transfer coefficient in both the forward and reverse directions. This is conservative since it maintains a forced convection heat transfer coefficient on the primary side and a nucleate boiling heat transfer coefficient on the secondary side during the LOCA blowdown. Although the RCPs are tripped at the initiation of the transient, this heat transfer coefficient is maintained throughout the transient as a conservative prediction of primary side heat transfer. On the secondary side, the reactor trip following the LOCA would in reality result in a turbine trip which would close the turbine stop valves and the secondary side heat transfer coefficient would decrease to a small natural convection coefficient. Using the initial steady state full power overall heat transfer coefficient conservatively maximizes the reverse heat transfer.
- 10. No RSG tubes are assumed to be plugged.
Minimizing tube pluggage increases the secondary to primary heat transfer, increases the RCS volume, and minimizes the loop resistance. These effects contribute to a conservative mass and energy release.
- 11. The decay heat model used in the blowdown calculation is representative of the 1971 ANS standard.
- 12. The treatment of steam and feedwater flow is handled via input Thus, steam flow is terminated by the closure of the stop valves following reactor trip on high containment pressure plus appropriate signal delays. Feedwater flow is added as a function of isolation valve position over time following MSIS on containment high pressure plus signal delays. For St. Lucie 1, feedwater terminates after the end of blowdown.
A.2 Description of Core Reflood and Post-Reflood Model
Reflood and Post-Reflood mass and energy release rates of the LOCA are calculated using the FLOOD3 computer code (Ref. 12). Since the refill period (the interval when the reactor vessel refills to the bottom of the active core) is conservatively omitted for containment calculations for containment heat removal considerations, reflood is assumed to follow the initial blowdown phase. The reflood phase is defined as the interval when the reactor vessel level rises, due to safety injection, from the bottom of the active core to the point that the core is quenched. Per SRP Section 6.2.1.3, this is the point at which the level rises to two feet below the top of the active core. The post-reflood period is the interval following the end of reflood to the point that the RCS and steam generators are essentially in equilibrium.
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The FLOOD3 code is an extension of the NRC approved FLOOD-MOD2 code (Ref. 13) which was used for the initial design basis analyses. The FLOOD-MOD2 code required separate heat transfer considerations in order to select fluid densities and did not allow time dependent densities. Consequently it was difficult, if not impossible, to analyze all possible parametric variations either rigorously or consistently when using FLOOD-MOD2. FLOOD3 uses the FLOOD-MOD2 hydraulics, and reproduces the FLOOD-MOD2 hydraulic solution when consistent sets of hydraulic data are used. FLOOD3 differs from its predecessor in that:
- Intact and broken loops are individually treated,
- Specific volumes of the fluids in the primary loop can be varied with time,
- A uniform methodology for both the Reflood and Post-Reflood time frames is used,
- A more rigorous heat transfer scheme is used for treating the transfer of energy from the loop and steam generator walls to the fluid in the primary loop,
- Containment back pressure may vary with time,
- Safety injection flow rates may be interpolated from a curve or computed explicitly.
- The fluid in the reactor vessel is heated mechanistically, as opposed to assuming saturated liquid in the core.
The intent of the reflood and post-reflood analysis is to extract heat from the hot steam generators following the blowdown phase. Since there is no mechanistic way for exiting steam to pass through the steam generator U-tubes for a hot leg break, the reflood analysis is only conducted for the cold leg breaks. This analysis assumes breaks in the suction and discharge legs.
For the reflood and post-reflood analysis, heat transfer is conservatively modelled for core, vessel walls, vessel internals, loop metal, steam generator tubes, steam generator inventory, and steam generator secondary walls. The FLOOD3 code hydraulics calculates loop flow rates and pressure. The heat transfer process predicts fluid enthalpies and fluid densities that are calculated as functions of pressure and enthalpy. The conservatisms in the model are as follows:
A. A one-dimensional heat transfer model is used for all wall heat transfer calculations. It has been demonstrated in past ABB C-E analyses via comparisons of one-dimensional models and otherwise identical two-dimensional models that one-dimensional modelling is conservative.
B. A nucleate boiling heat transfer coefficient of 10,000 Btu/hr-ft²-F is used to model the heat transfer from the steam generator tubes to the fluid. This coefficient represents an upper limit, and is conservatively used at all times throughout the tubes.
C. During reflood, calculations are made on the steam generator inventories to predict the liquid levels. As the secondary side contracts, a portion of the U-tubes uncovers. A conservative condensation heat transfer coefficient is used in conjunction with the tube area exposed to steam. A realistic natural circulation coefficient is calculated for the rest of the tube area.
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The post-reflood model is identical to the reflood model except that, at the end of reflood, the CRF is changed from 0.8 to 1.0. This conservatively increases the system flow rates due to the increased CRF. The flow rates are further enhanced by the fact that the core liquid height is now constrained at the 9.39 foot level, which maximizes the available driving head between the annulus level and the core in the FLOOD3 flooding equation. All heat transfer coefficients are kept at the values used for the reflood analysis. Condensation is analyzed as previously described, however, there is not sufficient spillage to completely thermodynamically condense the steam so that credit for condensation has not been taken.
A.3 Description of Long-Term Cooling Model
The heat generation rate from shutdown fissions, heavy isotope decay, and fission product decay is considered during this phase of the LOCA event. For conservatism mandated by the SRPs, the long-term analysis assumes that decay heat is added to the reactor vessel water at 20% greater rate than that predicted by the decay heat curve.
Following the post reflood period outlined above, the mass/energy source terms for long-term containment analysis are computed concurrently with the containment back pressure in the CONTRANS containment code. The steam flows out the break will be a function of the depressurization of the containment, decay heat (plus margin) and primary metal-to-primary fluid heat transfer. The steam generator secondary fluid, tube, thick and thin metal stored energy are used to superheat the steam prior to discharge into the containment.
The long-term energy release data is based on the containment pressure and the following calculational method:
The reactor coolant system is assumed to be a vessel containing a constant volume of saturated water. The pressure in the vessel is assumed to be the containment pressure. SIS water is injected in the vessel.
Steam is formed at a rate determined by decay heat, RCS metal-to-coolant heat transfer and the rate of containment depressurization. Since the water in the vessel is saturated, boiling will occur even without decay heat or metal heat transfer as the containment pressure decreases. The difference between the safety injection rate and the steaming rate is the spillage rate to the sump. It is conservatively assumed that all of the decay and RCS metal heat transfer goes into creating steam. The spillage flow is assumed to have the same enthalpy as the SIS injection enthalpy.
The rate of steam production is
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Where: Steam flow, lbm/sec Decay and RCS metal heat rates, BTU/sec Rate of change internal energy in RCS as a result of depressurization, Btu/sec Saturated steam enthalpy at containment pressure, Btu/lbm SIS injection enthalpy, Btu/lbm The steam created from the decay and RCS metal heat is saturated. For cold leg breaks it is conservatively assumed that all the steam passes through the steam generators and leaves at the secondary side temperature.
The long-term energy release to the containment is given by
Where:
Rate of steam energy release to containment, BTU/sec
Rate of heat transfer from steam generators to RCS steam, BTU/sec
A.4 Containment Pressure / Temperature Calculations The containment pressure / temperature calculations for the EPU LOCA analysis are performed using the CONTRANS computer program (Reference 7). The CONTRANS model predicts the pressure and temperature within the containment regions and the temperatures in the containment structures. The code takes input from separate blowdown and core thermal behavior studies which have determined mass and energy input rates such as that from a Loss of Coolant Accident or Main Steam Line Break.
The CONTRANS model analyzes both active and passive heat transfer within the containment following a LOCA or MSLB. The code has compared favorably with other industry codes such as CONTEMPT, which was used by Ebasco for the original MSLB containment P/T response and the original LOCA analyses. The containment spray and fan cooler models as well as the passive heat sink numerical calculations enable an accurate calculation of their effect in reducing containment pressure and temperature.
CONTRANS calculates a pressure-time transient with stepwise integrations between the thermodynamic state points. The integrations are based on the laws of conservation of mass and energy together with their thermodynamic relationships. Superposition of heat input functions is assumed so that any combination of coolant release, metal-water reaction, decay heat generation, and sensible heat release can be used with appropriate ESF features to determine the containment pressure time history associated with a LOCA.
The program uses a two region containment model consisting of the containment atmosphere (vapor region), the sump (liquid region), and a primary system model (reactor vessel) which is used to calculate mass and energy release data after the cold leg LOCA post-reflood period or the hot leg LOCA blowdown period. Mass and energy is transferred between the liquid and vapor regions by boiling, condensation, and evaporation. The 6.2-16 Amendment No.
26 (1 1/13) heat and mass transfer coefficients between these two regions are calculated in CONTRANS. Each region is assumed to be homogeneous, but a temperature difference can exist between regions. Any moisture condensed in the vapor region during a time increment is assumed to fall immediately into the liquid region. Noncondensible gases are included in the vapor region.
The thermodynamic assumptions used in CONTRANS and the modelling of the atmosphere and sump regions, reactor vessel region (long term release), safety injection system, containment spray system and shutdown cooling heat exchanger are discussed in Reference (14). This also includes the modelling of the heat transfer surfaces and coefficients. The cooling medium, typically the component cooling water (CCW), utilized for the original shutdown cooling heat exchanger model is assumed to be at a fixed inlet temperature.
An upgrade effort of the CONTRANS code was undertaken to support the St. Lucie 1 & 2 LOCA containment analyses. The intent was to calculate a time dependent CCW temperature. The updated coding incorporated a CCW and Intake Cooling Water (ICW) or salt water loop with common CCW heat exchanger. The new model allows for the time dependent addition of extra heat loads and associated flows such as that of the safety injection or spray pumps or control room A/C. The model is conservative since loop transient time delays or water volumes are not credited and as such is simplistic in nature. The model has been directly attached to the existing CONTRANS code and allows for inputs such as ocean temperature and CCW heat exchanger performance parameters. The enhanced model also updates containment fan cooler capacity as a function of changing CCW temperature.
The containment pressure and temperature transient analyses for the Main Steam Line Break were performed with a version of CONTRANS which was modified to run concurrently with the mass and energy code SGNIII. Running the containment code concurrent with the Mass and Energy code ensures equipment dependent on containment pressure for actuation will function at the correct time for the analysis.
In this computer code, the containment volume is divided into two regions, the atmosphere region (water vapor and air mixture) and the sump region (liquid water). Each region is assumed to be completely mixed and in thermal equilibrium. The temperature of each region may be different. Mass and energy additions are made to the appropriate region to simulate the mass and energy release from the reactor coolant system during and after blowdown with the contribution of the spray system water, and decay energy from the core. Account is taken of boiling in the liquid region and condensing in the vapor region, and mass and energy transfers between regions is considered.
The model represents the heat conducting and absorbing materials in the containment by dividing them into segments with appropriate heat transfer coefficients and heat capacities. Thermal behavior is described by the
one-dimensional multi-region transient heat conduction equation. The heat conducting segments may be used to describe materials and surfaces in the containment which act as heat sources or heat sinks. The model includes provision for mathematically simulating cooling of the containment atmosphere by fan coolers and/or by water sprays, and cooling of the sump water being recirculated to the water sprays by the shutdown heat exchangers.
Calculations are begun by computing initial steady state containment atmosphere conditions. Subsequent calculations are performed at incremental time steps. Following the rupture, the mass and energy addition to the atmosphere or liquid region is determined for each time interval. Heat losses or gains due to heat-conducting segments are calculated. Then the mass, volume, and energy balance equations are solved to determine containment pressure, temperature of the liquid and vapor region, and mass transfer between regions.
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The CONTRANS model and formulations have been shown to be applicable and conservative for the design of the containment vessel by simulated design basis accident tests such as the CVTR (Ref. 3) blowdown experiment.
As shown in the topical report of Reference (14), test cases are presented which outline the CONTRANS methodology. As shown, the proper representation of heat sinks is important, therefore care must be exercised in choosing the correct nodal spacing.
The node spacing within a heat sink is dependent upon the gradient of temperature within the sink. A maximum number of node points was considered where the gradient of temperature is maximum. This is done to ensure an accurate representation of the slope of the gradient. Too few mesh points would simulate a more gradual slope and thus would imply that more energy was stored within the structure than there actually is, substantially affecting the energy balance in the containment.
A description of the heat sink properties assumed to represent the containment vessel and its internal structures is presented in Tables 6.2-2F & 6.2-3. The values of the surface area and thickness given for steel reflect conservatively assumed total areas and surface area weighted thicknesses exposed to the containment atmosphere from all sources. These sources include structural steel (including polar crane and moving platform structures), instrumentation and control equipment, hydrogen recombiners, HVAC equipment (ringheader, ducts, fan coolers, dampers), and the refueling machine. The steel is assumed insulated on one side and is open to the containment atmosphere by Tagami heat transfer on the other. The assumed initial temperature is 120 F. This model of heat transfer follows the averaging process which calculates average thicknesses for the sources listed in the table.
The original values for heat sink mass presented were based on conservative assumptions during the conceptual design stage. The revised values of heat sink mass presented in Table 6.2-3 reflect the total areas, surface, and weighted thickness that were determined via a detailed comparison with the Unit 2 heat sink list. This included a
re-evaluation of the Unit 1 coating system.
The values for surface area and thickness given for concrete reflect total areas and surface-area weighted thicknesses of concrete within the containment. This concrete includes primary and secondary shield walls, operating floors, steam generator and pressurizer shield walls, missile shield cover, pressurizer cover, hatch cover, ring wall and connecting web. The concrete is treated like steel then exposed to the containment atmosphere (or sump) on one side and insulated on the other. The initial temperature is also 120 oF. The heat transfer coefficient between the containment atmosphere and the steel surfaces is calculated by the code using formulas based primarily on the work of Tagami(2). From this work, it was determined that the value of
the heat transfer coefficient increases parabolically to a peak value at the end of blowdown and then decreases exponentially to a stagnant heat transfer coefficient which is a function of air to steam mass ratio.
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B. Containment Peak Pressure / Temperature Analysis
- 1. Loss of Coolant Accident
1.A Input Assumptions An updated peak and long term containment pressure and temperature Loss of Coolant Accident (LOCA) analysis for EPU was conducted. This analysis used Revision 3 of the Standard Review Plan Regulatory requirements while maintaining conformance with the Licensing requirements of Unit 1. The following cases were analyzed:
- 9.82 ft² Double Ended Suction Leg Slot Break
- 9.82 ft² Double Ended Discharge Leg Slot Break
- 19.24 ft² Double Ended Hot Leg Slot Break The pressure and temperature transient calculations are based on the following potential sources of mass and energy release into the containment:
- 1) stored heat from the reactor core and internal structures
- 2) fission coastdown and decay heat from the reactor core
- 3) stored heat in the reactor coolant pressure boundary and the steam generators.
- 4) reactor coolant inventory with contained fission products
- 5) fission products from the fuel elements in the core
- 6) metal-water reaction
- 7) safety injection water
- 8) containment spray water
The above sources were addressed in the CEFLASH-4A, FLOOD3, and CONTRANS long term release models described earlier. Since reflood is not part of the hot leg break methodology the FLOOD3 code was not used for the hot leg breaks. The mass and energy release calculation was therefore limited to the CEFLASH-4A and CONTRANS long term release models. For the cold leg breaks, the FLOOD3 mass and energy release was a continuation of the CEFLASH-4A blowdown. All mass and energy was input to the CONTRANS code for the transient calculation of containment pressure and temperature.
The containment related assumptions are as follows:
- 1) The containment free volume is 2.
498 x 10 6 ft³. (includes -0.5% uncertainty)
- 2) The initial relative humidity within the containment is 45 percent.
- 3) The initial containment pressure is 15.
51 psia.
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- 4) The initial containment, sump, and heat sink temperature is 120 F, the maximum Tech. Spec. operating temperature of the containment.
- 5) No leakage into or out of the containment occurs.
- 6) expression as presented in Reference (14) is:
1/3 (Btu/hr-ft²- F).
- 7) No heat transfer to the sump, shield wall, or atmosphere is assumed.
- 8) The decay heat after reactor shutdown is calculated on the basis of infinite reactor operation at 3030 MW t, including power measurement uncertainty.
- 9) For cold leg breaks, all energy is assumed to go out the break. For hot leg breaks all core and reactor vessel energy is assumed to go out the break. RCS and SG wall sensible heat loss is assumed to be insignificant relative to the long term release energy addition.
- 10) One containment spray pump operates and sprays a base flowrate of 2545 gpm of 104F (max. Tech. Spec. Temperature plus 4 F uncertainty) water into the containment. Following RAS 2545 gpm is assumed. Spray flow added is a function of time against a conservatively assumed containment backpressure.
- 11) The minimum usable inventory of 411,260 gallons, which is based on TS minimum water volume, is used for calculating the time of RA S. 12) One shutdown cooling heat exchanger (SDCHX) operates during the recirculation mode to cool the containment spray water. A "service" U value of 277 Btu/hr-ft²-F is assumed. The heat removal capacity is updated as a function of time by a changing CCW temperature.
- 13) The fan cooler performance is based on as built calculated capacities. This base capacity is updated with time as a function of changing containment temperature.
- 14) The analyses are based on the loss of offsite power in which a coincident loss of diesel generator is assumed. This results in the loss of one cooling train which disables two fan coolers and one containment spray. This leaves one containment spray pump and one train of fan coolers (i.e. two units) available for operation.
- 15) A fan cooler containment high pressure actuation setpoint of 6.3 psig was assumed while the containment sprays were actuated on a containment high pressure setpoint of 113 psig. Both analytical setpoints included instrumentation uncertainty and Tech. Spec. delay times were assumed.
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The LOCA accident analyses are based upon the following additional overall assumptions:
- 1) Reactor thermal power is 3030 MWt. 2) An initial Tcold of 551 F which is the Technical Specification maximum plus 3F for instrument uncertainty.
- 3) An initial RCS flowrate of 375,000 gpm which was the Technical Specification minimum at the time of the analysis.
- 4) For the discharge leg break, the contents of three safety injection tanks (SITs) discharge into the reactor vessel when reactor coolant system pressure drops below tank pressure. This assumes the entire contents of the safety injection tank in the ruptured leg does not reach the core. For the hot and suction leg cases the contents of four SITs is considered.
- 5) An average of the minimum and maximum Technical Specification SIT water volume per tank of 11 62 ft³ was assumed with a Technical Specification maximum initial cover gas pressure of 280 psig.
- 6) One high and low pressure safety injection pump are assumed during the injection mode prior to recirculation, following recirculation LPSI pump operation is terminated.
- 7) CCW flowrates though the SDCHX and Containment Fan Coolers are assumed to be 4666 gpm and 3036 gpm, respectively.
- 8) A degraded ICW flowrate of 11, 880 gpm is assumed with a maximum ocean temperature of 95 F as discussed in the Technical Specification Bases.
- 9) The CCW heat exchanger performance is based on 10% tube pluggage with a U factor (274.6 Btu/hr-ft²- F). 10) The addition of HPSI, LPSI, and containment spray pumps heat load was included in the CCW calculations.
- 11) Volumetric expansion due to primary and secondary conditions at hot full power operating conditions vs. "cold drawing" values was considered per SRP guidelines. This includes the components of pressure, temperature, and manufacturing tolerance uncertainties.
- 12) Initial normal pressurizer and steam generator water levels were assumed.
- 13) Bounding fuels related inputs were assumed in the blowdown analysis.
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1.C LOCA Results A summary of the containment peak pressure and temperature and peak CCW temperature results are provided in Table 6.2-1. Note that this is an overall summary table which compares the original design basis calculations with the EPU analysis. Also listed are the relevant pressure and temperature criteria which were followed in the analysis. As can be seen from the summary table, the peak pressure and temperature from the updated analysis were from the double-ended Hot leg M in SI break case. The peak CCW temperature was from the Double-Ended Discharge Leg Min SI break case. Plots of the EPU peak containment pressure and CCW temperature are provided in Figures 6.2-1A through 6.2-1C. As can be seen, each case is characterized by an initial blowdown peak followed for the cold leg cases by a reflood peak. The small bump further into the transient represents the switchover to the recirculation mode when relatively hot containment spray water is introduced to the containment.
The CCW temperature profile depicts CCW temperature response as a function of the various heat loads coming
on-line.
The peak pressure and temperature results are all very similar. Like any containment analysis, trade-offs in blowdown times, condensation intervals, safety injection assumptions, metal heat contribution, delays associated with active heat removal devices, among many other critical items, make the determination of the limiting case very difficult. It is only through the containment analysis computer codes that these competing effects are quantified to produce a meaningful result.
Each case was shown to meet the peak containment pressure and CCW temperature criteria.
All cases were shown to meet the SRP Section 6.2.1.3 criteria to demonstrate containment pressure reduced to less than half the peak calculated value by 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Tables 6.2-5H to 6.2-5J provide the mass and energy release rates for the limiting temperature double ended discharge leg break case. Tables 6.2-5H, 6.2-5K, and 6.2-5L provide the mass and energy release rates for the limiting pressure double ended discharge leg break case. Tables 6.2-5M to 6.2-5O provide the mass and energy release rates for the limiting double ended suction leg break case. Table 6.2-5P provides the mass and energy release rates for the limiting double ended hot leg break case.
- 2) Steam Line Break in Containment 2.A MSLB Physical Description of Event
The Main Steam Line Break (MSLB) containment event is characterized by the rapid blowdown of steam into containment due to a rupture in the main steam line. The location of this break is at the steam generator outlet nozzle, upstream of the Main Steam Isolation Valves (MSIVs). This location results in the largest possible steam flow for a given break size. The blowdown is limited to one steam generator due to the reverse flow check valve, which prevents flow from the unaffected side steam generator. In this early phase of the event, steam continues to flow to the turbine, until the reactor trip. Following the reactor trip, which occurs on containment high pressure, the turbine stop valves close. During this portion of the transient, all the main feedwater is conservatively fed to the affected steam generator.
During the initial phase of the event, the only source of containment heat removal is via condensation heat transfer to the heat sinks or containment walls.
Containment high pressure initiates the reactor trip and a Safety Injection Actuation Signal (SIAS). This signal initiates the closure of the Main Feedwater Isolation Valves (MFIVs). A Main Steam Isolation Signal (MSIS) occurs on low steam generator pressure to initiate the closure of the MSIVs. The signal to initiate closure of the MFIVs is also initiated on the MSIS however, the containment high pressure signal occurs first. A Containment Spray Actuation Signal (CSAS) occurs on containment high-high pressure to open the containment spray valves and start the containment spray pumps.
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Normally, the Containment Fan Coolers (CFCs) also start in response to SIAS to supplement the active containment heat removal provided by the containment sprays. However, in Letter 96-06, Reference (16), the CFCs are not credited in this analysis.
The closure time for the steam line isolation valves is assumed to be a 5.5 second step function that initiates on MSIS after a 1.4 second delay. The feedwater valves step close in twenty seconds following a SIAS or MSIS.
Backflow for the St. Lucie design is essentially zero since the check valve downstream of the isolation valve of the faulted steam generator would close immediately on flow reversal, thereby terminating the reverse steam flow. The operation of the reverse flow check valve has been credited in the analysis.
Auxiliary Feedwater (AFW) is actuated on the low SG level during the main steam line break. Since the SG pressure differential between the ruptured and intact units quickly diverges due to the double-ended guillotine break, the high SG differential pressure setpoint for blockage of flow to the ruptured SG is quickly reached. However, for simplicity, all the AFW flow is diverted to the intact steam generator after 170 seconds delay following the time the low SG level setpoint is reached.
With auxiliary feedwater isolated from the ruptured SG, it boils dry, thus terminating the mass & energy release to containment. At this point, the containment spray system continues to decrease the containment pressure and temperature inside containment.
2.B MSLB Inputs and Assumptions
ergy releases for the main steam line break inside containment. SGNIII is a coupled primary and secondary model, which calculates a time dependent mass & energy release. The mathematical model used in SGNIII divides the Reactor Coolant System into a reactor core region, and for each loop a hot plenum and hot leg pipe, steam generator tubes, and cold plenum and cold leg pipe regions. The secondary side consists of the main feedwater line (to the MFIV), steam and water volume in the steam generators (to the MSIV) and the main steam line header. The core model is represented by one-group point kinetics with six delayed neutron groups. Non-linear Doppler and moderator temperature dependent feedback are considered. Shutdown CEA's and decay heat generation are included. As discussed in the input section, the SGNIII design inputs were conservatively biased to maximize the mass & energy release. The SGNIII code was also used to calculate containment pressure and temperature response simultaneously with the mass & energy release. A detailed description of the SGNIII code is provided in Appendix 6A.
The containment pressure and temperature response analysis for the MSLB event focused on a matrix of cases.
This matrix included five different initial power levels and several single failures. The goal of the analysis is to maximize the severity of the mass & energy release, which in turn maximizes the containment pressure and temperature response.
The initial plant conditions for the MSLB analysis were selected to maximize the mass and energy release. The initial power levels assumed for this analysis were 100.3%, 75%, 50%, 25%, and 0% of 3020 MWt. An additional 20 MWt was also included for reactor coolant pump heat. Since five power levels were evaluated in this analysis, a number of power dependent inputs were adjusted to conservatively reflect plant conditions for each power level. Presented in Table 6.2-4.A is a summary of the key inputs and assumptions for the cases considered in this analysis. In accordance with Section 6.2.1.4 of the Standard Review Plan, Reference (10), moisture carry over was not considered in this analysis.
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The input data for the mass and energy release and containment pressure/temperature analysis have been developed based upon the design of the plant and EPU conditions (reference 19). A thorough compilation of geometric, thermodynamic, design, and initial operating conditions prior to the hypothetical occurrence of an MSLB has been prepared. These physical and performance conditions were determined based upon conservative estimates of the most adverse design parameters with respect to maximizing containment pressure and temperature. The initial plant conditions assumed in the analysis of the containment response to an MSLB are provided in Table 6.2-4B. In addition to the containment initial conditions, Table 6.2-4B also lists several of the key assumptions concerning the actuation and performance of the containment spray system.
A loss of offsite power (LOOP) at the initiation of the event with the coincident failure of one diesel generator was evaluated as part of this analysis. It was determined that the LOOP scenario produces a less severe containment response than with offsite power available. This is due to the continued operation of the reactor coolant pumps with offsite power available, which maximizes the primary to secondary heat transfer. This offsets the loss of one train of containment sprays for the LOOP scenario. Although the limiting case did include the worst single failure (failure of a containment spray pump), no concurrent event (such as loss of offsite power) was assumed.
The updated MSLB containment analysis included a detailed single failure analysis. Each of these failures was evaluated at five different power levels: 10 0.3%, 75%, 50%, 25%, & 0%.
- 1. One containment spray pump fails to operate. This will leave 1 containment spray available.
- 2. The failure of a Main Feedwater Isolation Valve to close.
- 3. The failure of a Main Feedwater pump to trip.
- 4. LOOP and one emergency diesel fails to start, resulting in the loss of one spray train. This will leave one spray pump available. RCPs coast down on loss of power. This represents the loss of offsite power case.
The failure of a MFIV was not shown to be a limiting single failure. In the case of the MFIV failure, the Main Feedwater (MFW) pump trip was credited. In accordance with the Standard Review Plan, Section 6.2.1.4, non-safety grade control systems may be utilized as a backup to the primary isolation. Therefore, the MFW pump trip was considered as backup to the MFIV. The MFW pumps trip on MSIS generated on low steam generator pressure. The MSIS occurs slightly later than SIAS, which initiates the closure of the MFIV. However, for simplicity, it was assumed that the main feedwater flow is terminated to the steam generator at exactly the same time as in the MFIV failure scenario. Therefore, the response of the MFW pump failure scenario would be the same as the response of the MFIV failure scenario.
The MSLB events considered in the analysis were 5.412 ft 2 guillotine break at the SG steam outlet nozzle for all power levels except 25% and 0% power levels. For 25% and 0% power levels, the breaks considered were 3.31 ft 2 and 1.9 ft 2 slot breaks respectively, at the SG steam outlet nozzle.
The Main Steam Safety Valves (MSSVs) were relied upon to remove energy from the intact steam generator. The opening setpoint of the first bank was 1030 psia while the full open pressure of the last bank, including accumulation, was 1 103.3 psia. No operator actions are credited in the MSLB analysis.
A normal initial SG water level is assumed. This is consistent with the approved CE NuMSLB methodology for mass & energy release and containment response calculations.
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Closure of the Turbine Stop Valves is assumed following reactor trip. These valves are stepped closed in 0.26 seconds following a 0.10 second delay time after reactor trip. Since delaying the closure of the Turbine Stop Valves would reduce the severity of energy content of the steam generators, this time response is conservatively short. Closure of the Turbine Stop Valves is not a safety function in this instance since their rapid closure makes containment response slightly worse.
2.C MSLB Analysis Results
CE Nuclear Power's NRC approved SGNIII containment code was used to determine the containment pressure/temperature response to a MSLB inside containment for the matrix of cases described above.
The most limiting case was determined to be the 10 0.3% power case with the failure of a containment spray pump. This event assumed the availability of offsite power and continued operation of RCPs since this condition results in a more severe containment response Table 6.2-4C provides a summary of the peak containment pressures and temperatures for the twelve cases cited above. The peak calculated pressure and temperature for the limiting MSLB initiated from 10 0.3% power with the failure of a containment spray pump were 42.73 psig and 3 98F, respectively.
The pressure and temperature profiles for the containment response to the limiting MSLB are provided in Figures
6.2-12 and 6.2-13, respectively.
Table 6.2-4D provides a Sequence of Events for the limiting case.
Table 6.2-5Q provides the mass and energy release rates for the limiting case.
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6.2.1.3.3 Containment Internal Compartment Transient Analysis Circumferential (guillotine) and longitudinal (slot) breaks were postulated for the RCS hot and cold legs in the original plant design. Since then, however, the NRC revised General Design Criteria (GDC) 4 to eliminate the consideration of dynamic effects of a loss of coolant accident from the plant design bases. The dynamic effects of a LOCA include the effects of missiles, pipe whipping, discharging fluid (i.e., jet impingement),
decompression waves within the ruptured pipe and dynamic or nonstatic pressurization in cavities, compartments, and subcompartments. NUREG-1061 established criteria for existing plants to determine which systems were allowed exemption and the methodology that was applicable. Reference 10 demonstrates that the primary loop piping meets all of the criteria for application of leak-before-break presented in NUREG-1061, Volume 3. As a result, compartment pressurization from circumferential (guillotine) or longitudinal (slot) breaks in RCS hot leg or cold leg piping is no longer considered a design basis. (References 11 and 12)
As part of the original (and later) plant design bases, the reactor cavity, secondary shield wall enclosure, and the pressurizer cavity were analyzed for differential pressure loads associated with various sizes of primary coolant pipe ruptures. The results of the evaluations are described below:
The CONTEMPT code was originally used to calculate the pressure transients resulting from reactor coolant piping breaks within the reactor cavity between the reactor vessel and the primary shield wall, within the enclosed volume inside the secondary shield wall below the operating floor and within the pressurizer cavity.
Each subcompartment was considered as a single nodal volume which was assumed large enough to prevent any significant pressure variation within it. The vent flow areas used were based on the "as built" vent flow areas.
Due to inquiries from the NRC Staff, the same transients have been performed using the RELAP 3 code for the reactor cavity and pressurizer subcompartments.
The subcompartments are divided into several volumes connected by junctions. All calculations are based on the conservation of mass, momentum and energy. The blowdown mass is allowed to flash to the subcompartment pressure while the pressure builds up before being relieved through openings out of that subcompartment. The maximum pressure differential depends on the number and shape of vent openings, the volume of each subcompartment, and the blowdown rate from the broken pipe.
The results of the subcompartment analysis are summarized in Table 6.2-4H a) Reactor Cavity Due to the application of the leak-before-break criteria, reactor cavity pressurization due to the pipe breaks is no longer a design basis for the plant. The following discussion with associated tables and figures is retained only for historical purposes.
The reactor cavity extends approximately 21 ft below the base floor of the reactor building. Above the floor level, the cavity is formed by 7 ft thick concrete walls extending 18 ft above the floor. A 6 ft thick cylindrical wall extends to the operating deck. Below the floor level, two paths connect the reactor cavity space with an annular electrical tunnel. Each of the paths contains a pressure relief damper which effectively seals off the cavity from the electrical tunnel.
6.2-31 Amendment No.
26 (11/13)
Table IS-251 of ASME Section XI, 1971 (through 1972 Winter Addenda) at J-1 specifies pipe weld areas subject to nondestructive examination (NDE) and the frequency thereof. It requires that areas subject to examination are "longitudinal and circumferential welds in piping and the base metal for one wall thickness on both edges of these welds. Longitudinal welds shall be examined for at least a length of one-foot as measured from the intersection with the circumferential weld selected for examination". Code requirements for hot leg longitudinal welds shall be augmented to include all longitudinal welds in the reactor coolant system piping from the reactor pressure vessel to approximately the outboard surface of the reactor cavity, i.e., those piping sections that are relevant to reactor cavity analyses. The frequency of inspection shall as a minimum comply with paragraph IS-242 of Section XI, namely 25 percent of the required welds shall have been inspected by 3 1/3 years, 50 percent by 6 2/3 years and 100 percent by the end of the tenth year. This inspection interval will be repeated every 10 years for the life of the plant.
b) Secondary Shield Wall Analysis The double-ended guillotine break in the hot leg (which has been eliminated by the application of the LBB criteria), represents the bounding mass and energy release into the compartment for all postulated RCS pipe breaks within the compartment. The mass and energy release at extended power uprate conditions resulting from all other smaller postulated R CS pipe breaks remains bounded by the mass and energy release utilized for the original hot leg double ended rupture. Thus the differential pressure across the secondary shield wall structure at extended power uprate conditions is bounded by original design basis. The following discussion with the associated figure is retained only for historical purpose.
The CONTEMPT code is used to calculate the pressure transient within the enclosed volume inside the secondary shield wall below the operating floor. Only the double-ended guillotine break in the hot leg is considered since it provides the largest rite of mass and energy release into the compartment. The openings for the flow out of the secondary shield wall compartment are all treated as orifices, each with a conservative flow coefficient of 0.6. The total flow area out of the compartment is 1174 ft.
- 2. The net free volume within the compartment is approximately 175,000 ft
- 3. For these assumptions, the maximum internal pressure differential calculated across the compartment walls is 17.1 psi. The design pressure is 24 psi. This occurs at about 0.3 seconds after the LOCA. The differential pressure transient across the secondary shield wall is shown in Figure 6.2-
- 21.
6.2-35 Amendment No. 26 (11/13)
c) Pressurizer Cavity Analysis The analysis assumes pressurizer is supported on a pedestal from the floor of the reactor building and extends through an opening in the operating deck. Below the operating deck, the pressurizer is located within the secondary shield wall and is open to the steam generator subcompartment; above the operating deck, the pressurizer is surrounded within vertical concrete shield walls (2'
-0" thick). With this configuration the pressurizer subcompartment is divided into two distinct areas, the lower area which is the area within the secondary shield wall and the upper area which is a separate subcompartment.
Because the pressurizer cavity below elevation 62 ft is open to the secondary shield wall subcompartment, that portion of the pressurizer cavity is designed for the same maximum pressure differential as the secondary shield wall, i.e., 24 psi (in combination with the loads shown in Section 3.8.3.3).
A multi-nodal analysis was performed for two break cases in the pressurizer subcompartment above elevation 62 ft using the RELAP 3 thermal hydraulic analysis computer code. Figure 6.2-49a shows the model and Table 6.2-5d gives the assumptions used by the RELAP 3 code. The pressurizer subcompartment is divided into three volumes as follows:
- 1) Volume 1 extends from elevation 76.7 ft to elevation 87.0 ft and contains piping which is assumed to break;
- 2) Volume 2 contains the portion of the pressurizer extending from elevation 62.0 ft to volume 1;
- 3) Volume 3 covers the portion of the subcompartment below elevation 62.0 ft (and is considered part of the secondary subcompartment).
Volumes 4 through 7 represent the secondary subcompartment and volume 8 represents the containment volume. All volumes represent Unit 1 as-built volumes. A flow area multiplier of 0.6 is used by the code in the Moody choked flow calculations for representing the physical junctures between volumes.
The pressure response in the upper pressurizer subcompartment is examined for two break cases. Table 6.2-5e presents the original design basis blowdown data for a double ended pressurizer relief line break; Tables 6.2-5f and 5g present the original design basis blowdown data for a double ended pressurizer spray line break. Figures 6.2-49b and 6.2-49c show the result of the original design basis pressurizer relief line and pressurizer spray line breaks, respectively. The original design basis peak calculated pressure of 10.2 psig, which is reached in volume 1 for the relief line break, is well below the 14 psig upper pressurizer subcompartment design pressure. This portion of the pressurizer subcompartment is designed to withstand 14 psig in combination with the loads shown in Section 3.8.3.3. The design is based on stresses within the elastic limit of materials. Additional capability is available for plastic and yield line theory. The pressure response in the vent volumes (4 through 8) never approach their peak accident pressures.
The calculations performed for the pressurizer subcompartment are bounding for the times when the pressurizer missile shield roof is removed. The removal of the pressurizer roof removes a restriction to pressure buildup for the breaks that were analyzed, thereby reducing the pressurization effects.
6.2-36 Amendment No. 26 (11/13) 6.2.1.3.3 Upper Pressurizer Compartment The pressure response in the upper pressurizer subcompartment was assessed for the extended power uprate (EPU) for two break cases, the pressurizer relief line break and the spray line break, by comparing the estimated mass and energy (M&E) release rates at EPU conditions, with the corresponding values for original design. It was determined that the M&E release rates for the pressurizer relief line break presented in Table 6.2-5E remain unchanged by the EPU; consequently, the pressure response presented in Figure 6.2-49 continues to be valid following the EPU. Taking into consideration the lowest analyzed cold leg temperature of 5 43°F, the initial EPU M&E release rates following a pressurizer spray line guillotine break is higher than the M&E release rates associated with original design by 4.5% and 1.5% respectively. With respect to compartment pressurization these minimal increases in the M&E release rates are more than compensated by the impact of the increased vent path of approximately 190 ft 2 due to removal of the missile shield roof of the pressurizer cavity which was included in the original design basis. Thus the pressure response presented in Figure 6.2-49c remains unchanged at EPU conditions. Lower Pressurizer Compartment The pressurizer cavity wall below elevation 62 ft is designed for the same maximum pressure differential as the secondary shield wall i.e. 24 psid. Due to the smaller associated volume, the differential pressure across structural walls due to a pressurizer surge line break within the pressurizer cavity lower compartment could be worse than any line breaks within the secondary shield wall which encompasses a significantly larger volume. The pressurizer surge line break was not analyzed in the original analyses for the lower pressurizer compartment; thus the Unit 1 pressurizer surge line break at EPU conditions is assessed utilizing Unit 2 design information. The similarity of Units 1 and 2 RCS designs support application of M&E data derived for the Unit 2 surge line break in an evaluation of subcompartment response at Unit 1. Excluding the differences in the RCS operating conditions, the calculated M&E release rates for Unit 2 are directly applicable to Unit 1 since The reactor coolant system design at Units 1 and 2 are similar. The design differences between the Units 1 and 2 Replacement Steam Generators (RSGs), Reactor Vessel Upper Head (RVUH) and pressurizer have negligible impact on the M&E release rates. The time of interest of M&E release for evaluation of subcompartment pressurization is 4 seconds or less and the subcompartment pressure leaks in less than one second. The lag time for the RSGs and RVUH to respond and impact the break flow at the pressurizer surge nozzle is greater that the duration of the event. Therefore, the impact of these differences on the M&E release results is negligible. The design differences between the Units 1 and 2 surge lines are small with nearly identica l flow losses that would produce nearly identical M&E release rates for the same operating conditions. Thus the Unit 2 pre-EPU M&E data documented in Unit 2 UFSAR Tables 6.2-21A&B can be utilized to develop M&E data for Unit 1 at EPU conditions. Taking into consideration othe lowest analyzed cold leg temperature of 543°F, the initial Unit 2 EPU M&E release rates following a surge line break is estimated to be higher than the M&E arelease rates associated with original design by 0.9% and 0.4% respectively. Since the pressurizer cavity configurations for both Units 1 and 2 are nearly identical the maximum differential pressure of 22.5 psid shown in Unit 2 UFSAR Figure 6.2-30e is used to predict the maximum differential pressure at the EPU conditions for Unit 1. It is conservative to assure that the pressure increase is proportional to the M&E release rate increase. Thus, the maximum EPU differential pressure at Unit 1 is conservatively estimated to be approximately 22.7psid (=22.5 x 1.009) which is below the design pressure of 24 psid.
6.2-36 a Amendment No.
26 (11/13) 6.2.1.3.4 Shield Building Annulus Transient Analysis As a part of original plant design bases a digital computer code, WA-TEMPT (4); was developed in order to accurately predict the annulus transient for all post-accident conditions and to determine the shield building ventilation system sizing. This code is primarily an extension of the CONTEMPT (1) code. It uses a CONTEMPT type calculation to determine the containment pressure and temperature transients and the resulting transients in the shield building. Computer code GOTHIC is used to predict the post-LOCA annulus transient at EPU conditions.
Following the postulated LOCA, the annulus conditions are calculated to confirm that operating conditions in the annulus do not exceed those specified for the design. The shield building ventilation system is designed to limit the pressure rise in the shield building annulus so as not to exceed the shield building internal and external pressure differential of 3 psi as discussed in Section 3.8.2.2.2. The shield building ventilation system is also designed to establish and maintain a subatmospheric pressure in the shield building annulus within 120 seconds following the postulated LOCA to ensure that offsite doses resulting from the post-accident leakage from the containment are reduced by rerouting through the shield building filters as discussed in Section 6.2.3.1.
Leakage into and out of the annulus is calculated based on pressure dependent leakage rate formulas.
The dependency of the annulus volume on the containment wall temperature and on the differential pressure between the inside on the containment and the annulus is considered at all times. The shield building ventilation system is represented by input tables describing fan size, system resistance, and pressure dependent flow characteristics.
The analysis which is discussed is for the limiting LOCA case (DEHLS break, Min SI, 1 CS, 2 CFCs) which results in the highest containment pressure and also the worst case for the shield building transient. Only one of the two 100 percent shield building ventilation systems is assumed to be operating.
6.2-37 Amendment No. 2 6 (11/13)
Table 6.2-6 lists the important assumptions used in the shield building annulus transient analyses.
Figure 6.2-22 (historical data) shows the annulus pressure versus time at original design basis conditions and Figure 6.2-22A shows the annulus pressure vs time for the limiting LOCA case at EPU conditions. The corresponding pressure and temperature transient in the Containment is shown on Figures 6.2-1A, 6.2-1B, respectively. Figure 6.2-23 shows the condensing heat transfer coefficient versus time applied between the containment vapor to steel vessel. Figure 6.2-24 shows the corresponding annulus temperature versus time at EPU conditions. All of the above curves are based on an assumption of one hundred percent initial humidity in the annulus, as this assumption results in the highest pressure and temperature transients in the annulus for this break. These plots show that the temperature in the annulus approaches 160°F in 500 seconds and the gradually drop as the containment cools down. The annulus pressure reaches a peak of +5.7 in. H20 at 15 seconds and is negative after 116 seconds. The results show that at EPU conditions the design criteria set out for the shield building ventilation system in Section 6.2.3 are met.
Following the postulated LOCA, the annulus is quickly pressurized due to the volume reduction resulting from the sudden expansion of ;the containment vessel caused by the pressure and temperature transient resulting from the blowdown. The annulus is further pressurized as the gases within the annulus are gradually heated up due to convection and radiation heat transfer through the steel wall of the containment vessel. The containment pressurization, heating, and subsequent volume expansion was not implicitly modeled for the EPU assessment. Instead, the limiting LOCA EPU Containment pressure and temperature profiles were treated as boundary conditions and the annulus volume reduction effect due to containment volume expansions was explicitly modeled based on the original results shown in Figure 6.2-22 (historical data).
Heat transfer from the containment vapor space to the vessel surface was based on Tagami heat transfer coefficients. The EPU heat transfer coefficients developed for the containment analysis were conservatively increased by a factor of 2 during the initial 60 seconds to match the condensing heat transfer coefficients applied in the original analysis. This approach is conservative since the containment pressure and temperature profiles from the containment analysis at EPU conditions were applied as boundary conditions for the annulus pressurization assessment. In reality, for a consistent model, the containment pressure and temperature would decrease if the heat transfer coefficients were increased by a factor of 2.
Radiation heat transfer via the steel containment vessel to the annulus gas space, and to the shield building concrete wall and ceiling were considered in the analysis. Natural convective heat transfer was also applied between the containment vessel outer surface and the annulus gas space, and between t he annulus gas space and the Shield Building concrete wall and the inner surfaces of the ceiling. Heat transfer due to conduction within the containment vessel and the shield building concrete wall and ceiling was also considered.
The Shield Building Ventilation System (SBVS) fan flow rate transient used in this analysis was conservatively based on fan performance assuming operation of the emergency diesel generator at 1% under frequency conditions.
The radioisotope inventory of the main steam and feedwater released in the containment following a postulated main steam line break is not sufficient to warrant the analysis of transients in the Shield Building annulus.
6.2-38 Amendment No. 2 6 (11/1 3) 6.2.1.4 Testing and Inspection 6.2.1.4.1 Preoperational Leak Rate Testing (Contains Historical Information)
a) Containment Vessel On completion of fabrication and post-weld heat treatment of the containment vessel, and prior to the installation of penetration internals, pneumatic tests were performed in accordance with the applicable requirements of the ASME Code and ANS 7.60, "Proposed Standard for Leakage-Rate Testing of Containment Structures for Nuclear Reactors, 1971," to demonstrate structural integrity and leak-tightness of the completed vessel. All testing was performed prior to the concrete fill being placed in or under the vessel.
A soap bubble inspection test was conducted with the vessel pressurized to 5 psig. Soap suds were applied to all weld seams and gaskets, including both doors of the personnel air locks.
A second soap bubble inspection test was performed at 41.3 psig upon successful completion of the overpressure test in accordance with the ASM E Code. Following the completion of the overpressure test (described in Section 3.8.2) and the second soap bubble inspection test, a leakage rate test of the vessel was performed with only the inner doors of the personnel air locks closed. The starting test pressure was 41.3 psi to assure a continuous test pressure above 39.6 psi. Continuous hourly readings were taken for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> except for a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> period from the 39th to the 41st hour when no data was recorded.
6.2-39 Amendment No. 2 6 (11/1 3)
REFERENCES FOR SECTION 6.2.1 (1) L. C. Richardson, L. J. Finnegan, R. J. Wagner, J. M. Waage, CONTEMPT A Computer Program for Predicting the Containment Pressure Temperature Response to a Loss-of-Coolant Accident, IDO-17220 (June, 1967) and update: R. J. Wagner, CONTEMPT Modifications, Phillips Petroleum Company Memo WAG-24-68 AM, September 23, 1968.
NOTE: The contents of this update, plus subsequent Ebasco revisions and additions, are summarized in the "Revisions, Ebasco Service Modifications, CONTEMPT Program," March 1971.
(2) Tagami, Takashi, "Interim Report on Safety Assessments and Facilities Establishment Project in Japan for Period Ending June 1965 (No. 1)."
(3) J. A. Norberg, et al, "Simulated Design Basis Accident Tests of the Carolina's Virginia Tube Reactor Containment
-- Preliminary Results," IN-1325.
(4) Ebasco Report, "User's Manual for Dry Air Annulus Response to a Loss of Coolant Accident, WATEMPT," October, 1971 - Plus subsequent Ebasco modifications.
(5) Louisiana Power & Light letter (LPL-2656 Q-3-A28.11) to AEC, re Waterford Steam Electric Station, Docket No. 50-382, Attachment "A".
(6) CENPD-63, 1/5 Scale, Intact Loop Post-LOCA Steam Relief Tests, November 1972.
(7) CENPD-65, Steam-Water Mixing Test Program Task D: Formal Report for Task A, 1/5 Scale Broken Loop, January 1973.
(8) Corrected Redirect and Rebuttal Testimony Submitted on Behalf of Combustion Engineering, Inc., Docket RM-50-1, April 1973.
(9) Westinghouse Calculation CN-OA-08--24-11.
(10) NRC Standard Review Plan, NUREG-0800, Section 6.2.1, July, 1981.
(11) CEFLASH-4A, A FORTRAN77 Digital Computer Program for Reactor Blowdown Analysis, CENPD-133, Supplement 5-P, June 1985 and previous supplements (Proprietary).
(12) Computer Code Description and Verification report for FLOOD3, Combustion Engineering Inc., dated February 4, 1988.
(13) FLOOD-MOD2 - A Code to Determine the Core Reflood Rate for a PWR Plant with Two Core Vessel Inlet Legs, Interim Report, Aerojet Nuclear Company, November 2, 1972.
(14) Combustion Engineering Topical Report CENPD-140-A, dated June 1976, Description of the CONTRANS Digital Computer Code for Containment Pressure and Temperature Transient Analysis.
(15) L. A. Weins (NRC) to T. F. Plunkett (FPL), Issuance of Amendments RE: Implementation of 10 CFR Part 50, Appendix J, Option B, February 10, 1997.
(16) US Nuclear Regulatory Commission Generic Letter, GL 96-06, date September 30, 1996, Assurance of Equipment Operability and Containment Integrity During the Design-Basis Accident Condition.
6.2-44 Amendment No. 2 6 (11/1 3)
The only portions of the containment spray system which will be subjected to the containment environment associated with a LOCA are the spray headers and piping. The remaining portions of the system are located outside the containment in the reactor auxiliary building where the environmental conditions are essentially the same as those prior to the postulated accident. The containment cooling system is located entirely within the containment and is capable of long term operation in the post-accident environment.
All components of the containment heat removal system which are necessary to support the system safety functions have been designed as seismic Class I both inside and outside of containment.
Design data for the components of the containment spray system and the containment cooling system are given in Tables 6.2-8 and 6.2-9. 6.2.2.2 System Design
6.2.2.2.1 Containment Spray System
The containment spray system consists of two independent and redundant subsystems each containing a spray pump, shutdown heat exchanger, piping, valves and spray header as shown in Figure 6.2-28. The system has two modes of operation which are:
a) the initial injection mode, during which the system sprays borated water from the refueling water storage tank into the containment.
b) the recirculation mode, which is automatically initiated by the recirculation actuation signal (RAS) after low level is reached in the refueling water tank. During this mode of operation, suction for the spray pumps is from the containment sump.
Containment spray is automatically initiated by the containment spray actuation signal (CSAS) which is a coincidence of the safety injection actuation signal (SIAS) and the high-high containment pressure signal.
The CSAS is composed of two actuation channels (A and B) with each channel starting its associated spray pump (A or B) and opening its associated spray isolation valve. If required, the operator can manually actuate the system from the control room. Refer to Section 7.3 for further discussion of CSAS circuitry.
The heat removal capacity of the containment spray system is adequate to keep the containment pressure and temperature below design values. Each of the two spray pumps is designed to deliver 2 550 gpm of borated cooling water (approximately 1 900 ppm boron) to the containment atmosphere against a total dynamic head (TDH) of 4 30 ft for CS Train A and 439 ft for CS Train B (Reference 6).
6.2-46 Amendment No.
26 (11/13)
The containment spray pumps initially take suction from the refueling water tank. When low level is reached in the refueling water tank, sufficient water has been transferred to the containment, 411,260 gallons , which is credited for accident analysis, and 411,260 gallons, which is credited for strainer submergence to allow for the recirculation mode of operation. Spray pump suction is automatically realigned to the containment sump upon RAS. Automatic realignment of suction requires opening the valves in t he sump outlet lines and closing the valves at the outlets of the refueling water tank. To assure adequate supply of water for the pumps during suction transfer, the sump valves are designed to be fully open within 40 seconds and the tank valves to be fully closed at 90 seconds following RAS. This is accomplished by using different gear ratios on the motor operators. Refer to Section 7.3 for further discussion of RAS circuitry and logic.
The containment recirculation sump is a seismic Class I structure in protected areas of the Reactor Containment Building. This sump is defined to be the volume in the containment vessel below the minimum flood elevation in the areas occupied by the recirculation strainer system. The containment vessel is a seismic Class I structure and the locations occupied by the strainer system are protected from the dynamic effects of high energy line breaks and missiles. Figure 6.2-40 shows the arrangement of the containment recirculation sump system. As the arrangement indicates, a barrier is provided in the sump to prevent large debris from entering the suction piping to the engineered safety features (ESF) pumps consisting of the containment spray, and high pressure and low pressure safety injection pumps. This barrier consists of the recirculation strainer system, an arrangement of stainless steel modular strainers within the containment recirculation sump that serves as a suction filter during ESF recirculation.
The recirculation strainer system is comprised of twenty-one (21) strainer modules installed inside containment; 17 modules at the 18' elevation and 4 modules in the trench around the outside of the bioshield at the 16' elevation. There is a total of over 8,000 square feet of strainer surface area. The strainers are grouped and piped to a common strainer manifold by 4 parallel pipe runs. The design particle retention of the strainer system is 100% of particles larger than 0.066 (+0) inch via perforated-plate strainer disks with 1/16" nominal circular holes. The pumps which use the containment sump for suctio n during the recirculation phase of a LOCA have the capability of passing particulates 1/4 inch (0.25 inch) and smaller without any detrimental effect on pump capability.
Within the containment recirculation sump boundary is the reactor drain tank (RDT) area cavity, which is located outside the secondary shield wall at azimuth 180 and bottom elevation 7'-6". The strainer manifold connects to the suction piping of both ESF pump trains by two stainless steel pipelines routed through the RDT area and terminating inside the recirculation suction lines. The suction lines are enclosed in carbon steel
gua rd pipes and extend from the bottom of the RDT area cavity inside containment to outside the shield building wall. Each guard pipe is directly welded to a steel containment vessel nozzle and is an extension of the nozzle in both directions. The stainless steel suction lines routed to the ESF pumps are welded to the carbon steel pipes at the RDT area so that water cannot enter the annulus formed by the concentric pipes. Loads from the manifold piping inside the RDT area are isolated from the suction lines and the penetration nozzles by means of a stainless steel collar free to slide against a backing plate attached to the guard pipe. Outside the containment the stainless steel suction lines are sealed to the guard pipes by means of a stainless steel bellows. The bellows seal allows for anticipated differential movement due to thermal or seismic forces.
Further discussion on the recirculation suction lines is presented in Section 3.8.2.1.10.
During the recirculation mode, the spray water is cooled by the shutdown heat exchangers prior to discharge into the containment. The shutdown heat exchangers are cooled by the component cooling system described in Section 9.2.2. The basis for sizing the shutdown heat exchangers is the refueling mode of operation since exchangers is more than adequate for post-accident conditions. The shutdown heat exchangers are designed with a fouling factor of 0.0005 in accordance with the Heat Exchange Institute. Refer to Section 9.3.5 for detailed shutdown heat exchanger design data.
UNIT 1 6.2-47 Amendment No. 27 (04/15)
The spray water is discharged into the containment dome through spray nozzles arranged on headers. The spray nozzles are of the open throat design and are not subject to clogging. The containment spray system operation is based on the spray water being raised to the temperature of the containment air-steam mixture. This occurs when the spray water falls through the steam-air atmosphere within the containment. The spray nozzles in each of the two headers are designed to deliver droplets of approximately 700 microns (3.93 x 10
-5 in.) mean diameter with the spray system operating at design conditions and the containment at design pressure. In order that the spray droplets attain thermal equilibrium with the steam-air mixture during the fall, approximately 70 ft has been provided between the spray nozzles and the top of the steam generators.
The spray water is directed toward the containment sump through a number of flow paths. Any water entering the refueling cavity leaves the cavity through sleeves in the side walls. Any water falling within the secondary shield wall flows towards the secondary shield wall. The recirculation strainer modules are distributed around the secondary shield wall perimeter. They are located on the floor area inside the shield wall, within t he openings in the bottom of the shield wall, and in the trench around the outside of the secondary shield wall.
The trench around the shield wall is open to the containment floor on top and connected to the area within the secondary shield wall on the side by the openings in secondary shield wall. Water falling outside the secondary shield wall flows towards the recirculation strainer modules via the trench. The strainer system is entirely located below the minimum water elevation expected in the containment following a LB LOCA, which is 23.66 ft. All portions of the spray system which are designed to recirculate radioactive water collected in the containment sump are designed to operate in the radiation environment associated with the maximum hypothetical accident (MHA).
The system components are fabricated of corrosion resistant materials as indicated in Table 6.2-8 and are designed to operate in the environment to which they will be exposed following the LOCA. However, in accordance with the staff requirements in this regard, post-LOCA pH control will be provided. A caustic Sodium Hydroxide (NaOH) solution is educted into the buffered boric acid and water solution used for Containment Spray System (CSS) operation. Eductors meter the caustic addition flow rate to maintain a required pH at the spray nozzles of less than 9.49. The spray water with a pH of less than 9.49 will result in an overall containment sump pH greater than 7.0 but less than 9.66 for post-LOCA recirculation.
6.2-48 Amendment No. 26 (11/13)
REFERENCES FOR SECTION 6.2.2
- 1) Uhlig, Herbert H., "The Corrosion Handbook", John Wiley and Sons, Inc. 6th Edition, 1958.
- 2) Polar, P. J., "Guide to Corrosion Resistance", Climax Molybdenum Company.
- 3) Engineering Evaluation PSL-ENG-SENS-04-015, Rev. 0, Plant Operations with Four Containment Fan Cooler s Normally Operating.
- 4) NRC Generic Letter 2004-02, Potential Impact of Debris Blockage on Emergency Recirculation During Design Basis Accidents at Pressurized-Water Reactors, September 13, 2004.
- 02. 6) Westinghouse Calculation CN-SEE-II-11-Extended Power Uprate Program,-05-11.
6.2-59 Amendment No. 2 6 (11/13) 6.2.3 SHIELD BUILDING VENTILATION SYSTEM This section contains information relative to the inputs, assumptions and results of the original radiological off-site dose assessment that has subsequently been revised as a result of implementation of Alternative Source Term (AST) dose assessment methodology implemented via Technical Specification Amendment 206 and extended power uprate (EPU). The information in this section has been retained for historical informational purposes; however, information relative to current system performance assumptions and the resulting dose assessment is provided in the discussion of the event consequences as reported in Chapter 15 of the UFSAR.
6.2.3.1 Design Bases The shield building ventilation system is designed to:
a) limit the pressure rise in the shield building annulus following a LOCA so as not to exceed the shield building internal design pressure, assuming a single active or passive failure.
b) establish and maintain a subatmospheric pressure in the shield building annulus within two minutes following a LOCA to ensure that offsite doses resulting from post-accident leakage from the containment are reduced by routing through the shield building filters, assuming a single active or passive failure. The offsite and control room dose consequences resulting from post-accident leakage remain acceptable for a shield building depressurization time to sub-atmospheric conditions of less than 310 seconds following a LOCA.
c) provide fission product removal capacity based o n guidelines established for design basis accidents and a containment vessel design leak rate of 0.5 volume percent per day. Per Technical Specification Amendment No. 206, thyroid dose conversion factors will be those listed in Federal Guidance Report 11, of Radionuclide Intake and Air Concentration and Dose Conversion Factors for Inhalation, Submersion, and Ingestion d) withstand post-accident environmental conditions within the shield building without loss of function.
e) withstand design basis earthquake loads without loss of function.
f) permit appropriate periodic inspection and periodic pressure and functional testing to assure system integrity and functional capability. Although the containment spray system borated water spray may aid in attenuating the iodine concentration in the containment atmosphere following a LOCA, the shield building ventilation system was originally designed to limit the offsite doses to values at least as low as those calculated in Section 15.4.1
.5 without any credit taken for operation of the spray system. The assumptions for the revised offsite dose analysis are in Appendix 6B. Containment air purification and cleanup systems not required to mitigate the effects of a LOCA but necessary to reduce the concentration of radioactive contaminants in the containment atmosphere which build up during normal operation are discussed in Section 12.2.
6.2.3.2 System Design The shield building ventilation system is shown on Figure 9.4-3 and consists of two full capacity redundant fan and filter subsystems which share a common shield building duct intake and a common plant vent. Each filter subsystem consists of demisters, electric heating coils, HEPA filters and charcoal adsorbers enclosed in a common casing. Each of these components as well as humidity controls are discussed in Section 6.2.3.3. Shield building ventilation system electric heaters are discussed in Appendix 6B. Refer to Table 6.2-13 for design data and materials of construction for shield building ventilation system components, including charcoal filters. Refer to Table 6.2-13A for a comparison of the shield building ventilation system design to Regulatory Guide 1.52.
6.2-60 Amendment No. 2 6 (11/1 3)
through the failed system. Detectors in the charcoal beds annunciate temperatures exceeding 200° F. 6.2.3.3 Design Evaluation
6.2.3.3.1 Performance Requirements and Capabilities
Each of the two full capacity redundant fan filter subsystems of the shield building ventilation system has been designed to fulfill the performance requirements stated in the design bases, Section 6.2.3.1. The shield building ventilation system sequence of operation as related to the shield building pressure transient is illustrated in Figure
6.2-31 (historical data). The method of analysis and assumptions used in the shield building pressure transient are discussed in Section 6.2.
1.3.4.
Following a LOCA, the air in the annular space between the shield building and the containment vessel heats up due to natural convection and radiation heat transfer from the containment vessel. At the same time, the pressure differential between the containment and the annulus and the heating of the containment vessel is assumed to cause an expansion of the vessel and a resulting decrease in the volume of the annulus. The effects result in pressurization of the annulus. Each of the shield building ventilation system centrifugal fans is designed to independently decrease annulus pressure to slightly subatmospheric within two minutes after a LOCA, assuming a 30 second delay in starting. Each fan is capable of exhausting from 6,000 cfm to 8,500 cfm to satisfy this requirement.
Once the subatmospheric pressure is established, it is maintained between 1 and 3 inches wg negative by a controller sensing pressure differential across the shield building wall which would open the outside cooling air inlet valve and allow the check valve to regulate cooling air flow. The subatmospheric annulus pressure assures that post-accident activity release from the containment vessel is routed through the filter train provided and not through the shield building as leakage. Continuous fan performance at a flow of 6000 cfm + 10% is required to maintain this pressure negative as well as to provide cooling air for the filters.
There are two separate filter train assemblies provided, one for each fan system, consisting of a demister, electric heating coils, HEPA prefilter, charcoal absorber and HEPA afterfilter in that order. Each component of the filter train is capable of withstanding pressure drops sufficient in magnitude to cover all ranges of fan flow.
Each moisture separator demister has an efficiency of 99 percent when exposed to entrained water particles of 1 to 5 microns in size. The twelve HEPA filters per train have an efficiency of a least 99.97 percent when tested with 0.3 micron dioctylphthalate (DOP) smoke. HEPA filter assemblies are constructed of materials capable of withstanding a temperature of 250°F. The charcoal adsorbers are iodine impregnated and have the capability of removing 99.9 percent minimum of iodides with 5 percent in the form of methyl iodine, CH 3I, when operating at 70 percent relative humidity and 150°F. The analysis presented in Section 6.2.1.3.4 demonstrates that the shield building relative humidity is
6.2-62 Amendment No. 2 6 (11/1 3) below 70 percent within 200 seconds following a LOCA. The charcoal beds have the capability to hold 6000 gms of stable iodine and 360 gms of radioactive iodine including 300 gms of CH 3I. Adsorbers in each filter train are capable of operating with 750 watts of fission product decay heat when supplied with 20 percent of rated filter flow.
Calculations of off-site doses are presented in Section 15.4.1.8 together with the assumptions made and model used. Two calculational models are developed there, one a reasonably conservative model which assumes some annulus mixing and the other a very conservative model using all the assumptions of Safety Guide 4.
a) Humidity Control This section contains information relative to the inputs, assumptions and results of the original radiological off-sit e dose assessment that has subsequently been revised as a result of implementation of Alternative Source Term (AST) dose assessment methodology implemented via Technical Specification Amendment 206 and extended power uprate (DPU). The information in this section has been retained for historical informational purposes; however, information relative to current system performance assumptions and the resulting dose assessment is provided in the discussion of the event consequences as reported in Chapter 15 of this UFSAR.
The LOCA analysis conducted in Section 15.4.1.2 assumed an elemental iodine removal efficiency of 90 percent and a methyl iodide removal efficiency of 70 percent. These efficiencies are appropriately conservative for the SBVS design for the following reasons:
- 1) The SBVS is a secondary filtration system, i.e., it does not circulate the containment atmosphere, but rather maintains shield building annulus vacuum by pumping shield building inleakage to the vent stack. The system is not exposed to undesirable environmental conditions such as steam, water sprays, or mist.
- 2) The air entering the filter train comes from two sources, namely, the shield building annulus and outside makeup. The combined stream entering the filter train will be of temperature and relative humidity characteristic of maritime air. The characteristics of each stream are discussed below:
a) Section 6.2.1.3.4 discusses the transient in the shield building annulus following a LOCA. The relative humidity falls to 70 percent in 200 seconds and remains below that value thereafter while the temperature approaches 160° F in 500 seconds and then gradually drops as the containment cools down.
b) Outside air makeup is provided to insure rated continuous system flow. Onsite relative humidity data taken at 0600, 1200, 1800, and 2400 hours0.0278 days <br />0.667 hours <br />0.00397 weeks <br />9.132e-4 months <br /> of the day from March 1971 to December 1972 indicated that monthly averages did not exceed 79 percent. Onsite temperature data from March 1971 to February 1972 varied from a monthly average of 65 to 8°F. Site meteorological characteristics are discussed in Section
2.3.2.
6.2-63 Amendment No. 2 6 (11/13)
The bounding LOCA event dose consequences were subsequently updated to incorporate a revised source term for high burnup and the thin clad fuel design. These revised bounding LOCA event dose consequences are shown below.
Thyroid 75 167 Whole Body 5.4 6.3
- Updated for high burnup and thin clad fuel design first implemented in Cycle 11.
For a LOCA, Technical Specification Amendment 206, which adopted the alternative source term allowed in 10 CFR 50.67, revised the radiological consequences as currently reported in UFSAR Table 15.4.1-
- 11. b) Charcoal Adsorber Temperature Control As part of original license, an evaluation was made of the provisions which would assure that charcoal in the shield building ventilation system adsorbers will not attain temperatures that permit either desorption of iodine (300°F) or ignition of charcoal (640°F).
(3)
The discussion that follows considers both the oxidation of charcoal and the heating due to the decay of entrapped fission product iodines. The SBVS design precludes adsorber temperatures in excess of 200°F, which provides ample margin to the onset of desorption. Control room annunciation is provided at 200°F.
The oxidation heat load at a 200°F adsorber temperature been calculated based on test data (7) to be 66.4 Btu/hr and is added to the peak decay heat load that is developed.
To determine the heating effect of iodine radioactive decay on the charcoal adsorbers, the following assumptions are made:
a) Leakage from the containment vessel is in accordance with the assumptions of Regulatory Guide 1.183. Leakage from the containment is assumed to occur at the rate of 0.5 percent of the containment free volume for the initial 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period and 0.25 percent thereafter.
b) Twenty-five percent of the core inventory of iodine is available for leakage.
c) Leakage from the containment vessel appears immediately on the charcoal adsorbers; that is, there is no holdup assumed in the shield building annulus. The charcoal filters are assumed to have 100 percent iodine trapping efficiency.
d) All physical and chemical forms of iodine collect on the charcoal adsorbers.
e) Half of the gamma decay energy and all of the beta decay energy of the trapped iodine is absorbed by the filter.
(1) f) Temperature rise of the air stream is based on the total available decay heat input in item (e) plus the heat of oxidation.
g) Temperature of the hottest spot in the charcoal bed is 5°F above the temperature of the air leaving the filters. This is based on investigations at ORNL which showed the above difference to be within 2 or 3°F.
(2)
6.2-67a Amendment No. 2 6 (11/1 3)
The decay heat load versus time is provided in Figure 6.2-41. The peak heat loading rate of 2577 Btu/hr occurs 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the LOCA. To this the charcoal heat of oxidation rate of 66 Btu/hr is added yielding a
peak rate of 2643 Btu/hr. At this point in.time the air flow to the adsorbers will be from the annulus (about l00 cfm) and from the outside makeup line (about 5900 cfm), thus the temperature would be typical of the outside air temperature. Nonetheless, to place an upper bound on the cooling flow required, the cooling flow was determined based on an inlet air temperature of 150F (annulus temperature - see Figure 6.2-24) and a charcoal bed exit temperature of 195F. The flow required to maintain a 200F adsorber temperature is 55 cfm.
The shield building ventilation system has the capability of removing fission product decay heat from either filter train, if the fan in one filter train should become inoperable, by means of a cross-connection to the remaining fan/filter train. Assuming failure of the operating train of the shield building ventilation system, train A for example, approximately 6000 cfm of air would be drawn through the train B air intake when the train B fan is automatically actuated. Of the 6000 cfm, a system air balance analysis demonstrates that approximately 300 cfm would be drawn through the inoperable train A filters. This is accomplished by opening the control room operated cross-connect valve (FCV-25-13 on Figure 9.4-3) which is located downstream of the filters and upstream of the fans. The cooling air from train A then joins the train B air stream prior to discharge by fan HVE-6B. A single failure analysis is provided in Section 6.2.3.3.2. It demonstrates that no single failure results in a flow of less than 55 scfm through the inoperative bank.
An evaluation was performed to determine the impact of the Extended Power Uprate (EPU with regard to decay heat generation and dissipation. With the minimum cooling flow greater than 300 cfm, the actual temperature rise across the charcoal filters is approximately 8F for a TID -14844 source term (UFSAR Appendix 6B, Section 4.1.3). The existing margin between the original design basis predicted heat rise at a minimum cooling flow of 300 cfm (i.e., from 150F to 158F ), and the alarm setpoint (200F ), is more than sufficient to accommodate the approximately 12% power uprate and the change in source terms from TID-14844 to Alternate Source Term (AST). It is noted that the changeover to AST will reduce the EPU iodine inventory and associated heat load in the charcoal filters to less than that predicted to have been accumulated in the TID-14844 based analysis. The heat contribution to the charcoal media due to gamma heating resulting from the particulate inventory accumulated in the HEPA filters is not significant since the associated gamma heating rate in the charcoal is less than that generated by the iodine in the charcoal during the first 30 days following the DBA when the decay heat rate is the highest.
Each filter train is monitored for temperature by redundant sensors as indicated in Section 6.2.3.5. Since charcoal adsorber temperature is alarmed and recorded in the control room and, and since capability exists for utilizing the redundant filter train, and since cooling air is available for the shutdown filter train, even when any single active failure is assumed, the charcoal filter train temperature will not approach that required for the onset of desorption or combustion. Thus, the SBVS design provides satisfactory cooling of the adsorber beds.
Filter cooling is accomplished as described above and in Appendix 6B. Humidity control of the cooling air flow through a filter bank was provided for as part of a backfit modification. Humidity control modifications were implemented as part of PC/M 270-177. 6.2.3.3.2 Single Failure Analysis
Two redundant subsystems are provided, either of which is capable of meeting the requirements of the system design bases. Each subsystem is actuated by a separate CIS actuation channel. As explained in Section 8.3, all redundant active components are powered from separate emergency bases. Consequently, the shield building ventilation system design function is not compromised by any single failure. Refer to Table 6.2-
- 14.
6.2-68 Amendment No. 2 6 (11/13)
An analysis has been conducted to determine if a single active failure could result in an air flow through a recently shutdown filter train of less than 55 scfm, the flow required to maintain a 200 F adsorber temperature. For any single active failure (fan, cross-connect valve or air intake valve), a system air flow balance indicates that in the worst case at least 300 cfm of cooling air would be drawn through the inoperative train. Therefore, the analysis shows that adequate air flow will always be available for filter cooling even when the minimum cooling flow requirements are based on upper limit calculations.
The single failure criterion has not been applied to HVAC ductwork serving redundant safety related equipment. No ductwork operates at pressures greater than 22" wg (about 3/4 psi) so that rupture of the ductwork could not occur due to the pressure of the contained fluid.
Common ductwork serving safety related equipment occurs at the:
a) Auxiliary Building main air supply (ECCS air supply)
b) Electrical equipment room ventilation system supply c) Cross connect duct of shield building ventilation system d) Control room ventilation system recirculation and supply
e) Containment ring duct header
In each case the ducting is located in areas where there is no high pressure piping that could result in pipe whip or jet impingement. Similarly, the ducting is not located in areas where internally generated missiles or failure of non seismic Class I structures or components could affect system operation. Leakage from cracks in the ductwork will not prevent the vent system from performing its safety function.
6.2.3.3.3 Service Environment
Except for ducting, the components of the shield building ventilation system are located external to the shield building in the reactor auxiliary building where the external environmental conditions (temperature and pressure) are essentially unchanged after a LOCA. Environmental design of the shield building ventilation system fan and damper motors is discussed in Section 3.11.
6.2.3.3.4 Natural Phenomena
All components of the shield building ventilation system are designed as seismic Class I. Purchase specifications require and vendors have substantiated through test, calculational and/or operational data that system components will remain operable under the design basis earthquake loads.
6.2-69 Amendment N
- o. 26 (11/13)
applicable section.
Table 6.2-16 lists all of the mechanical and HVAC Penetrations, the service they provide and the system to which they belong. Also tabulated are penetration type, isolation class, flow direction, location reference to containment, valve type, pipe size, method of closure (primary and secondary), actuation channel, normal valve position, valve position with power failure, post-accident position and valve closure time on actuation signal.
All containment isolation valves, actuators and controls are located in areas which are enclosed and which have been designed to withstand the maximum seismic forces expected in that area. These penetration areas are also designed to withstand the missiles postulated in Section 3.5.
The piping in the penetration area has been designed such that the failure of any pipe will not cause damage to adjoining piping by jet forces or pipe whipping. This design concept assures that the failure of a non-Class I pipe will not result in loss of containment isolation. Under accident conditions the penetration area is continuously vented by the emergency core cooling area ventilation system (Section 9.4.3) such that the service operating environment will not be detrimental to the equipment. Isolation valves located inside the containment are designed to operate in the post-accident environment for the time necessary to perform their safety functions.
Purchase specifications specify required closure times and resulting maximum operating pressure differentials for all isolation valves. Evaluations were conducted for the Main Steam Isolation valves for the EPU conditions to verify integrity after being subjected to the forces resulting from fast closure against full system pressure. The evaluations concluded that valve parts needed replacement for the Main Steam Isolation valves to ensure integrity can be maintained. The resulting valve modification ensures that the valves will close and maintain integrity under all operating conditions.
The fuel transfer tube isolation system is part of the transfer system for transporting fuel between the fuel handling building and the reactor containment. The fuel transfer tube has a double gasketed blind flange on the containment side, permitting pressure leak testing between the gaskets and a gate valve at the end inside the fuel handling building. The transfer tube and attachments are designed to withstand the forces resulting from the design basis earthquake. The double gasketed blind flange serves as the primary containment seal. Refer to Sections 3.8.2.1.6 and 9.1.4.2 for additional information.
6.2.4.3 Design Evaluation 6.2.4.3.1 Performance Requirements and Capabilities
After a LOCA, the only potential paths of direct leakage through the isolation system would be from seismic
Class I system penetrations which are directly connected to the reactor coolant system and from penetrations for non-seismic Class I pipes. The first group would be directly open to the containment atmosphere following a LOCA. The second group could be postulated to be directly open to the containment atmosphere and to the outside atmosphere following a design basis earthquake.
6.2-78 Amendment No. 26 (11/13)
the expected number of service lift cycles to verify endurance of the system.
Each recombiner unit operates on 480 volts, three phase power, and requires 75 Kw maximum. The shell is made of Type 300 series stainless steel. The inner structure is Inconel 600 and heaters Incoloy 800. It must be noted that the hydrogen recombiner is the same as that provided for Calvert Cliffs 1 and 2 (Dockets
50-317/318). The Advisory Committee on Reactor Safeguards in their Interim Calvert Cliff report of 6/18/73 has stated that the post-LOCA qualification testing was acceptable.
Figure 6.2-45A shows a cutaway of the St. Lucie recombiner.
6.2.5.2.2 Hydrogen Purge System The hydrogen purge system will be used as a diverse means of hydrogen control as a backup to the hydrogen recombiner in accordance with Regulatory Guide 1.7.
The hydrogen Purge System will be used as a containment pressure control function during normal operating conditions during Modes 1 thru 4.
6.2-85 Amendment No.
26 (11/13)
The containment hydrogen purge system is designed for intermittent or constant flow rate purge operation. When, as a result of information obtained by means of the sampling system, it is determined that the maximum allowable limit for hydrogen concentration has been reached, the purge system is placed in operation under strict administrative controls. The containment purge isolation valves (FCV-25-20, FCV-25-21) are remote manually or local manually opened, and one of the two purge system fans is remote manually started. The flow control valve (FCV-25-9) is adjusted to regulate the purge flow rate to a value consistent with the purge rate for that time of purging after an accident as determined by analysis. Instrumentation monitors the flow rate of the purge stream.
Subsequent containment sampling indicates the effectiveness of the purging operation by determining the rate of change of the hydrogen concentration. After a period of purge system operation, the system may be shut down to await more favorable meteorological conditions before restarting.
The simplest mode of operation is the fixed purge. In this mode, the purge is initiated when the selected maximum hydrogen concentration is reached as determined by the sampling system (Section 6.2.5.2.3). The flow of the purge system is set at the flow required to prevent the hydrogen concentration from exceeding the maximum and is not changed thereafter. As fission products decay, the rate of hydrogen production decreases and consequently, if the purge flow is maintained constant, the hydrogen concentration will continuously decrease.
A second method of control is to select the purge flow and duration based on periods of optimum meteorological dispersion or wind direction. At these times a higher purging rate is allowed. This method sufficiently decreases the hydrogen concentration so that purging can be reduced or even halted during periods of less favorable meteorology.
The Hydrogen Purge System provides a new function to control containment pressure.
The pressure venting function of the hydrogen purge line is remote manually controlled to vent pressure in containment during normal operation The Hydrogen Purge System is remote manually controlled for both Hydrogen Purge and Containment Pressure Control. The Containment Isolation valves are air operated valves with remote control from the control room. The Containment isolation valves will close upon receipt of CIS.
The mechanical components and materials of construction are presented in Table 6.2-17 and are described below:
a) Purge lines and valving The inlets of the purge lines are located at the top of the containment dome. Two 3-in purge lines lead down from the top of the containment dome at elevation 219 ft and are reduced to 2 inches at the penetrations through the containment vessel and shield building wall. One line is connected to the filter-train/fan assembly located in the reactor auxiliary building equipment room at elevation 43' - 0". The purge fans discharge to either the plant vent or the Shield Building Ventilation System. This serves as a standby mode of operation. The second purge line bypasses the filter train and permits discharge into the purge fan suction. Two locked closed gate valves and two remotely closed ball valves in the purge lines are used for containment isolation.
6.2-86 Amendment No.
26 (11/13)
The valves are located in the heating and ventilating equipment room at elevation 43' 0". Access to these valves during post-accident conditions is administratively controlled to minimize radiation exposure per NUREG-0737 item II.B.2.
b) Filter Train A single filter train is utilized in the main system and includes a demister, HEPA prefilter, two charcoal adsorber banks in series and a HEPA afterfilter. This sequence was selected to prevent water saturation of the HEPA filters and also so that the gaseous flow enters the charcoal filters with no entrained moisture and with most of the particulates removed. The final HEPA filter is provided to ensure that no radioactive charcoal can be released to the plant vent. Two charcoal filters are included in the purge line to provide more efficient iodine removal so that off-site thyroid doses are minimized.
The demister consists of a single cell, 24 in. wide by 24 in. high by 2 in. deep, mounted on a structural frame. The demister has an efficiency of 99 percent for removing entrained water particles of 1 to 5 micron size. The normally isolated demister drain can be routed to the waste management system via a local floor drain.
The HEPA prefilter and afterfilter each consist of a single cell, 24 in. wide by 24 in. high by 110 in. deep, mounted on a structural frame. Each HEPA filter is factory tested to meet an efficiency of not less than 99.97 percent when tested with 0.3 micron dioctylphthalate (DOP) smoke. Filter and frame are of fire resistant construction in accordance with UL-586. The first charcoal adsorber bank consists of 6 charcoal cells arranged 1 wide by 6 high. The second charcoal adsorber bank consists of 3 charcoal cells arranged 1 wide by 3 high. The cells of each bank are mounted on a cradle structural frame. Each cell is of the flat bed type consisting of two 2-in. thick charcoal-beds. Iodine impregnated charcoal is capable of removing 99.9 percent minimum of iodine with 10 percent in the form of methyl iodide (CH3I), when operating at 70 percent relative humidity.
c) Fans Two centrifugal fans provide the purge function. Each fan has the flow capacity to deliver 25 percent (500 cfm) of rated charcoal adsorber flow for effectively removing the maximum postulated decay heat without appreciably increasing the charcoal temperature above the purge air temperature. Excess capacity allows for increased purge rates during periods of favorable meteorological conditions.
d) Outside Air Cooling Line A 6 in. line permits drawing approximately 450 cfm of air directly from outside of the reactor auxiliary building for removing the decay heat generated in the charcoal absorbers. A motor operated modulating butterfly valve with (I-FCV-25-10) in the outside air line regulates the outside air flow consistent with the purge rate. The valve is normally throttled and controlled from the control room. It also allows isolating the filters for servicing. A check valve in the outside air line prevents backflow in case of failure of the motor operated valve.
6.2-87 Amendment No. 2 6 (11/1 3)
Historical Information (continued)
Regulatory Guide 1.29), except insofar as portions of the system constitute part of the primary containment boundary.'
Item 2b of the Regulatory Position states in part;
"If the incremental long-term dose from purging in the event of a postulated LOCA are calculated to be less than 2.5 rem whole body and 30 rem thyroid at all points beyond the exclusion area boundary, no combustible gas control systems other than purging need be provided. The combination of the dose from purge and the long-term dose from a Postulated LOCA should be below the guidelines of 10 CFR 100 at the low population zone outer boundary."
The design complies with the Regulatory Position. Redundant combustible control systems and a backup purge system are incorporated in the design. The doses resulting from purge operation are acceptably low.
Thyroid doses are as presented above and whole body doses follow:
Whole Body Dose (rem)
Purge Rate (cfm)
Exclusion Distance LPZ 28 0.003 0.0002 50 0.004 0.0003 100 0.006 0.0005 Since the bypass leakage technical specification is based on the sum of the SBVS and bypass post-LOCA doses not exceeding 150 rem, the small incremental purging dose is well below the 10 CFR 100 limits. It must be noted that the backfit position of RG 1.7 would not require recombiners for Unit 1. Nonetheless, the recombiners have been provided.
In light of the above it is concluded that heaters for the purge system are not required because:
a) The incremental dose due to purging is very low and when added to the 150 rem (SBVS + bypass) limit the total offsite post LOCA dose is well below 10 CFR 100 requirements.
b) Due to the small fraction of methyl iodide in the iodine inventory available for leakage, the addition of heaters would not result in substantial additional protection for the public health and safety (10 CFR 50.109).
c) Since the purge system is a backup to two redundant safety grade combustible gas control systems, it will undoubtedly never be utilized. Its utilization would require concurrently (i) a LOCA, (ii) failure of one recombiner system, and (iii) failure of the second recombiner system. The likelihood of this is so remote that it is not a design basis for the plant.
In addition to the above historical justification for the hydrogen purge system not requiring heaters to maintain the inlet air relative humidity into the charcoal filters at 70% or below, the updated dose analysis performed for EPU conservatively take no credit for methyl or elemental iodine removal thru the charcoal filters during any of the postulated design basis accident analysis. The analysis performed determined post LOCA offsite doses are within the dose guidelines established for the design basis accidents.
6.2-90 Amendment No.
26 (1 1/13)
The shield building ventilation system will be used as a backup means of purging hydrogen, utilizing a purge line which is connected to the shield building ventilation system upstream of the charcoal filters.
Instrumentation provided for the system and discussed in Section 6.2.5.5 provides ample monitoring and indicating capability for complete control of the purging and sampling operations. Complete separation of redundant containment isolation valve control switches and wiring is provided. Internal wiring associated with redundant systems are run through separate totally enclosed metal trays which are permanently marked with identifying letters. In no way shall exposed wiring from one redundant system be in close proximity with the exposed wiring of the other redundant system.
The hydrogen analyzers are located in separate shielded cubicles at 43.00 ft elevation in the RAB, in a low traffic area, thereby reducing potential exposure to plant personnel following a LOCA. The shielded cubicles allow access to either analyzer for maintenance, while the other analyzer is in service.
The hydrogen purge and sampling systems are designed as Seismic Class I and are located in the Seismic Class I reactor auxiliary building-
The hydrogen purge system isolation valves fail closed on a loss of instrument air supply. Upon receipt of a CIS the isolation valves close automatically with 30 seconds if the system was in service. The pressure control function of the hydrogen purge system is not required for safe shutdown of the reactor or to mitigate the consequences of a design basis accident.
6.2-94 Amendment No. 26 (11/13)
The fraction of total decay energy that is gamma is determined from the work of Shure.
(9) The time dependency of this fraction is considered in the analysis.
- 2) Out-of-Core Contribution - The radiolysis produced by fission products released from the core and distributed in the water considers that the total decay energy is effective. However, it is important to note that t he assumed distribution of fission products between the coolant and containment atmosphere affects not only the rate of hydrogen production but also what is available to be released to the plant environment. This effect is significant only for the halogens released and the resultant thyroid doses.
The noble gases are essentially completely distributed in the containment atmosphere although a small amount is dissolved in the coolant. This fraction is estimated from Henry's constants for the gases and contributes only slightly to radiolysis. The released solid fission products (1 percent of the total decay energy) are assumed to be entirely dissolved or suspended in the coolant. Some small fraction might appear in the atmosphere as aerosols but this is neglec ted.
The distribution of halogens in the coolant and the atmosphere, however, is strongly dependent upon a number of factors which could result in the halogens exhibiting a high or low volatility. Since it is difficult to predict the behavior of the halogens a range of dissolved halogen fractions are analyzed.
- 3) Total Radiolytic Hydrogen - The amount of hydrogen produced in-core and out-of-core for three different dissolved halogen fractions for applicant and Safety Guide 7 assumptions is shown on Figures 6.2-34 and 6.2
-35, respectively.
Hydrogen production increases with increasing halogens dissolved in the coolant. It was originally assumed that the reactor had been operating at 2700 Mwt and that just prior to the LOCA the containment temperature is 120 F at 14.7 psia. The containment atmosphere temperature at the time of the accident affects the initial amount of air with which the hydrogen will be mixed. The initial amount of air decreases with increasing initial temperature; hence, the value selected is based on the highest expected normal containment temperature during operation.
b) Zirconium - Water Reaction Zirconium reacts with steam given the proper conditions according to the following reaction:
The reaction rate becomes significant at a temperature of 1800 F and increases rapidly above this temperature. However, the action of the safety injection system will limit temperatures attained by the reactor
6.2-99 Amendment No. 26 (11/13)
core following a loss of coolant such that only a small fraction of the zirconium in the core will react. Calculations in Section 6.3.3 indicate that less than 0.4 percent of the zirconium in the core will react. Because of the temperature distribution across the core, the highest local fraction reached will be less than 1 percent while some parts of the core will not experience any reaction.
The reactor core contains approximately 53,500 lb of Zirconium Alloy, approximately 44,700 lb of which is cladding and the remaining 8800 lb are springs, spacers, and end fittings. Although only the cladding would be expected to react with steam, the entire 53,500 lbs of Zirconium Alloy has been assumed to be Zirconium available for reaction. For conservatism, the amount of zirconium reacted is assumed to be 2 percent or 1070 lbs. This is a factor of 5 greater than the maximum amount calculated for a LOCA. This reaction is assumed to occur essentially instantaneously and produces 23.55 lb moles of hydrogen. This amount of hydrogen is
equivalent to a concentration in the containment building of 0.369 volume percent at 120 F and 1 atmosphere pressure.
c) Electrolysis If currents of electricity passed through the solutions present in the containment after the MHA, water will be electrolyzed and hydrogen and oxygen would be generated as gases.
The design of the plant is such, that, subsequent to the accident, the only electrical power required within the containment would be that for the four containment cooling unit motors and for some instrumentation. The power supplies to other equipment can be interrupted without adverse effects on safety. The power supplies to the instrumentation are low current capacity systems and represent no significant source of leakage current.
Therefore, only the power supplies to the containment cooling units need be considered.
The wiring for the containment cooling units is waterproof. This prevents leakage currents from the conductors. In the event that a cable is severed, indication of this is readily determined by the operator from the motor input current readings and by the cooling wThe circuit breaker for this power supply will then be opened and no current from the supply will flow into the containment. Hydrogen from electrolysis is therefore assumed to be insignificant.
d) Corrosion of Metals The corrosion of metals has received a great deal of study and has been found to be a very complex subject.
Although it is generally believed that corrosion is basically an electrochemical process, there are questions of protective films, polarization, oxidation, concentration cells and electrode potentials which confuse the issue so that practical solutions to corrosion problems are largely empirical. The fact that corrosion studies are slanted to the protection of the metal makes it difficult to apply the available information on corrosion to the problem which concerns us here, i.e., the generation of hydrogen within the
UNIT 1 6.2-100 Amendment No. 27 (04/15)
containment after a LOCA. To better understand the complexities of the corrosion problem, a brief review of the sequence of events following the postulated MHA is presented.
On the initiation of the break, the reactor coolant system water will partially flash into steam, and impinge on any equipment in its path. The water will flow down all paths available to it and collect in the sump in the bottom of the containment. The composition of the solution collecting in the sump initially will have the same composition that it had in the reactor coolant system when the reactor was operating at power except to be somewhat concentrated because of the flashing to steam. At the beginning of life, this composition could be as high as 1400 ppm of boron as boric acid with the pH adjusted by the addition of a chemical, such as lithium hydroxide. At the end of life, the boron concentration in the primary coolant will be essentially zero, and there may be a very small amount of lithium present for pH adjustment.
Approximately 5 seconds after the break, (for a 42 in. double-ended break), the four safety injection tanks will start to discharge into the reactor coolant system. These tanks contain 0.98 percent boric acid which is equivalent to 1900 ppm of boron. The pH of this solution is approximately 5. The composition of the refueling water tank and the solution in these tanks is essentially the same. The contents of the safety injection tanks fill the reactor coolant system with the excess spilling into the containment sump. Accordingly, the solution discharging onto the equipment within the containment at the break may start out as a neutral or slightly alkaline solution at end of life and then becomes more acidic as the safety injection proceeds.
Within 30 seconds after the break, the containment spray system starts to operate, spraying water from the refueling water tank into the top of the containment.
Accordingly, all of the components and structures above the sumps are drenched by the boric acid spray. The water in the sump and in the bottom of the containment is a solution which probably is somewhat alkaline and becomes more acidic as the spray continues.
Once the recirculation mode is started, the composition of the solution sprayed into the containment and that in the sump are the same except that the spray liquid will contain appreciable amounts of dissolved oxygen due to the exposure to the containment atmosphere. Within the reactor system and in portions of the sump the dissolved oxygen may be consumed in the corrosion reactions and the corrosive properties will be those of a nonoxidizing environment.
In summary then, the metals which are exposed to the spray have corrosion rates due to the boric acid solution with a pH of about 5, saturated with air and at temperatures ranging between 200-259F (Refer to Section 6.2.1.3.2) for a period of about 30-60 minutes (the tine until the recirculation phase for minimum safety feature operation). The containment atmosphere temperature falls slowly and tends to level out below 150F. The spray liquid is essentially saturated with air since there is no mechanism by which the oxygen in the containment could be appreciably depleted except for limited portions of the liquid within the
6.2-101 Amendment No.
26 (11/13) reactor coolant system or in the sump which have the corrosive properties of an oxygen-free borate solution.
Within the containment a variety of metals are present Including mild steel, several different low alloy steels, stainless steels (especially the 300 series), zinc (as galvanized iron), and aluminum.
A potentially important source of hydrogen production is from zinc and aluminum corrosion. Compared with zinc and aluminum, hydrogen generation from the other metals is insignificant. Experiments (References 10 through
- 14) have shown that the corrosion rate of aluminum in a borate solution is lower but comparable to that of zinc at high temperatures (approximately 0.02 mg/cm 2/day). Since the surface area (approximately 14250 ft
- 2) and weight (approximately 4480 lbs.) of aluminum are much less than the surface area (approximately 65,000 ft
- 2) and weight (approximately 26,800 lbs.) of zinc, the amount of hydrogen generated by corrosion of aluminum is considered negligible in comparison to that generated by zinc corrosion.
Southern Nuclear Engineering has performed experiments to determine the rate of evolution of hydrogen when galvanized iron strips are exposed to a 0.97 percent boric acid solution containing 9 ppm of lithium hydroxide. In these tests, 28 gauge galvanized iron was cut into strips about one inch wide and eight inches long. These strips were placed in a vessel containing the borated solution. The number of strips was such that a total of four sq ft of zinc surface was exposed to the test solution for each test. The amount of iron exposed by the edges amounted to approximately 9.7 sq inches. Tests were performed at 80F, 150F, 180F, and 205F. Each test was run for a period ranging from 50-150 hours.
The gas generation rates, assumed to be all from hydrogen, are given in Table 6.2-20 below. The hydrogen generation rates were measured at a temperature of 80F.
These rates were used with a conservative stepwise representation of the post-accident containment atmosphere temperature (205F from 0 to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after the accident; 180F from 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> to 5 days; 150F after 5 days) to calculate the net volume of hydrogen generated as a function of time for the conservatively assumed total area of 180,000 ft 2 of galvanized surface area (primarily ductwork and grating) externally ex-
6.2-102 Amendment No. 17 (10/99)
posed to the containment environment and the interior of ducts and cable trays which might be exposed to the solution. The containment steel liner is coated with an approximately 3 mil thick Carbo-zinc coating containing approximately 10,700 pounds of zinc with a non-zinc finish coating. Tests of specimens painted with the prime coating have been conducted and reported by the manufacturers (Carboline Research and Development Laboratory). The temperature for the test was increased to 200°F in the first hour and then linearly increased to
285°F over an additional three hours. After maintaining the temperature at 285°F for another three hours, it was decreased to 200°F in the last two hours. From the test results, 4.1 x 10
-5 grams of H 2 per square f eet of surface were generated from the chemical reaction of zinc with the solution during the testing period of nine hours. For the containment, the total, painted area is 0.94 x 10 5 ft 2 and, therefore, the amount of hydrogen generated due to the zinc in the prime coating would be 1.55 scf during the first nine hours after the occurrence of the MHA. Even if the same amount of hydrogen (1.55 scf) is assumed to be generated every nine hours after the MHA, the accumulated hydrogen from this source at any time after the accident would be negligible as compared to the amount of hydrogen generated by the other sources mentioned previously.
e) Total Hydrogen Generation The total hydrogen generated from the radiolysis of water, the zirconium water reaction, and metal corrosion are given in Figures 6.2-36 and 6.2-37 for the applicant model and Figures 6.2-38 and 6.2-39 for the Regulatory Guide 1.7 model. Figures 6.2-36 and 6.2-38 (reference cases) assume the corrosion rates given above. Figures
6.2-37 and 39 also assume those corrosion rates, but to be conservative also include an additional 0.20 lb-moles/day of hydrogen generation to account for any uncertainties in the overall rate of hydrogen production. The curves for the applicant model assume a 2 percent zirconium-water reaction takes place immediately following the MHA, while the contributions from radiolysis and corrosion are time dependent.
The process capacity of the hydrogen recombiners is such that each unit will preclude the hydrogen concentration limits specified in Safety Guide 7 from being exceeded.
Figure 6.2-37 shows that, for the applicant model, the required fixed purge rate necessary to prevent hydrogen concentrations in the containment from exceeding 4 volume percent is 11.5 cfm, starting approximately 110 days after the accident. Figure 6.2-39 shows that, for the Safety Guide 7 model, the required fixed purge rate would be 28 cfm, starting 45 days after the accident.
f) EPU Impact on Containment Combustible Gas Control The EPU has no impact on the fundamental mixing mechanisms identified in UFSAR Section 6.2.5.3 or the capability of the hydrogen monitoring system to diagnose beyond design basis accident hydrogen concentrations.
6.2.5.3.3 Offsite Doses Due to Hydrogen Purging Operations Assuming the highly unlikely unavailability of both hydrogen recombiners, purging will begin if analysis of the containment atmosphere indicates that the hydrogen flammability concentration level has been approached. The design allows flexibility such that advantage can be taken of favorable meteorological conditions during the purging operation.
6.2-103 Amendment No. 2 6 (11/13)
Conversely, purging can be halted during periods of less favorable meteorology. The design also includes redundant components to assure a high degree of operational reliability.
The system design has enough margin in it to allow for contingencies. The calculational assumptions are purposely conservative and thus in many cases are not physically consistent. This is particularly evident in the different assumed values of halogens in the containment sump water. For maximum whole body doses, all the halogens released from the core are assumed in the water; for maximum thyroid doses only a certain fraction is assumed in the water; and for charcoal filter loading all of the halogens are assumed to be trapped in the charcoal.
Of major concern in a purging system is that radioactivity released during venting be kept as low as practically possible. In this regard, purging would commence as long after the postulated accident as practical to allow substantial decay of the containment activity. This, coupled with the use of charcoal filters in the purge lines, will allow consequences to be insignificant at the exclusion area boundary.
The shield building ventilation system provides backup purging capability.
6.2.5.4 Testing and Inspection Switches, solenoids, and relays are shop energized to check operation. Electrical interlocks are shop checked under simulated operating and/or emergency conditions. Prior to installation, the vendor performs a system operation test, using air to demonstrate the operability of the analyzer system. The analyzer is operationally tested using calibrated gas samples introduced at the sample selector panel.
Purchase specifications require that vendors submit type test, calculational or operating data which verifies the ability of the equipment to function following a design basis earthquake.
The purging system charcoal and HEPA filters are designed to remove radioactive iodine and particulates and are shop tested to assure compliance with purchase specifications.
Preoperational testing was performed on the purge and sampling system to ensure that the system function is as required by the design bases. The hydrogen analyzer is calibrated by introducing a test sample of known concentration. The electronic output signal may be checked introducing an electronic test signal.
There are no special test provisions required to monitor the Hydrogen Purge System for operability in pressure control function.
Preoperational testing procedures for the hydrogen recombiner have been developed. Three tests are performed to achieve the purpose of the preoperational procedure: (1) the preoperational test; (2) the recombiner heat up test, and (3) the air flow test. The preoperational test is performed in order to determine the temperature-to-power relationship of the recombiner heaters and verify their operability. Included is an alarm annunciation test in which the thermal cutout circuit is tested in its function to cut off recombiner power on
6.2-104 Amendment No. 26 (11/13) high temperature alarm from the heaters. The heat up test is performed to calibrate the recombiner power setting with temperature for proper operation under post LOCA conditions. Intake air flow rate characteristics and proper recombination flow rate are verified in the air flow test.
Periodic testing of the hydrogen control system is discussed in the plant Technical Specifications.
6.2-105 a) Adsorber Considerations Charcoal adsorber performance can be affected by humidity and adsorber heating. Methyl iodine efficiency is a function of relative humidity with this effect becoming important for impregnated charcoal at relative humidities greater than 90 percent. The onset of desorption of iodine occurs at about 300°F. These effects are evaluated below. Note that the purge system is a backup to two 100 percent capacity recombiner systems, and the hydrogen generation rate is predicted in accordance with Regulatory Guide 1.7 methodology which yields a conservative upper limit value suitable for sizing such systems. Operation of the purge system for post-LOCA hydrogen control is most unlikely. Nonetheless, operation of the system is assumed for design evaluation purpose s. 1) Adsorber Efficiency For Methyl Iodide (Historial)
The offsite consequences of post-LOCA hydrogen purging for the Siemens thin cladding fuel design are referenced in Section 15.4.1.2.5. Regulatory Guide 1.7 methodology requires that purging begin at a rate of 28 cfm, 45 days after the incident, and an analysis considered more representative of actual accident conditions indicates that purging begins, at a rate of 11.5 cfm, 110 days after the incident. Assumptions used in the analysis of the offsite consequences of purging at these rates are provided in Table 15.4.1-6, and the resultant long term thyroid doses calculated are:
Regulatory Guides Applicant's Model 1.4 & 1.7 Exclusion area boundary distance (R EM) 0.0011 0.55 Low population zone radius (R EM) 0.000082 0.050 Arbitrarily assuming a zero percent methyl iodide efficiency results in an increase of the maximum thyroid dose from 0.55 to 0.87 R EM. Obviously with the extremely low resultant offsite doses calculated using conservative regulatory guide methodology and the extremely remote likelihood of operating this system, the question of methyl iodide efficiency is academic. Humidity control, i.e., heaters,are not required for the purge system.
- 2) Adsorber Heating Purge system operation is dependent on the rate of hydrogen generation, which is discussed in Section 6.2.5.3.2.
Based on the analysis considered representative of the accident, purging would not be required for 110 days or about 13.6 iodine-131 half lives. Thus, radioactive decay will effectively eliminate the adsorber heating concern for the more likely case.
The case based on Regulatory Guide 1.7 states that purging at a rate of 28 cfm is to begin 45 days after the accident to maintain the required hydrogen concentration within containment. This mode of operation, i.e., a continual purge of 28 cfm, is considered
6.2-106 Amendment No. 24 (06/10)
unlikely. Purging periodically at the design purge rate of 100 cfm is more the probable operating mode.
The latter operating mode is preferable since it allows control of purging operations to coincide with favorable meteorological conditions, and eliminates operating problems associated with the control of very low purge rates. If purging at 100 cfm were conducted for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, it could be terminated for about 85 hours9.837963e-4 days <br />0.0236 hours <br />1.405423e-4 weeks <br />3.23425e-5 months <br /> before purging need be resumed.
To assess the filter heat loading in a manner consistent with Reg. Guide 1.7, the 28 cfm continual purge rate case was analyzed assuming the following unrealistic but conservative assumptions. In this manner, an upper limit heat loading is estimated:
a) The iodine release to containment results in 25 percent of the equilibrium core iodine inventory being uniformly dispersed within the containment and available for leakage.
b) The iodine decays for 45 days. During this period, all containment leakage is assumed to be zero.
c) The radioactive decay of the iodine inventory after 45 days (essentially I131) is accounted for within containment and on the filters.
d) All iodine removed via the 28 cfm purge is deposited on the charcoal adsorbers, i.e., a 100 percent efficiency is assumed for all iodines.
The resulting peak heat load on the purge filters is about 240 Btu/hr. The heat of oxidation at 200F is about 33 Btu/hr, thu the total adsorber heat load is 277 Btu/hr. Adsorber temperatures are annunciated above 200F. Only 2.5 scfm of 95F air is required to remove this heat load.
It is conceivable, but not likely, that the containment purge system be operated continuously at rated capacity of 500 cfm (100 cfm purge plus 400 cfm outside dilution air). Under these conditions, the peak heat loading of 730 Btu/hr is reached in about 213 hours0.00247 days <br />0.0592 hours <br />3.521825e-4 weeks <br />8.10465e-5 months <br />. Adding the heat of oxidation yields 766 Btu/hr, which requires only 6.9 scfm of 95F air. If credit for containment leakage is assumed, the peak decay heat load is reduced to about 583 Btu/hr.
Accounting for oxidation, the peak becomes 616 Btu/hr and the cooling air required is 5.6 scfm.
Based on the trivial quantities of cooling air required, the highly unlikely utilization of this system and the ability to provide 400 cfm of outside cooling air from either fan, it is concluded that the design provides satisfactory cooling of the adsorber beds.
6.2-107 Amendment No. 17 (10/99)
6.2.5.5 Instrumentation Application The hydrogen purge exhaust line is normallyisolated by two remotely closed ball valves (FCV 25 20, FCV 25 21) operated from the control room. The outside air makeup line is normally isolated by two locked closed gate valves (V25011, V 25 12) in series. When the containment air analysis indicates that the limit of hydrogen has been reached, the purge system is put into operation under strict administrative controls as follows (refer to Figure 9.4-2): a) Fan HVE-7A or HVE-7B are remote manually started from the control room.
b) Valve FCV-25-10 is normally maintained throttled allowing outside air flow through the filters.
c) Purge valves BCV 25 20 and FCV 25 21 are remote manually operated from the control room and local manually operated.
d) Flow control valve FCV-25-9 is positioned from a remote switch in the control room to provide a purge flow rate conservatively based on the hydrogen concentration rate of increase.
e) The isolation valve V25013 is normally open and manually operated when testing Containment Isolation Valves FCV 25 20 and FCV 25 21.
The outside air makeup line isolation valves are manually unlocked and opened to prevent a buildup of vacuum in the containment. A check valve is provided in the line to prevent backflow to the environs.
Each of the seven sampling lines of the containment hydrogen sampling system are isolated from the containment atmosphere by two normally closed solenoid operated isolation valves arranged in series. These valves are remote manually actuated from the control panel in the control room.
The hydrogen purge system includes a flow recorder in the control room for monitoring the purge rate. Temperature sensors in the charcoal adsorber beds provide indication in the control room of buildup in charcoal temperature due to decay heat. Temperatures exceeding 200F are annunciated. Relative humidity of the-air upstream of the charcoal adsorber is locally indicated. Relative humidities in excess of 85 percent are annunciated in the control room. A radiation monitor is provided in the plant vent to determine radiation levels in the purge effluent when it is exhausted via that route.
Instrumentation provided to monitor, record and/or alarm purge and sampling system performance and operation is presented in Table 6.2-21.
6.2-108 Amendment No. 2 6 (11/13)
REFERENCES FOR SECTION 6.2.5
- 1. Allen, A.O., The Radiation Chemistry of Water and Aqueous Solutions, Van Nostrand Co., Inc. (1961)
- 2. Ershler, B. V. and Myasishcheva, G. G., "Mechanism of the Radiolysis of an Aqueous Solution of H 2 , O 2 , and H 2 O 2 Proc. of 2nd All-Union Conf. on Radiation Chemistry, translated from Akademiya Nauk. USSR (1964).
- 3. Gordon, S. and Hart, E. V., "Radiation Decomposition of Water under Static and Bubbling Conditions," 2nd International Conference on the Peaceful Uses of Atomic Energy, A/CONF. 15/P/52, Geneva (1958).
- 4. Zittel, H. E., ORNL Nuclear Safety Research and Development Program, Bi-Monthly Report for September - October 1967, ORNL-TM-2057. 5. Zittel, H. E., ORNL Nuclear Safety Research and Development Program, Bi-Monthly Report for March - April 1969, ORNL-TM-2588. 6. Zittel, H. E., ORNL Nuclear Safety Research and Development Program, Bi-Monthly Report for May - June 1969, ORNL-TM-2663.
- 7. Not Used
- 8. "SHADRAC, Shield Heating and Dose Rate Attenuation Calculation," 630-1365 (1966).
- 9. Shure, K., "Fission Product Decay Energy," WAPD-BT-24, Dec. 1961.
- 10. Evans, U. R., Corrosion Oxidation of Metals, p. 316, London, 1960
- 11. Uhlig, H. H., "Corrosion Handbook", N.Y., 1948
- 12. Owen, B. B., "Journal of the American Chemical Society," Vol, 56, p. 1110, 1934
- 13. Draley and Ruther, "Corrosion," Vol. 12 p. 441 T, 1956
- 14. Uhlig, H. H., Corrosion and Corrosion Control, N.Y., 1967 6.2-109 Amendment No. 24 (06/10)
6.2.6 IODINE REMOVAL SYSTEM In response to the NRC's letter of September 3, 1974 FPL committed to revise the short term accident x!O values used in the analysis of the design basis functional requirements of the Engineered Safety Features (ESF) and Technical Specifications for containment leak rate. In this response FPL committed to modify the ESF design to provide sufficient dose reduction in the LOCA event to meet the dose requirements of 10 CFR 100 at a low population zone (LPZ) distance of one mile. FPL's response is documented in Appendix 68 of the UFSAR. This response resulted in the establishment of License Conditions 1.1 and 1.2 to require installation of a containment spray additive system (Iodine Removal System -IRS) and installation of auxiliary heaters in each train of the Shield Building Ventilation System (SBVS). License Conditions 1.1 and 1.2 were satisfied by the installation of the IRS and the auxiliary heaters in the SBVS filter trains. The requirements for the IRS and SBVS auxiliary heaters were incorporated into the Technical Specifications in Amendments 26 and 27, respectively.
6.2.6.1 Design Bases The iodine removal system is designed to operate in conjunction with the containment spray system to remove radioiodines from the containment atmosphere following a loss of coolant accident.
The iodine removal system (IRS) is designed to the following criteria:
a) To maintain the containment spray solution pH to achieve rapid absorption of radioiodines and minimal caustic corrosion of materials and protective coatings within the containment.
b) To maintain the containment spray removal system nozzle spray pH between 7.89 and 9.49. The EPU dose assessment assumes containment spray pH is maintained above a conservatively computed minimum of 7.89 and conservatively computed maximum of 9.49. c) To achieve a containment sump pH equal to or greater than 7.0 but less than 9.66 after all the spray chemical mixes with the available water inventory including, RWT, safety injection tanks, boric acid makeup tanks, and the reactor coolant system blowdown to assure retention of iodine in the sump solution.
The EPU dose assessment evaluated the St. Lucie Unit 1 post-LOCA containment recirculation spray and sump bounding pH values for extended power uprate (EPU) operating conditions based on the bounding borated water concentrations for the RWT and SITs, as well as the bounding sodium hydroxide (NaOH) concentrations in the sodium hydroxide tank. In addition, the pH values consider the generation of hydrochloric acid (HCI) and nitric acid (HN0 3) per the methodology reported in NUREG/CR-5950 (Reference
[5]). A maximum pH value case also includes consideration of CsOH. This assessment also determined the containment spray pH during injection.
The concentration of NaOH is calculated based upon the maximum and minimum containment spray flow rate in order to calculate the minimum and maximum pH during injection, respectively.
The results of that assessment are summarized in the table below: Summary of calculated pH values Case H Minimum 30 da ost-LOCA sum H 8.14 Maximum 30 da ost-LOCA sum H 9.66 Maximum 30 da ost-LOCA sum H with CsOH 9.66 Minimum recirculation sum H 7.03 Minimum one hour ost-LOCA sum H 7.45 7.89 9.49 6.2-110 Amendment No. 26 (11/13)
All containment sump pH levels calculated are determined to be greater than or equal to 7.0. Thus, the regeneration of iodine (1 2) due to radiolysis will not be significant per Section 3.1 of Reference
[5] and the requirements of Section 111.4.c.ii of SRP Section 6.5.2 (Reference
[6]) are met. d) To remove elemental and particulate iodines with the minimum following first order removal coefficients.
Iodine Form First Order Removal Coefficient Elemental Particulate 6.07 h(1 e) To minimize the possibility of precipitation of the spray solution within the system or its inadvertent introduction into the refueling water tank. f) System materials are chosen for compatibility with sodium hydroxide.
g) To be seismic Category I, Quality Group B, and function under post-accident environmental conditions (based on location).
h) To perform its function following a LOCA, assuming a single active component failure. 6.2.6.1.1 System Interfaces Interfaces are as follows: The IRS is in essence a subsystem of the containment spray system (see Section 6.2.2). a) The NaOH storage tank is located in the west end of the -0.5 ft elevation of the reactor auxiliary building in such a manner as to yield a minimum static head of approximately 9.0 feet at the eductor suction nozzle. 6.2-110a Amendment No. 26 (11/13) b) The NaOH storage tank is normally provided with a nitrogen cover gas. The nitrogen supply is not required for the IRS to function.
Nitrogen is provided as a cover gas to limit the interaction of NaOH with carbon dioxide and to provide tank agitation to prevent potential stratification.
c) The containment spray headers are located in the upper region of the containment such as to provide complete coverage of the containment area below. (See Figures 6.2-50 and 6.2-51.) The design of all interface systems will be consistent with the required function to support the iodine removal system (IRS). 6.2.6.2 System Design 6.2.6.2.1 Description The iodine removal system (IRS) design is consistent with the design philosophy used in all engineered safety feature systems. The system is redundant and will function with allowance for a single active failure. The NaOH storage tank is located inside the reactor auxiliary building and the temperature in the area surrounding the tank is above the precipitation point. Therefore heating of the system is not required.
A nitrogen cover gas at atmospheric pressure is normally provided for the NaOH storage tank to preclude deterioration of the NaOH. The iodine removal system is shown in Figure 6.2-28. System design parameters are given in Table 6.2-22. The IRS consists of (1) NaOH storage tank, (2) isolation valves, (3) NaOH flow orifice, (4) spray nozzles, and (5) system eductors.
See Figure 6.2-28. The design of the IRS is based on a combination of a buffered solution of borated water and sodium hydroxide.
The sodium hydroxide is stored in the NaOH storage tank and proper amounts are drawn into the suction of the containment spray pumps through the use of eductors.
The actual flow is indicated in the control room. Upon receipt of the containment spray actuation signal (CSAS), isolation valves open in the line to allow flow of the caustic solution to commence.
The sodium hydroxide flow rate is measured by a flow orifice in the caustic line and is determined by the eductor size and the vacuum created by the containment spray pump flow. Utilizing this control system assures proportionate injection of NaOH flow throughout the transient.
The NaOH injection rate is set to adjust the pH of the spray water between 7.89 and 9.49 at the containment spray nozzles. Upon reaching low-low level in the NaOH storage tank, the caustic line isolation valves close to isolate the NaOH storage tank, thereby ending injection of sodium hydroxide.
6.2-111 Amendment No. 26 (11 /13)
The injection system is designed to be fully automatic yet is capable of local manual control. The total quantity of NaOH injected will ensure a containment sump pH greater than or equal to 8.5 for long term recirculation.
The containment sump pH based upon conservative assumptions for the EPU dose assessment is provided in Section 6.2.6.1. The containment spray nozzle design is effective in removing iodine from the post-LOCA containment atmosphere.
The spray nozzles are non-clogging headers in the upper portion of the containment to provide complete coverage of the containment area below. Table 6.2-22 gives the number of nozzles per spray header. Figures 6.2-50 and 6.2-51 show the nozzle spacing, location and orientation, for the containment spray system. Using this information, an effective mean fall height of 140 feet has been calculated for the spray droplets.
This calculation was performed taking into account the effective areas of equipment above the operating deck, (e.g., the steam generators) and areas below the operating deck. The steel grating at elevation 23 feet is assumed to have an effective area of 1 /3 of the total surface area. Each spray nozzle is designed such that when oriented to spray vertically downward at a distance of 10 feet, the nozzle sprays produce a circle of 452 square feet. This spray pattern has been verified by test by the nozzle manufacturer; Spraying System Company, Wheatan, Illinois.
The volume mean diameter of the spray droplets is 763 microns. This value was determined using high-speed photography of the spray droplets produced by the St. Lucie nozzles. The containment spray (CS) pumps were not originally designed for operation with the IRS. However, the following design considerations have been met: a) The eductor is sized such that, if a single spray pump fails the caustic solution required to maintain a pH of at least 7.89 at the spray nozzles will be delivered by the remaining spray pump. Therefore, the single failure criterion is met. b) The NaOH tank isolation valves will be fully open by the time the spray pumps reach full speed. Considering the above discussion, the design assures that the required amount of NaOH is added. All components of the iodine removal system required to perform a safety function are seismic Category I and Quality Group B. The caustic line isolation valves are solenoid operated.
These solenoid valves will fail closed in event of loss of de power. The containment spray actuation signal (CSAS) which initiates containment spray also activates the iodine removal system. The activation of the iodine removal system entails opening solenoid valves l-SE-07-1A, l-SE-07-1 B, l-SE-07-2A and l-SE-07-2B.
6.2.6.2.2 Modes of Operation The modes of operation of the iodine removal system conform to those of the containment spray system as follows: a) containment spray (injection
-suction from RWT); 6.2-112 Amendment No. 26 (11/13) b) long term containment spray with limited chemical addition (for single failure of one CS pump only).
Spray initiation starts with receipt of a containment spray actuation signal (CSAS) on high-high containment pressure in coincidence with a safety injection actuation signal (SIAS). Full spray flow at the nozzles commences within 61.3 seconds following CSAS assuming loss of offsite power.
The flow rates for the containment spray and chemical injection are shown in the matrix below for the three cases:
Case 1: Minimum safeguard flow, (i.e., 1 CS pump + 1 HPSI pump + 1 LPSI pump). Loss of offsite power with one diesel failure.
Case 2: Maximum safeguard flow and single failure of one CS pump (i.e., 1 CS pump + 3* HPSI pumps + 2 LPSI pumps). Offsite power available.
Case 3: Maximum safeguard flow (i.e., 2 CS pumps + 3* HPSI pumps + 2 LPSI pumps). Offsite power available.
_______________
- Currently, only pumps 1A & B are available for the HPSI system. The 1C HPSI pump has been abandoned in place.
6.2-113 Amendment No. 17 (10/99)
SAFEGUARD SYSTEM TOTAL CS TOTAL CS ADDITIVE CASE OPERATION MODE FLOW-GPM FLOW-GPM 1 INJECTION 2550-4151 16.5-19.5 RECIRCULATION 2550-3800 16.5-19.5 2 INJECTION 2550-4151 16.5-19.5 RECIRCULATION 2550-3800 16.5-19.5 3 INJECTION 5100-8302 33.0-39.0 RECIRCULATION 5100-7600 33.0-39.0 6.2-114 Amendement No. 26 (11 /13) 6.2.6.3 Design Evaluation 6.2.6.3.1 Theory of Iodine Removal by Containment Spray Using the models described in WASH-1329, an evaluation of the effectiveness of the IRS in removing radioiodine from the containment atmosphere post LOCA has been performed.
The removal of radioiodine is considered to be a first order rate phenomenon and is mathematically described below:
Which integrates to:
where: Airborne concentration Removal rate constant Initial concentration Time of spray operation which is a function of the iodine absorption efficiency of the spray droplets (E), the iodine partition coefficient (H), the flow rate of the containment spray system (F), and the containment volume (V).
The iodine adsorption efficiency of the spray droplets (E) takes into account the mass mixture transport process of iodine from the containment air steam to the spray drops and within the drops themselves, and the hydrodynamic and aerodynamic behavior of the drops as they fall through the containment. The mass transfer model used to calculate the transfer of iodine considers both the interface gas film resistance and the liquid phase resistance of the drops. The effect of drop saturation inhibiting mass transfer rates is not considered since calculations show that saturation does not occur in the time interval of drop transit through the containment atmosphere.
The partition coefficient, H, is defined as the equilibrium ratio of the concentration of iodine in the liquid phase to concentration in the gas phase. It is a function of temperature, pH, and iodine concentration. Experimental data (1) indicates that adjusting the pH of the containment spray by the addition of NaOH to a sufficiently alkaline value will shift the partition of iodine significantly toward the liquid phase, thus dissolving more airborne iodine.
6.2-115 Amendment No. 25 (04/12)
6.2.6.3.2 Calculation of the Elemental Iodine Removal Rate Pursuant to WASH-1329, the removal rate of elemental iodine by sprays with a sodium hydroxide composition has been evaluated. The elemental iodine removal rate is related to the spray parameter as follows:
where V
= Overall deposition velocity, h = Spray droplet mean full height F = Spray flow rate V = Containment net free volume D = Mean droplet diameter U = Spray droplet terminal velocity The deposition velocity is evaluated from where = Overall deposition velocity, = Gas film mass transfer coefficient, = Liquid film mass transfer coefficient,
= Iodine partition coefficient The liquid film mass transfer coefficient is predicted by:
where = Diffusivity of iodine in water, = Mean drop diameter The gas film mass transfer coefficient is predicted by:
where = Diffusivity of iodine in gas phase = Reynolds number = Schmidt number = Mean drop diameter, cm
The spray droplet terminal velocity U, was evaluated using the following equation:
(2) 6.2-116 Amendment No. 25 (04/12)
where = Acceleration due to gravity = Mean Drop diameter = Drop density = Containment air density = Viscosity of containment air Using the methodology described above and the calculated parameters given in Table 6.2-22, an elemental A correction factor of 0.9 has been applied to the iodine removal rate.
This compensates for the fact that 10% of the containment net free volume (i.e., the volume under the operating deck) does not see the NaOH spray. The elemental iodine removal rate has therefore been calculated to be.
From an offsite dose evaluation viewpoint, as per WASH-1329, an elemental iodine removal rate of 10 hr
-1 has been used. In addition, a maximum overall decontamination factor of 100 has been used in the offsite dose evaluation studies of LOCA. 6.2.6.3.3 Calculation of the Particulate Iodine Removal Rate As per WASH-1329, the particulate iodine removal rate is described by the following relationship:
where = spray droplet mean fall height = spray flow rate = iodine adsorption efficiency of the spray droplets = mean droplet diameter = containment net free volume Using the equation above a particulate iodine removal rate constant has been evaluated. This value is:
As described previously, a correction factor of 0.9 has been applied to the AP above. The final value calculated is therefore:
Consistant with WASH-1329 a maximum particulate iodine removal rate coefficient of 0.45 hr
-1 has been used in the offsite dose evaluation studies. 6.2.6.3.4 Containment Iodine Removal Modeling The revised analysis of Technical Specification Amendment #38 uses a conservative two compartment containment model that takes into account the difference in iodine scrubbing effectiveness between the regions of the containment that receive or do not receive spray coverage. The volume of the containment atmosphere that is sprayed is conservatively assumed to be 86%. Mixing is assumed to occur between the sprayed and unsprayed regions at a rate of four (4) volumes of unsprayed regions per hour. In this conservative model it takes 44 minutes for the sprays to reduce the elemental iodine concentration in the containment by the allowable factor of 100. The removal of particulate iodine by the sprays is terminated at one (1) hour. The pH of the sodium hydroxide solution at the spray nozzle will be between 8.5 and 11. The bounding LOCA event dose consequences in the Technical Specification Amendment #38 design basis analysis are summarized in UFSAR Section 15.4.1.8.
6.2-117 Amendment No. 25 (04/12)
6.2.6.4 Testing and Inspections Sufficient instrumentation is provided to enable the operator to assess the status of the system in the standby or operational mode. Level indication is provided locally and in the control room to assess tank availability. A level alarm in the control room will indicate a fall of caustic to the low level. Four separate level switches are provided to close the solenoid valves (SE-07-1A, SE-07-1B, SE-07-2A and SE-07-2B) after the required volume of NaOH has been injected into the Containment Spray System. Temperature indication is provided locally.
The containment spray and iodine removal systems are designed to allow testing of components and actuation logic to the maximum extent practicable. The design of the IRS allows for a full test of the actuation and control logic. The testing of the NaOH addition equipment is described below.
The eductors were shop tested to verify flow under two conditions; full pressure, full flow with water and partial pressure, partial flow with water. After system installation the chemical addition tank was filled with water and the system was tested at partial pressure, partial flow conditions. The in place data was then compared with the shop data and ejector flow was verified.
Periodic testing of the system is accomplished by applying an electrical test signal to the controller simulating containment spray flow after manually isolating the line from tank to the eductors. As the solenoid valves open in response to this signal, the flow through the lines is essentially started. The opening and closing of the solenoid valves are verified by the indication of lights in the control room. Thus, not only is the physical opening of valves confirmed, but also controller logic is verified.
Additionally, test valves are provided in the NaOH system to provide a means to verify flow paths in accordance with the Technical Specification requirements. Flow through the system from the tank discharge through the eductors can be verified by observing flow of demineralized water supplied to the system at the test connection downstream of the tank isolation valve, and discharged at the valves downstream of the mixing eductors. Flow may be verified visually by observing fluid exiting the system downstream of the eductors or by use of the system flow indication instrumentation. During normal plant operation, the NaOH injection system test valves are locked closed to insure system integrity.
The containment spray system testing and inspection is described in Section 6.2.2.
Spraying Systems Company has conducted tests to verify the spray pattern and droplet sizes. Spray droplet measurement is done without the use of any collection medium which may interfere with effective collection of particle size data. This is accomplished with the use of a TV camera, a TV monitor, a strobe light and a computer console as shown on Figure 6.2-53. The analyzer was used to count and measure the particles as follows:
6.2-118 Amendment No. 25 (04/12)
a) A nozzle spray was positioned between the strobe light and the TV camera.
b) As the stroboscope flashes, the television camera receives the spray drop images whose motion is stopped by the rapid strobe light source.
6.2-119 c) The image that is now on the vidicon tube is scanned in the television camera and the electrical impulses formed by these images is sent to the electronic counting and measuring circuits housed in the console.
d) The console as it receives these impulses analyzes as follows:
- 1) It determines whether a drop is in focus or out of focus; if it is out of focus, it is rejected and not counted.
- 2) If the drop is in focus, its diameter is then determined by the number of TV scan lines that pass through the drop.
- 3) The spray particle is counted by being recorded on one of the nine meters on the right side of the console. Each one of these meters represents a particular particle size range (20-25 microns, 25-30 microns, etc., all the way up to 20,000 microns) in steps of four magnification ranges.
e) Once the image on the television screen has been scanned and all of the spray particles in the image have been measured and counted by the electronic circuits, the image is erased and the strobe light flashes once more to put a new image on the television tube. The time element between light flashes, for all this to occur is extremely short and approximates 1/3 of a second.
In order to obtain reasonably accurate particle size data, the analyzer is calibrated. This is accomplished with etched slides which contain images of particles of specific diameters which conform to specific channels in each magnification range. These slides are placed in the cameral s field of view and the equipment is then adjusted until the proper count is obtained in the proper channel. Only when this is accomplished is the equipment ready for operation.
After the actual counting of particles is accomplished in one or more magnification ranges, certain constants and boundary conditions are applied to the data in order to apply drop velocity corrections. Since the spray is composed of drops of many different sizes traveling at different velocities at the measuring zone, corrections must be applied to the data in order to obtain an accurate sampling. Because of the complexity of the mathematics involved, these calculations are done by computer. The results for St. Lucie are found on Table 6.2-
- 23. 6.2-120 6.2.6.5 Instrumentation Application Instrumentation is provided for monitoring the actuation and performance of the Iodine Removal System. The instrumentation is as follows:
Instrument Function Chemical Storage Tank (CST) Press ure Indicates pressure (1) and alarms (2) on high N 2 cover gas pressure CST Temperature Indicates temperature (3) of NaOH CST Level Alarm Indicates level (1) and alarms (2) on low and low
-low level NaOH Flow Indicator and Recorder Indicates and records flow rate (2) of NaOH (1) Local and control room (2) Control room (3) Local
6.2.6.6 Materials
The materials used in the IRS are compatible with NaOH solution and the environment for the following reasons:
a) The specifications restrict metals contacted by reactor coolant to austentic stainless steel, Type 316, 304 or an acceptable alternative material.
b) None of the materials used are subject to decomposition by the radiation or thermal environment. The specifications require that the materials be unaffected when exposed to the equipment design temperature, the total integrated radiation dose, the caustic solution and the boric acid.
6.2-121 The corrosion of materials normally found in reactors and the containment building due to spray solution used for iodine adsorption has been (3)(4) tested The information obtained from these tests can be summarized as follows: a) Aluminum alloys were subject to severe corrosion in the caustic soda solution.
b) Copper and its alloys corrode at a low rate with an alkaline borate solution.
C) Carbon steels are generally resistant to corrosion with the alkaline borate solution.
d) Stainless steel is inert in alkaline borate solutions.
e) Galvinized surfaces are subject to corrosion by alkaline borate solution sprays.
f) Inconel 600 and 718, Zircaloy 2, and Monel 400 were almost completely inert in the alkaline borate solution.
g) Concrete exposed to an alkaline borate solution showed no loss of crush strength and the load carrying capacity is not affected.
Sodium hydroxide is not known to undergo significant radiolytic decomposition. Sodium has a low neutron adsorption cross section and will not undergo significant activiation.
With respect to the susceptibility of (NaOH) to pyrolytic decomposition, sodium hydroxide is stable at least to its melting point temperature of 604 F. It may convert to sodium oxide (Na
- 20) upon removal from water.
6.2-122 REFERENCES FOR SECTION 6.2.6 1. Parsly, L.F., "Calculation of Iodine-Water Partition Coefficients," ORNL-TM-2412, Part IV. 2. Chemical Engineers Handbook, Second Edition, 1941, page 1855. 3. WCAP -7153, Westinghouse Confidential Report, March 1968. 4. ORNL-TM-2412, "Design Considerations of Reactor Containment Spray Systems -Part Ill Corrosion of Materials in Spray Solutions," J. C. Griess and A. L. Bacarella, December 1969. 5. NUREG/CR-5950, "Iodine Evolution and pH Control," December 1992. 6. NUREG-0800, Section 6.5.2, "Containment Spray as a Fission Product Cleanup System," Revision 4. 6.2-123 Amendment No. 26 ( 11 /13)
TABLE 6.2-1 Summary of Containment Analysis Pressure I Temperature Results and Criteria Parameter Pressure (psig) Temperature
(°F) Containment Design Criteria:
-Pressure 44.0 -Temperature (Cont. Vessel) Original FSAR Analyses:
-LOCA Pressure 38.4 -LOCA Temperature
-MSLB Pressure 41.6 -MSLB Temperature Technical Specification Limits: -ILRT Pressure 42.8 -Vessel Temperature EPU Analyses*
- -LOCA Pressure**
42.77 -LOCA Temperature***
Component Cooling Water: -Design Temperature
-EPU Analysis Temperature See UFSAR Section 6.2.1 Reference (9) for results of break spectrum.
- Double-ended hot leg slot break. *** Double ended discharge leg break 264.0 259.0 290.0 264.0 245.69 120.0 119.94 **** **** Double-ended hot leg slot break. See UFSAR Section 6.2.1 Reference (18) for analysis results. 6.2-124 Amendment No. 26 (11 /13)
TABLE 6.2-1A TYPICAL NON-SEISMIC CLASS I EQUIPMENT INSIDE CONTAINMENT
Electrical Equipment
- 1) Communications handsets, and speaker signal lamps
- 2) Lighting panels
- 3) Lighting fixtures, toggle switches, and receptacles
- 4) Pull terminal and control station boxes
- 5) Power (welding) receptacles 6) Small distribution transformers HVAC Equipment
- 1) Airborne radioactivity removal units (HVE-1,2)
- 2) CEDM cooling system (HVE-21A, 21B) 3) Ducts associated with above Mechanical Equipment
- 1) Reactor cavity sump pumps
- 2) Piping* a) primary water line b) component cooling water lines (non-essential header) c) instrument and station air lines d) Reactor cavity sump pump discharge e) refueling water purification lines
- 3) Pressurizer quench tank
- 4) Refueling machine and mast
- 5) Fuel upender
- 6) Two instrument air compressors, one air dryer, one air receiver and associated piping. (Abandoned in place)
_______________ *These piping lines are either located at grade level or near the floor
6.2-125 Amendment No. 25 (04/12)
TABLE 6.2-1B 24" VACUUM BREAKER FLOW RATE (LB/HR) VS TIME AND CONT.-ANN DIFFERENTIAL PRESSURE FOR CT=120F ST=60F HUM=0%
Containm ent-Annulus (PSI) Flow Rate (AnnulusCont) (LB/HR) Time (sec) 0.5 -0.026 0 1.0 -0.051 0 1.5 -0.075 0 2.0 -0.0995 0 2.5 -0.123 8.5 x 10 2 3.0 -0.147 2.46 x 10 3 3.5 -0.169 6.34 x 10 3 4.0 -0.1 91 1.14 x 10 4 4.5 -0.213 1.88 x 10 4 5.0 -0.233 2.76 x 10 4 5.5 -0.252 3.77 x 10 4 6.0 -0.270 4.64 x 10 4 6.5 -0.287 5.66 x 10 4 7.0 -0.304 6.69 x 10 4 7.5 -0.319 7.31 x 10 4 8.0* -0.333 7.79 x 10 4 8.5 -0.347 8.00 x 10 4 9.0 -0.361 8.16 x 10 4 9.5 -0.374 8.31 x 10 4 10.0 -0.387 8.45 x 10 4 10.505 -0.399 8.58 x 10 4 6.2-126 TABLE 6.2- Time (sec) Containment
-Annulus (PSI) Flow Rate (AnnulusCont) (LB/HR) 11.0 -0.411 8.70 x 10 4 11.495 -0.422 8.81 x 10 4 11.99 -0.433 8.93 x 10 4 12.485 -0.444 9.03 x 10 4 12.98 -0.454 9.14 x 10 4 13.475 -0.464 9.23 x 10 4 13.97 -0.474 9.32 x 10 4 14.465 -0.483 9.41 x 10 4 14.96 -0.492 9.5 x 10 4 15.455 -0.501 9.58 x 10 4 15.95 -0.509 9.65 x 10 4 16.445 -0.517 9.72 x 10 4 16.94 -0.525 9.79 x 104 17.435 -0.532 9.86 x 10 4 17.93 -0.539 9.92 x 10 4 18.425 -0.546 9.98 x 10 4 18.92 -0.553 1.003 x 10 5 19.415 -0.559 1.009 x 10 5 19.91 -0.566 1.014 x 10 5 22.015 -0.589 1.033 x 10 5 24.015 -0.608 1.048 x 10 5 27.515 -0.632 1.065 x 10 5 30.015 -0.644 1.073 x 10 5 30.315 -0.645 1.074 x 10 5 6.2-127 TABLE 6.2- Time (sec) Containment
-Annulus (PSI) Flow Rate (AnnulusCont) (LB/HR) 30.615 -0.646 1.0745 x 10 5 30.915 -0.64 7 1.0750 x 10 5 31.215 -0.648 1.0755 x 10 5 31.515 -0.649 1.0760 x 10 5 31.815 -0.65 1.0764 x 10 5 32.115 -0.6505 1.0768 x 10 5 32.415 -0.6512 1.0771 x 10 5 32.715 -0.6519 1.0774 x 10 5 33.015 -0.6526 1.0777 x 10 5 33.315 -0.6532 1.0779 x 10 5 33.615 -0.6537 1.0780 x 10 5 33.915 -0.6542 1.0782 x 10 5 34.215 -0.6547 1.0782 x 10 5 34.515 -0.6550 1.0783 x 10 5 34.815 -0.6554 1.0783 x 10 5 35.115 -0.6557 1.0783 x 10 5 35.715 -0.6562 1.0781 x 10 5 36.315 -0.6564 1.0778 x 10 5 36.915 -0.6565 1.0773 x 10 5
- Valve fully open at 8 seconds.
6.2-128 TABLE 6.2-1C LOCA CONTAINMENT RESPONSE RESULTS FOR LIMITING PRESSURE AND LONG-TERM TEMPERATURE RESPONSE CASES (EPU) Peak Peak Peak Containment Containment Containment Containment Case Pressure Vapor Pressure Vessel @Time Temperature
@24 Hours Temperature
@Time LOCA DEHLS -(peak 42.77 psig 265.57°F 7.55 psig 230°F I pressure response case) @ 18.17 sec @ 18.17 sec @ 1449 sec LOCA DEDLS -(long-term 40.16 psig 261.64°F 7.64 psig 246°F I temperature response case) @ 13.97 sec @ 13.97 sec @ 1299 sec MSLB (peak pressure 42.73 psig NA NA NA I response case) MSLB (EQ case) NA 387°F NA 251.1°F I @200 sec 6.2-128a Amendment No. 26 (11 /13)
TABLE 6.2-2 SHIELD BUILDING LEAKAGE RATES (Based upon data presented in the Report N AA-SR-10100, Conventional Buildings for Reactor Containment)
Source of Leakage Leakage Rate**
Cubic Feet in 24 Hours Leakage Rate**
Percent of Annulus Volume in 24 Hours Concrete Surface of Wall and Dome 11.4 2.9 x 10-3 Construction Joints*
94.0 24.0 x 10-3 Cracks in Concrete:
a) Temperature Cracks Negligible Negligible b) Shrinkage Cracks Negligible Negligible c) Earthquake Cracks Negligible Negligible d) Stress Cracks at Springline 2220.0 555 x 10-3 Penetrations (All)
Negligible Negligible Equipment Door 576 144 x 10-3 Personnel Door
- (2) 259 64.8 x 10-3 Total Leakage 3160.4 790 x 10-3
- Construction joint leakage is based on constructing the wall with built-up forms and allowing cold joints between successive 6 foot pours with no seals or coatings at joints. Leakage allowance has also been make for construction joints in the roof.
- At least 1/4 inch wg differential pressure.
6.2-129 TABLE 6.2-2A SINGLE FAILURE ANALYSIS- CONTAINMENT VACUUM RELIEF SYSTEM Component Identification and Quantity Failure Mode Effect on System Method of Detection Monitor Remarks Compressed air system Fails Loss of normal air supply to accumulators Low air pressure alarm CRI Seismic Class I accumulators have sufficient stored air to operate their respective vacuum relief valves Air accumulator Fails Loss of one vacuum relief subsystem Periodic testing CRI Redundant vacuum relief subsystem available Vacuum relief valve or check valve Fails to open Loss of one vacuum relief subsystem Valve position indication plus high P alarm CRI Redundant vacuum relief subsystem available Vacuum relief annulus to containment P switch Fails Loss of one vacuum relief subsystem Periodic testing C RI Redundant vacuum relief P switch available Differential pressure sensor Fails Loss of one valve actuation signal CRI Redundant differential pressure sensor available to provide actuation
CRI - Control Room Indication
6.2-130
Table 6.2-2B REACTOR VESSEL PRESSURE DROP intentionally deleted
6.2-131 Amendment No. 12, (12/93)
6.2-2C COMPONENT PRESSURE DROPS intentionally deleted.
6.2-132 Amendment No. 12, (12/93)
Table 6.2-2D FLOW RESISTANCE FACTORS FOR FLOOD-MOD2 DOUBLE-ENDED SUCTION LEG BREAK intentionally deleted.
6.2-133 Amendment No 12, (12/93)
Table 6.2-2E SAFETY INJECTION SYSTEM FLOW FOR FLOOD-MOD2 DOUBLE-ENDED SUCTION LEG BREAK intentionally deleted.
6.2-134 Amendment No. 12, (12/93)
TABLE 6.2-2F DETAILED CONTAINMENT PASSIVE HEAT SINK LISTING Description Material Surface Thickness Exposure Area (Ft 2) Exposure Side 1 Exposure Side 2 Thermal Conductivity (BTU/hr-ft-°F) Volumetric Heat Capacity (BTU/ft 3-°F) 1. Containment Concrete Structures (walls and floor slabs (4) Paint 4-7 mils All Concrete surfaces are painted 0.25-0.375 47.1 Surfaces 4-7 mils 0.10 28.0 Concrete 1.0 31.9 Surfaces Secondary Shield 1451 Cont. liquid
- Wall 20438 Cont. vapor
- Primary Shield 7.3 814 Cont. liquid
- Wall 1943 Cont. vapor
- 76 Cont. liquid
- 9894 Cont. vapor
- 21 Cont. liquid
- 1195 Cont. vapor
- Massive Wall (interior surface o nly) 725 Cont. liquid Ground Shield Wall 540 Cont. liquid
- 3180 Cont. vapor
- Ground Floor at E l. E l. Foundation (interior surface only
) 5485 Cont. liquid Ground 6035 Cont. vapor Operating Floor at 13450 Cont. vapor
- El. 62.0 Steam Generator 6390 Cont. vapor
- Shield Wall Pressurize r Shield 3050 Cont. vapor
- Wall Missile Shield Cover 851 Cont. vapor
- Hatch Cover 670 Cont. vapor
- Ring Wall 2760 Cont. vapor
- Reactor Cavity Floor 380 Cont. liquid Ground 6.2-135 Amendment No. 25 (04/12)
TABLE 6.2- Description Material Surface Thickness Exposure Area Exposure Side 1 Exposure Side 2 Thermal Conductivity (BTU/hr-ft-°F) Volumetric Heat Capacity BTU/ft 3-°F) Sump Pit 907 Cont. liquid (6) Misc. Walls 1250 Cont. vapor
- Concrete Steam 370 Cont. vapor (7) 1.0 31.9 Generator Nose 520 Cont. liquid (7) Vertical Wall Pressurizer Cover 320 Cont. vapor
- 1.0 31.9 Connecting Web 1632 Cont. vapor
- 1.0 31.9 Electrical Tunnel 5400 Cont. liquid (6) Air Tunnel 710 Cont. liquid (6) Access Key 1717 Cont. liquid (6) Vertical Surface 6410 Cont. liquid (6) 1.0 31.9 Area for Trenches Outside Secondary Shield Wall
- 2. Uninsulated Pipe Stainless Steel (SS) 0.406 in 519 Cont. vapor 9.8 54.0 SS 0.406 in 183 Cont. liquid 9.8 54.0 SS 0.365 in 521 Cont. vapor 9.8 54.0 SS 0.322 in 3903 Cont. vapor 9.8 54.0 SS 0.280 in 1545 Cont. vapor 9.8 54.0 SS 0.237 in 1220 Cont. vapor 9.8 54.0 SS 0.218 in 374 Cont. vapor 9.8 54.0 SS 0.218 in 221 Cont. liquid 9.8 54.0 SS 0.216 in 512 Cont. vapor 9.8 54.0 SS 0.216 in 262 Cont. liquid 9.8 54.0 SS 0.237 in 25 Cont. vapor 9.8 54.0 SS 0.179 in 643 Cont. liquid 9.8 54.0 SS 0.179 in 43 Cont. vapor 9.8 54.0 Carbon Steel (CS) 0.154 in 635 Cont. liquid 25.9 53.57 SS 0.154 in 2 Cont. vapor 9.8 54.0 SS 0.147 in 3 Cont. vapor 9.8 54.0 CS 0.133 in 163 Cont. vapor 25.9 53.57 SS 0.237 in 445(1) Cont. vapor 9.8 54.0 CS 0.154 in 749(1) Cont. vapor 25.9 53.57 SS 0.120 in 763 Cont. vapor 9.8 54.0 6.2-135a Amendment No. 25 (04/12)
TABLE 6.2- Description Material Thickness Surface Area (Ft 2) Exposure Side 1 Exposure Side 2 Thermal Conductivity (BTU/hr-ft-o F) Volumetric Heat Capacity (BTU/ft 3-o F) SS 0.113 in 3 Cont. vapor 9.8 54.0 CS 0.109 in 136 Cont. vapor 25.9 53.57 3. Safety Injection Tanks (4) Stainless Steel 7/8 in. 5240 Cont. vapor (7) 9.8 54 4. Reactor Dr. Tk.
SS 5/16 in. 230 Cont. liquid (7) 9.8 54 5. Quench Tank (painted)
SS 5/16 300 Cont. vapor (7) 9.8 54 6. H 2 Recombiner SS 2 1/2 200 Cont. vapor (7) 7. Refueling Machine Steel 2 1/4 945 Cont. vapor Cont. vapor 25.9 53.57 8. Crane Steel Steel 3/16 500 Cont. vapor Cont. vapor 25.9 53.57 7/32 5000 Cont. vapor Cont. vapor 25.9 53.57 1/4 120 Cont. vapor Cont. vapor 25.9 53.57 3/8 4800 Cont. vapor Cont. vapor 25.9 53.57 1/2 1100 Cont. vapor Cont. vapor 25.9 53.57 1 3/8 1900 Cont. va por Cont. vapor 25.9 53.57 9. Instr. Housing (Painted) Cast Aluminum 0.25 9 Cont. vapor (7) 120 34.3 10. Instr. Racks Galvanized Steel 3.5 mils .154 310 Cont. vapor (7) 611.0 25.9 40.6 53.57 Galvanized Steel 3.5 mils .39 550 Cont. vapor Cont. vapor 611.0 25.9 64.0 40.6 53.57 40.6 Galvanized Steel 3.5 mils .25 175 Cont. vapor Cont. vapor 611.0 29.9 611.0 40.6 5.57 40.6 Galvanized Steel 3.5 mils 11. Tubing 316 SS 0.065 3000 Cont. vapor Process f luid 9.8 54.0 12. Fittings 316 SS 0.065 300 Cont. vapor Process fluid 9.8 54.0 13. Instr. Manifolds 316 SS 1.25 25 Cont. vapor Process fluid 9.8 54.0 14. Piping seismic Restraints and hangers CS CS .75 .75 20000 5000 Cont. vapor Cont. liquid Cont. vapor Cont. liquid 25.9 25.9 53.57 53.57 6.2-135b Amendment No. 25 (04/12)
TABLE 6.2 Description Material Thickness Surface Area (Ft 2) Exposure Side 1 Exposure Side 2 Thermal Conductivity (BTU/hr-ft-o F) Volumetric Heat Capacity (BTU/ft 3-o F) 15. Electrical Conduit Galvanized
.8 mil 31089 Cont. vapor (7) 64.0 40.5 Steel .154 (7) 25.9 53.57 Galvanized
.8 mil 10328 Cont. vapor (7) 64.0 40.6 Steel .083 (7) 25.9 53.57 16. Electrical boxes Galvanized 2 mil 2 185 Cont. vapor (7) 64.0 40.6 Steel .083 (7) 25.9 53.57 17. Cable Trays Galvanized 2.5 mil 13000 Cont. vapor Cont. vapor 64.0 40.6 Steel .065 25.9 53.57 Galvanized 2.5 mil 64.0 40.0 Cable Trays Galvanized 2.5 mil 14666 Cont. vapor (7) 64.0 40.0 (with covers)
Steel 0.065 8666 25.9 53.57 Steel 0.049 6000 25.9 53.57 18. Tube Supports Galvanized 3.5 mil 1875 Cont. vapor Cont. vapor 64.0 40.6 Steel .109 25.9 53.57 Galvanized 3.5 mil 64.0 40.6 19. Cable Tray Steel .25 7836 Cont. vapor Cont. vapor 25.9 53.57 Restraints Steel .3125 718 Cont. vapor Cont. vapor 25.9 53.57 Steel .375 .315 Cont. vapor Cont. vapor 25.9 53.57 Steel .1875 1479 Cont. vapor Cont. vapor 25.9 53.57 Ste el .235 314 Cont. vapor Cont. vapor 25.9 53.57 Steel .269 628 Cont. vapor Cont. vapor 25.9 53.57 Steel .5 141 Cont. vapor Cont. vapor 25.9 53.57 Steel 1.0 316 Cont. vapor Cont. vapor 25.9 53.57 20. Cont. Vessel Cylinder (3) Steel 1.92 55900 Cont. vapor Annulus 25.9 53.57 21. Cont. Vessel Dome (3) Steel 0.96 30800 Cont. vapor Annulus 25.9 53.57 22. Refueling Pool Stainless c Wall 1000 Cont. vapor Concrete 25.9 53.57 Exposed Steel Steel c Wall 30 00 c Wall 180 0 c Wall 2200 23. Gratings, Ladders, Galvanized 3.5 mils 18383 Cont. vapor Cont. vapor 64.0 40.6 Misc. Steel .1875 13674 25.9 53.57 Steel .3125 3610 25.9 53.57 6.2-135c Amendment No. 25 (04/12)
TABLE 6.2-2F Cont'd. Thermal Volumetric Surface Exposure Exposure Conductivity Heat Capacity Description Material Thickness Area (Ft 2) Side 1 Side 2 (BTU/hr-ft-Fl (BTU/ft 3-0°F) 23. (Cont'd) Steel .375 681 25.9 53.57 Steel .5 418 25.9 53.57 Steel 3.5 mils 64.0 40.6 Galvanized 3.5 mils 660 Cont. vapor (7) 64.0 40.6 Steel .1875 207 25.9 53.57 Steel 2.0 453 25.9 53.57 24. Handrails and Galvanized 3.5 mils 5260 Cont. vapor (7) 64.0 40.6 Treads Steel .14 25.9 5357 Aluminum 4375 674 Cont. vapor 120 34.3 25. Trench Covers Steel 0.25 465 Cont. vapor Cont. vapor 25.9 53.57 26. Elevator Steel 0.25 2675 Cont. vapor Cont. vapor 25.9 53.57 27. HVAC Duct Galvanized 1.53 mil 23418 Cont. vapor Cont. vapor 64.0 40.6 Steel .1046 25.9 53.57 Galvanized 1.53 mil 64.0 40.6 28. HVAC Casings Galvanized 1.53 mil 2045 Cont. vapor Cont. vapor 64.0 40.6 Steel .1345 25.9 53.57 Galvanized 1.53 mil 64.0 40.6 29. HVAC Fans Steel .375 5629 Cont. vapor Cont. vapor 25.9 5357 30. Embedded Steel 3) Steel .75 724 Cont. vapor Concrete 25.9 53.57 Steel 1.0 2211 Cont. vapor Concrete 25.9 53.57 Steel 1.5 15 Cont. vapor Concrete 25.9 53.57 Steel 1.375 1583 Cont. vapor Concrete 25.9 53.57 Steel .75 180 Cont. liquid Concrete 25.9 53.57 Steel 1.0 1458 Cont. liquid Concrete 25.9 53.57 1.5 41 Cont. liquid Concrete 25.9 53.57 31. Pipe Restraints Steel .25 490 Cont. vapor Cont. vapor 25.9 53.57 Steel .375 1248 Cont. vapor Cont. vapor 25.9 53.57 Steel .42 1305 Cont. vapor Cont. vapor 25.9 53.57 Steel .5 898 Cont. vapor Cont. vapor 25.9 53.57 Steel .5625 208 Cont. vapor Cont. vapor 25.9 53.57 Steel .625 1759 Cont. vapor Cont. vapor 25.9 53.57 6.2-135d Amendment No. 26 (11/13)
TABLE 6.2- Description Material Thickness Surface Area (Ft 2) Exposure Side 1 Exposure Side 2 Thermal Conductivity (BTU/hr-ft-o F) Volumetric Heat Capacity (BTU/ft 3-o F) Steel .688 967 Cont. vapor Cont. vapor 25.9 53.57 Steel .72 533 Cont. vapor Cont. vapor 25.9 53.57 Steel .75 2161 Cont. vapor Cont. vapor 25.9 53.57 Steel .8125 179 Cont. vapor Cont. vapor 25.9 53.57 Steel 1.0 3613 Cont. vapor Cont. vapor 25.9 53.57 Steel 1.25 1352 Cont. vapor Cont. vapor 25.9 53.57 Steel 1.375 1200 Cont. vapor Cont. vapor 25.9 53.57 Steel 1.5 4074 Cont. vapor Cont. vapor 25.9 53.57 Steel 1.75 96 Cont. vapor Cont. vapor 25.9 53.57 Steel 2.0 788 Cont. vapor Cont. vapor 25.9 53.5 7 Steel 2.25 530 Cont. vapor Cont. vapor 25.9 53.57 Steel 2.5 274 Cont. vapor Cont. vapor 25.9 53.57 Steel 2.75 280 Cont. vapor Cont. vapor 25.9 53.57 Steel 3.25 150 Cont. vapor Cont. vapor 25.9 53.57 Steel 3.5 60 Cont. vapor Steel(8) 4.0 56 Cont. vapor Concrete 25.9 53.57 Steel(8) 2.25 18 Cont. vapor Concrete 25.9 53.57 Steel(8) 1.5 2117 Cont. vapor Concrete 25.9 53.57 Steel(8) 2.5 130 Cont. vapor Concrete 25.9 53.57 Steel(8) 2.0 420 Cont. vapor Concrete 25.9 53.57 Steel(8) 1.0 268 Cont. vapor Concrete 25.9 53.57 Steel(8) 1.25 20 Cont. vapor Concrete 25.9 53.57 Steel(8) 1.75 51 Cont. vapor Concrete 25.9 53.57 Steel(8) 3.0 15 Cont. vapor Concrete 25.9 53.57 Steel(8) 1.625 17 Cont. vapor Concrete 25.9 53.57 Steel(8) 2.25 20 Cont. liquid Concrete 25.9 53.57 Steel(8) 1.0 155 Cont. liquid Concrete 25.9 53.57 Steel(8) 2.25 31 Cont. liquid Cont. liquid 25.9 53.57 Steel(8) 2.0 278 Cont. liquid Cont. liquid 25.9 53.57 Steel(8) 1.0 50 Cont. liquid Cont. liquid 25.9 53.57 St eel(8) 1.25 20 Cont. liquid Cont. liquid 25.9 53.57 Steel(8) .683 30 Cont. liquid Cont. liquid 25.9 53.57 Steel(8) .5 32 Cont. liquid Cont. liquid 25.9 53.57 Steel(8) .375 40 Cont. liquid Cont. liquid 25.9 53.57 32. Equipment Steel Supports Steel .38 212 Cont. vapor Cont. vapor 25.9 53.57 Steel .5 222 Cont. vapor Cont. vapor 25.9 53.57 Steel .69 7217 Cont. vapor Cont. vapor 25.9 53.57 Steel .75 445.8 Cont. vapor Cont. vapor 25.9 53.57 Steel 1.0 341 Cont. vapor Cont. vapor 25.9 53.57 Steel 1.12 35 Cont. vapor Cont. vapor 25.9 53.57 Steel 1.5 763.5 Cont. vapor Cont. vapor 25.9 53.57 Steel 1.75 39 Cont. vapor Cont. vapor 25.9 53.57 6.2-135e Amendment No. 25 (04/12)
TABLE 6.2- Description Material Thickness Surface Area (Ft 2) Exposure Side 1 Exposure Side 2 Thermal Conductivity (BTU/hr-ft-o F) Volumetric Heat Capacity (BTU/ft 3-o F) Steel 2.0 2202.6 Cont. vapor Cont. vapor 25.9 53.57 Steel 2.5 289 Cont. vapor Cont. vapor 25.9 53.57 Steel 4.0 504.8 C ont. vapor Cont. vapor 25.9 53.57 Steel 5.0 78 Cont. vapor Cont. vapor 25.9 53.57 Steel 3.0 853.4 Cont. vapor Cont. vapor 25.9 53.57 Steel .25 21 Cont. vapor Cont. vapor 25.9 53.57 Steel 1.25 570.6 Cont. vapor Cont. vapor 25.9 53.57 Steel 2.0 482.6 Cont. vapor Insulated 25.9 53.57 Steel 4.0 99.2 Cont. vapor Insulated 25.9 53.57 Steel 1.0 500 Cont. liquid Cont. liquid 25.9 53.57 Steel 1.5 397.6 Cont. liquid Cont. liquid 25.9 53.57 Steel 2.5 112 Cont. liquid Cont. liquid 25.9 53.57 Steel 3.0 681 Cont. liquid Cont. liquid 25.9 53.57 Steel 4.0 1039 Cont. liquid Cont. liquid 25.9 53.57 Steel 5.0 357 Cont. liquid Cont. liquid 25.9 53.57 Steel 6.0 288 Cont. liquid Cont. liquid 25.9 53.57 Steel 3.5 185 Cont. liquid Cont. liquid 25.9 53.57 Steel 2.0 206.7 Cont. liquid Cont. liquid 25.9 53.57 Steel .25 10 Cont. liquid Cont. liquid 25.9 53.57 Steel 1.25 31 Cont. liquid Cont. liquid 25.9 53.57 Steel .5 377 Cont. liquid Cont. liquid 25.9 53.57 Steel 1.75 107 Cont. liquid Cont. liquid 25.9 53.57 Steel 2.75 336 Cont. liquid Cont. liquid 25.9 53.57 Steel 2.625 76 Cont. liquid Cont. liquid 25.9 53.57 Steel 4.25 382 Cont. liquid Cont. liquid 25.9 53.57 Steel .75 159.5 Cont. liquid Cont. liquid 25.9 53.57 Steel(8) 1.25 15.5 Cont. v apor Concrete 25.9 53.57 Steel(8) 1.0 266.8 Cont. vapor Concrete 25.9 53.57 Steel(8) 1.5 90.2 Cont. vapor Concrete 25.9 53.57 Steel(8) 3.0 46 Cont. vapor Concrete 25.9 53.57 Steel(8) .5 25.5 Cont. vapor Concrete 25.9 53.57 Steel(8) 2.0 16.4 Cont. vapor Concrete 25.9 53.57 Steel(8) .75 2.7 Cont. vapor Concrete 25.9 53.57 Steel(8) 2.5 21.7 Cont. vapor Concrete 25.9 53.57 Steel(8) .5 3868.0 Cont. liquid Concrete 25.9 53.57 Steel(8) 1.0 2.3 Cont. liquid Concrete 25.9 53.57 Steel(8) 2.0 94.6 Cont. liquid Concrete 25.9 53.57 Steel(8) 3.0 116.1 Cont. liquid Concrete 25.9 53.57 Steel(8) 4.0 142.2 Cont. liquid Concrete 25.9 53.57 Steel(8) .75 1.4 Cont. liquid Concrete 25.9 53.57 Steel(8) 12.0 144.0 Cont. liquid Concrete 25.9 53.57 33. HVAC Duct Steel .1875 81 Cont. vapor Cont. vapor 25.9 53.57 .25 6721 Cont. vapor Cont. vapor 25.9 53.57 .288 206 Cont. vapor Cont. vapor 25.9 53.57 6.2-135f Amendment No. 25 (04/12)
TABLE 6.2- Description Material Thickness Surface Area (Ft 2) Exposure Sid e 1 Exposure Side 2 Thermal Conductivity (BTU/hr-ft-o F) Volumetric Heat Capacity (BTU/ft 3-o F) .3125 536 Cont. vapor Cont. vapor 25.9 53.57 .345 293 Cont. vapor Cont. vapor 25.9 53.57 .5 414 Cont. vapor Cont. vapor 25.9 53.57 .433 264 Cont. vapor Cont. vapor 25.9 53.57 .375 335 Cont. vapor Cont. vapor 25.9 53.57
_______________ (1) Piping is painted.
(2) For all carbon steel surfaces, see Section 3.8.3.6.1 for a discussion on protective coatings inside containment.
(3) For the steel containment vessel, see Section 3.8.3.6.1 for a discussion on protective coatings inside containment.
(4) The given surface area for a concrete wall has been reduced to represent both sides of the wall since the faces often have different areas. the exposure side 2 column identifies where this has been done and should be taken to mean both sides are exposed to the environment of exposure side one. The given thickness is that of the full wall.
(5) When both sides are exposed to containment environment, the area of one side only.
(6) Exposure on side 2 is not applicable since it ranges from surfaces previously given to ground.
(7) The interior surface is not readily subject to the exposure of side 1 since that environment has no free path to the inner surface. The surface area represents the outer surface only and the heat sink is considered to be the full thickness.
(8) Where the steel is buried in concrete or backed by concrete this is indicated in the exposure side 2 column. In these cases the surface area represents that area exposed to the environment of the exposure side 1 column.
6.2-135g Amendment No.
25 (04/12)
TABLE 6.2-3
SUMMARY
OF PASSIVE HEAT SINKS USED IN THE LOCA CONTAINMENT ANALYSIS Description Thickness Surface Area** Exposure Exposure Conductivity Heat Capacity (ft2) Side 1 Side 2 (BTU/hr-ft-°F) (BTU/ft 3-°F) 1. Containment Primary Cylinder Top Coat* 55,900 Cont Vapor Annulus Bottom Coat
- Steel shell-1.92 in 25.9 53.57 Paint film 2. Containment Primary Dome Top Coat
- 30,800 Cont Vapor Annulus Bottom Coat
- Steel shell -.96 in 25.9 53.57 Paint film* 3. Ground Floor -Concrete Paint Film* 5,733.3 Cont Vapor Ground Surfacer*
Concrete -20 ft. 1.0 31.9 4. Concrete (shield walls and Paint Film* 64,023.4 Cont Vapor Insulated Concrete pads) Surfacer*
Concrete -2 ft. 1.0 31.9 5. Concrete exposed to Paint Film* 23,898.2 Cont Liquid Insulated Containment Sump Water Surfacer*
Concrete -3 ft. 1.0 31.9 6. Stainless Steel -embedded Stainless Steel -.1875 in 8,300 Cont Vapor Insulated 9.8 54.0 Surfacer -4 ft. 1.0 31.9 7. Stainless Steel (piping and Stainless Steel -.5099 in 15,618 Cont Vapor Insulated 9.8 54.0 other components)
- 8. Galvanized steel (conduits a) Zinc -.8 mil 41,417 Cont Vapor Cont Vapor 64.0 40.6 and cable trays) Steel -.1488 in 25.9 53.57 b) Zinc -1.53 mil 25,463 Cont Vapor Cont Vapor 64.0 40.6 Steel -.107 in 25.9 53.57 Zinc -1.53 mil 64.0 40.6 c) Zinc-3 mil 91,047 Cont Vapor Insulated 64.0 40.6 Steel -.09041 in 25.9 53.57 *See LOCA Analysis Reference (9) for assumed coating value. Coating specifications are described in Section 3.8.3.6.1.
- LOCA analysis Reference (9) assumes -2% uncertainty for the surface areas. 6.2-136 Amendment No. 26 (11 /13)
Table 6.2-3A CONTAINMENT HEAT SOURCES intentionally deleted.
6.2-138 Amendment No. 12, (12/93)
Table 6.2-3B DOUBLE-ENDED SUCTION LEG SLOT BREAK BLOWDOWN PHASE Intentionally deleted
6.2-139 Amendment No. 12, (12/93)
Table 6.2-3C DOUBLE-ENDED SUCTION LEG SLOT BREAK REFLOOD PHASE Intentionally deleted
6.2-140 Amendment No. 12, (12/93)
Table 6.2-3D DOUBLE-ENDED SUCTION LEG SLOT BREAK BLOWDOWN ENERGY BALANCE Intentionally deleted
6.2-141 Amendment No. 12, (12/93)
Table 6.2-3E DOUBLE-ENDED SUCTION LEG SLOT BREAK REFLOOD ENERGY BALANCE Intentionally deleted
6.2-142 Amendment No. 12, (12/93)
Page Left Intentionally Blank
6.2-143 Amendment No. 12, (12/93)
Time (Seconds) 0.0 0.46 1.04 11.0 11.0 18.17 TABLE 6.2-4 SEQUENCE OF EVENTS 19.24 FT 2 DOUBLE-ENDED HOT LEG SLOT BREAK (MIN SI) Event Setpoint Value DEHLS LOCA occurs from 100.3% power and reactor trips 19.24 tt2 on voids break Containment Hi Pressure Signal (CHPS) is generated.
This 6.3 psig will cause a MSIS and SIAS following signal delay. Containment Hi-Hi Pressure Signal (CHHPS) is generated 11.3 psig End of Slowdown phase; start of long term boil-off-phase Safety Injection Pumps started at End of Slowdown Containment peak pressure and temperature reached 42.77 psig 265.57°F 30.46 Two containment fan coolers start following 30-second delay time after CHPS 80.40 4571.24 2.6 E+6 Containment spray full flow following 30-second delay after CHHPS Recirculation Actuation Signal (RAS) generated.
All LPSI flow is terminated.
End of Simulation 2545 gpm @RWT volume of 411,260 gal 6.2-144 Amendment No. 26 ( 11 /13)
Table 6.2-4A MASS and ENERGY RELEASE RELATED INITIAL CONDITIONS AND KEY ASSUMPTIONS FOR MAIN STEAM LINE BREAK INSIDE CONTAINMENT 1 . Methodology Break Type Steam Separation Rate Multiplier Water in Feed Pipe Steam in Header Pipe 2. Initial NSSS Parameters MODE Power Level Initial Primary Pressure Initial RCS Inlet Temperature Initial Secondary Pressure Primary and Secondary Volumetric Expansion Due to Pressure/Temperature Steam Generator Level Number of U-tubes plugged 3. Reactor Shutdown Reactor Trip Logic Delay Time Rod Drop Time 4. Reactor Coolant Pumps Total RCS flowrate VALUE/ASSUMPTION 5.412 ft 2 guillotine at SG outlet nozzle 3.31 ft 2 slot at SG outlet nozzle (25% power) 1.99 ft 2 slot at SG outlet nozzle (0% power) 2.5 Considered Considered (No impact due to Reverse Flow Check Valve) 100.3% (limiting case) 75%, 50%, 25%, 0% also considered 2250 psia 554.0°F(1 l 864.6°F(1 l Considered 35.0' above tube sheet (Normal Water Level) 0 (conservatively assumed) On high containment pressure analytical setpoint of 4.6 psig 1.4 sec 3.4 seconds including holding coil delay On throughout the event (except the loss of offsite power case) 438,500 gpm 6.2-145 Amendment No. 26 (11/13)
Table 6.2-48 CONTAINMENT RELATED INITIAL CONDITIONS AND KEY ASSUMPTIONS FOR MAIN STEAM LINE BREAK INSIDE CONTAINMENT Free Volume Safety Injection Actuation Setpoint (SIAS) Containment Spray Actuation Setpoint (CSAS) Spray Delivery Time (after CSAS is generated)
Spray (RWT) Temperature Containment Spray Logic Containment Fan Coolers (CFCs) Initial Containment Temperature Initial Containment Pressure Initial Relative Humidity Heat Transfer Coefficient Used for Passive Heat Sinks Credit for Condensate Revaporization Credit for Heat Transfer to Water in Containment Sump 2,498,445 ft 3 6.3 psig in containment 11.3 psig in containment 67.0 sec, with off-site power available 78.5 sec, with loss of off-site power 100°F 2 spray trains (2545 gpm* per train) Not Credited 120°F 15.51 psia 45% Uchida Correlation Not Credited Not credited *The MSLB analysis conservatively assumes 2545 gpm per CS pump, 5 gpm less than the CS pump minimum design flow. 6.2-146 Amendment No. 26 (11/13)
Table 6.2-4C RESULTS OF MAIN STEAM LINE BREAKS INSIDE CONTAINMENT Case# Description Peak pressure (psig) I Peak Temperature
(°F) 1 100.3% power MSLB with the failure of one Pmax = 42.73 psig Containment Spray Pump. Tmax = 398°F 2 75% power MSLB with the failure of one Pmax = 40.02 psig Containment Spray Pump. Tmax = 392°F 3 50% power MSLB with the failure of one Pmax = 37.17 psig Containment Spray Pump. Tmax = 384°F 4 25% power MSLB with the failure of one Pmax = 33.94 psig Containment Spray Pump. Tmax = 373°F 5 0% power MSLB with the failure of one Pmax = 33.44 psig Containment Spray Pump. Tmax = 363°F 6 100.3% power EQ -MSLB with the failure of Pmax = 40.56 psig one Containment Spray Pump. Tmax = 387°F 7 100.3% power MSLB with a LOOP and the Pmax = 33.90 psig failure of one Containment Spray Pump. Tmax = 376°F 8 100.3% power MSLB with the failure of a MFIV Pmax = 41.34 psig to close or MFP to trip. Tmax = 398°F 9 75% power MSLB with the failure of a MFIV to Pmax = 38.79 psig close or MFP to trip. Tmax = 392°F 10 50% power MSLB with the failure of a MFIV to Pmax = 36.03 psig close or MFP to trip. Tmax = 384°F 11 25% power MSLB with the failure of a MFIV to Pmax = 33.33 psig close or MFP to trip. Tmax = 372°F 12 0% power MSLB with the failure of a MFIV to Pmax = 32.53 psig close or MFP to trip. Tmax = 364°F Note that all of the breaks are located at the SG steam outlet nozzle. Except for the 0% and 25% power cases all are 5.412 tt2 breaks. The 0% power case break is a 1. 99 ft 2 slot break. The 25% power case break is a 3.31 ft break. 6.2-147 Amendment No.26 (11/13)
TABLE 6.2-4CA DELETED
6.2-148 Amendment No. 18, (04/01)
TABLE 6.2-40 SEQUENCE OF EVENTS FOR LIMITING MAIN STEAM LINE BREAK INSIDE CONTAINMENT TIME, sec EVENT 0.0 Break occurs 2.43 Reactor trip analytical setpoint reached, Containment High Pressure 3.73 SIAS analytical setpoint reached, Containment High Pressure 3.83 CEAs begin entering core 4.09 Turbine Stop Valves closed 5.21 MSIS analytical setpoint reached, SG Low Pressure 8.3 CSAS analytical setpoint reached, Containment High-High Pressure 10.78 AFW isolation to the affected SG (High SG .llP) analytical setpoint reached 12. 11 MSIV Closure 23.73 MFW isolation valve closed 59.6 Containment peak temperature occurs 75.3 Containment Sprays full on 86.99 Containment peak pressure occurs 251 AFW to Intact SG initiated 300 End of transient 6.2-149 Amendment No. 26 (11 /13)
Volume Number 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 TABLE 6.2-4E (Historical)
VOLUME DIVISIONS USED IN RELAP 3 ANALYSIS OF REACTOR CAVITY PRESSURE RESPONSE Volume Volume Height Lower Elevation (ft3) (ft) (ft) 213.84 10.5 25.5 232.70 10.5 25.5 232.70 10.5 25.5 213.84 10.5 25.5 232.70 10.5 25.5 232.70 10.5 25.5 160.78 14.86 10.64 160.78 14.86 10.64 370.68 14.86 10.64 160.78 14.86 10.64 160.78 14.86 10.64 370.68 14.86 10.64 160.78 14.86 10.64 160.78 14.86 10.64 370.68 14.86 10.64 155.58 8.55 2.09 155.58 8.55 2.09 322.61 8.55 2.09 155.58 8.55 2.09 155.58 8.55 2.09 322.61 8.55 2.09 155.58 8.55 2.09 155.58 8.55 2.09 322.61 8.55 2.09 1885.73 5.13 -3.04 4.6886 x 10 4 26.0 36.0 2.5 x 10 6 196.0 -3.04 211.33 8.0 25.5 211.33 8.0 25.5 365.43 7.0 25.5 365.43 7.0 25.5 282.23 7.0 25.5 207.50 7.0 25.5 582.00 7.5 0.0 453.00 7.5 0.0 336.00 7.5 0.0 455.00 7.5 0.0 396.00 7.5 0.0 5,558.00 7.5 0.0 1,638.00 18.0 0.0 6.2-150 Amendment No. 26 (11/13)
TABLE 6.2-4F (Historical)
JUNCTIONS USED IN RELAP 3 ANAL YIS OF REACTOR CAVITY PRESSURE RESPONSE Junction Minimum Elevation Junction Friction Number Flow Area (ft 2} ill} Inertia (ft-1} Coefficient 25.4 29.5 .1378 8.859 x 10" 8 2 19.5 29.5 .3764 2.0779 x 10*7 3 19.5 29.5 .3764 2.0779 x 10*7 4 25.4 29.5 .1378 8.859 x 10" 8 5 19.5 29.5 .2908 2.0310 x 10*7 6 19.5 29.5 .2138 1. 9889 x 10*7 7 16.65 36.0 .25075 3.9402 x 10*7 8 16.65 36.0 .25075 3.9402 x 10*7 9 16.65 36.0 .25075 3.9402 x 10*7 10 16.65 36.0 .25075 3.9402 x 10-7 11 16.65 36.0 .25075 3.9402 x 10*7 12 16.65 36.0 .25075 3.9402 x 10*7 13 18.0 25.5 .63994 1.7749x10-8 14 18.0 25.5 .63994 1.7749 x 10" 8 15 18.0 25.5 .63994 1.7749 x 10" 8 16 18.0 25.5 .63994 1.7749 x 10" 8 17 18.0 25.5 .63994 1.7749 x 10" 8 18 18.0 25.5 .63994 1.7749 x 10" 8 19 3.24 25.5 1.44202 2.625 x 10*5 20 3.24 25.5 1.44202 2.625 x 10*5 21 24.94 25.5 0.18708 1.66065 x 10*9 22 3.24 25.5 1.44202 2.625 x 10*5 23 3.24 25.5 1.44202 2.625 x 10*5 24 24.94 25.5 0.18708 1.66065 x 10*9 25 3.24 25.5 1.44202 2.625 x 10*5 26 3.24 25.5 1.44202 2.625 x 10*5 27 24.94 25.5 0.18708 1.66065 x 10*9 28 41.47 10.64 0.17362 1.8541 x 10*9 29 13.08 10.64 0.44018 2.2359 x 10-6 30 41.47 10.64 0.17362 1.8541 x 10*9 6.2-151 Amendment No. 26 (11/13)
TABLE 6.2-4F (Cont'd) (Historical)
Junction Minimum Elevation Junction Friction Number Flow Area (ft 2} illl Inertia (ft-1} Coefficient 31 41.47 10.64 0.17362 1.8541 x 10-9 32 13.08 10.64 0.44018 2.2359 x 10-<> 33 41.47 10.64 0.17362 1.8541 x 10-9 34 41.47 10.64 0.17362 1.8541 x 10-9 35 13.08 10.64 0.44018 2.2359 x 10-<> 36 41.47 10.64 0.17362 1.8541 x 10-9 37 11.42 10.64 1.1203 5.4599 x 1 o-8 38 11.42 10.64 1.1203 5.4599 x 1 o-8 39 24.94 10.64 0.51274 4.5514 x 10-9 40 11.42 10.64 1.1203 5.4599 x 10-8 41 11.42 10.64 1.1203 5.4599 x 10-8 42 24.94 10.64 0.51274 4.5514 x 10-9 43 11.42 10.64 1.1203 5.4599 x 1 o-8 44 11.42 10.64 1.1203 5.4599 x 1 o-8 45 24.94 10.64 0.51274 4.5514 x 10-9 46 36.64 2.09 0.19652 1.7371 x 10-9 47 22.39 2.09 0.25729 7.4246 x 10-1 48 36.64 2.09 0.19652 1.7371 x 10-9 49 36.64 2.09 0.19652 1.7371 x 10-9 50 22.39 2.09 0.25729 7.4246 x 10-7 51 36.64 2.09 0.19652 1.7371 x 10-9 52 36.64 2.09 0.19652 1.7371 x 10-9 53 22.39 2.09 0.25729 7.4246 x 10-7 54 36.64 2.09 0.19652 1.7371 x 10-9 55 62.30 2.09 0.10891 1.8799 x 10-10 56 62.30 2.09 0.10891 1.8799 x 10-10 57 63.36 2.09 0.10709 1.5988 x 10-10 58 62.30 2.09 0.10891 1.8799 x 10-10 59 62.30 2.09 0.10891 1.8799 x 10-10 60 63.36 2.09 0.10709 1.5988 x 10-10 61 62.30 2.09 0.10891 1.8799 x 10-10 62 62.30 2.09 0.10891 1.8799 x 10-10 63 63.36 2.09 0.10709 1.5988 x 10-10 6.2-152 Amendment No. 26 (11 /13)
TABLE 6.2-4F (Cont'd) (Historical)
Junction Minimum Elevation Junction Friction Number Flow Area (ft2) Inertia (ff 1) Coefficient 64 16.16 -3.04 1.98 4.9842 x 10-7 65 30.0 2.09 1.244 2.6079 x 10-7 66 30.0 2.09 1.244 2.6079 x 10-7 67 1111.07 62.0 0.0234 8.9149 x 10-11 68 25.4 29.5 0.1378 1.7216 x 10-7 69 25.4 29.5 0.1378 1. 7216 x 10-7 70 19.5 29.5 0.3764 3.0421 x 10-7 71 19.5 29.5 0.3764 3.0421 x 10-7 72 19.5 29.5 0.2908 2.995 x 10-7 73 19.5 29.5 0.2138 2.953 x 10-7 74 43.1 0.0 0.2301 7.133x10-8 75 43.1 0.0 0.2301 7.133 x 10-8 76 43.1 0.0 0.1441 8.917 x 10-8 77 43.1 0.0 0.1441 8.917 x 10-8 78 86.0 0.0 0.1765 1.22 x 10-8 79 86.0 0.0 0.1623 3.924 x 10-8 80 78.0 0.0 0.2791 1.864 x 10-8 6.2-153 Amendment No. 26 (11/13)
TABLE 6.2-4G CONTAINMENT RESPONSE ANALYSIS PARAMETERS (EPU) Parameter LOCA Value MSLB Value I Initial Containment Pressure (psia) 15.51 15.51 I Initial Containment Temperature
(°F) 120 120 I Initial Relative Humidity(%)
45 45 I Net Free Volume including a -0.5% uncertainty 2,498,445 2,498,445 I Ultimate Heat Sink/Intake Cooling Water Temperature
(°F) 95 NA I RWT Water Temperature
(°F) 104 100\l) I Containment Fan Coolers I Total 4 NA I Analysis Maximum 4 NA I Analysis Minimum 2 NA I Containment Pressure Hiqh Setpoint (psiq) 6.3 NA I Delay Time (sec) 30 NA I Without Offsite Power Containment Sprav Pumps I Total 2 2 I LOCA -Maximum Safeguards 2 NA I LOCA -Minimum Safeguards 1 NA I MSLB -Failure of MFP to Trip, Failed open MFIV NA 2 I MSLB -Failure of Containment Spray Pump NA 1 I Flowrate (gpm) Injection Phase (per pump) 2,545(3) 2,545(3) Recirculation Phase (per pump) 2,545(3) NA Containment Pressure High-High Setpoint (psig) 11.3 11.3 I Delay Time after the Setpoint is Reached (sec) 78.5(2) Without Offsite Power 78.5 With Offsite Power NA 67.0 (1) The MSLB analysis uses the (maximum)
Technical Specification RWT temperature.
(2) The LOCA analysis assumes a 1.9-second response time to reach the Containment High-High Setpoint.
Therefore, the total delay is 80.4 seconds (1.9 sec+ 78.5 sec) from the initiation of the LOCA event. (3) The LOCA and MSLB analyses conservatively assume 2545 gpm per CS pump, 5 gpm less than the CS pump minimum design flow rate. 6.2-153a Amendment No. 26 (11/13)
TABLE 6.2-4H RESULTS OF SUBCOMPARTMENT ANALYSIS Peak Wall Subcompartment Breaks Analyzed M&E Data Model Results Differential Wall Design Margin% Pressure (psid) Value (psid) 4.91 ft 2 Cold Leg Slot Break Table 6.2-5A Figure 6.2-18 series Table 6.2-4E Reactor Cavity 4.0 ft 2 Cold Leg Guillotine Break Table 6.2-5B Table 6.2-4F Figure 6.2-19 NA NA NA (See Note 1) Figure 6.2-17 series series 3.44 ft 2 Hot Leg Guillotine Break Table 6.2-5C Figure 6.2-20 series Secondary Shield Hot Leg DE Guillotine Break NA NA Figure 6.2-21 17.1 24 40 Wall (See Note 2) Pressurizer Cavity Pressurizer Relief Line Break Table 6.2-5E Figure 6.2-49b 10.2 (upper wall) 14 (upper wall) 37 (See Note 3) Pressurizer Spray Line Break Table 6.2-5F Table 6.2-5D Figure 6.2-49c 4.8 (upper wall) 14 (upper wall) Table 6.2-5G Figure 6.2-49a (See Note 4) Pressurizer Surge Line Break NA NA 22. 7 (lower wall) 24 (lower wall) 6 (See Note 5) Notes: 1. Analysis is no longer required due to the application of the LBB criteria (refer to UFSAR Section 6.2.1.3.3.a).
- 2. This break is eliminated due to the application of the LBB criteria (refer to UFSAR Section 6.2.1.3.3.b).
- 4. The pre-EPU M&E data slightly increase at EPU conditions (refer to UFSAR Section 6.2.1.3 3.c). 5. This break was not analyzed in the original design. However, the peak wall differential pressure at EPU conditions is estimated based on the St. Lucie Unit 2 pressurizer cavity analysis (refer to UFSAR Section 6.2.1.3.3.c).
6.2-153b Amendment No. 26 (11 /13) I I TABLE 6.2-5a (Historical)
SLOWDOWN DATA FOR 4.91 Ft 2 COLD LEG SLOT BREAK Mass Flow Rate of Integral Time Rate Enthalpy Release Break Mass (sec) (lb/sec) (Btu/sec)
(10 Btu/sec) (lb) 0.0 0.0 544.69 0.0 0.0 0.005 37,713 539.83 3.030 846.05 0.5 65,387 542.11 3.545 0177.8 0.075 62,559 541.95 3.390 3799.2 0.1 57,099 541.50 3.092 5266.3 0.125 58, 124 541.62 3.148 6702.4 0.15 58,656 541.62 3.177 8166.4 0.175 57,438 541.61 3.111 9627.6 0.2 56,974 541.59 3.096 11,043 0.225 57,675 541.68 3.124 12,482 0.25 57,376 541.68 3.108 13,921 0.275 56,366 541.62 3.053 15,343 0.3 56,810 541.68 3.077 16,752 0.325 56,792 541.71 3.077 18, 177 0.35 56,053 541.68 3.036 19,587 0.375 55,529 541.67 3.008 20,980 0.4 56, 118 541.76 3.040 22,375 0.425 55,511 541.75 3.007 23,773 0.45 55,056 541.75 2.983 25,154 0.475 55,295 541.81 2.996 26,531 0.5 55,296 541.86 2.996 27,916 0.55 54,538 541.89 2.955 30,652 0.6 54,216 541.98 2.938 33,381 0.65 54, 141 542.09 2.935 36,085 0.7 53,479 542-16 2.899 38,775 0.75 53,500 542.30 2.901 41,453 0.80 53,200 542.41 2.881 44,113 0.85 52,642 542.53 2.856 46,757 0.9 52,486 542.68 2.848 49,.386 0.95 52, 119 542.82 2.829 52,000 6.2-154 Amendment No. 26 ( 11 /13)
TABLE 6.2-5a (Cont'd)
Mass Flow Rate (lb/sec) Rate of Energy Release (10 7 Btu/sec) Integral Break Mass (lb) Time (sec) Enthalpy (Btu/sec) 1.0 51,777 542.97 2.811 54,599 1.05 51,572 543.13 2.801 57,183 1.1 51,220 543.29 2.783 59,752 1.15 50,891 543.45 2.766 62,305 1.2 50,608 543.63 2.751 64,842 1.25 50,257 543.80 2.733 67,364 1.3 49,887 543.98 2.714 69,868 1.35 49,492 544.17 2.693 72,372 1.4 49,113 544.36 2.674 74,817 1.45 48,712 544.5.6 2.653 77,263 1.5 48,291 544.77 2.631 79,688 1.55 47,855 544.97 2.068 82,091 1.6 47,438 545.17 2.586 84,474 1.65 47,039 545.38 2.565 86,835 1.7 46,661 545.58 2.546 89,178 1.75 46,287 545.78 2.526 91,502 1.8 45,898 545.97 2.506 93,806 1.85 45,497 546.16 2.486 96,091 1.9 45,134 546.35 2.466 98,356 1.95 44,774 546.54 2.447 100,600 2.0 44,400 546.74 2.428 102,803 2.1 44,052 547.20 2.411 107,250 2.2 43,602 547.65 2.388 111,640 2.3 43,138 548.11 2.365 115,970 2.4 42,707 548.58 2.343 126,270 2.5 42,249 549.03 2.320 124,510 2.6 41,784 549.44 2.296 128,720 2.7 41,332 549.80 2.272 132,870 2.8 40,895 550.11 2.250 136,980 2.9 40,452 550.39 2.227 141,050 3.0 40,013 550.64 2.203 145,070 3.1 39,610 550.88 2.182 149,050 6.2-155 TABLE 6.2-5a (Cont'd)
Mass Flow Rate (lb/sec) Rate of Energy Release (10 7 Btu/sec) Integral Break Mass (lb) Time (sec) Enthalpy (Btu/sec) 3.2 39,296 551.11 2.166 153,000 3.3 39,217 551.33 2.162 156,920 3.4 59,031 551.50 2.153 160,840 3.5 38,770 551.64 2.139 164,730 3.6 38,490 551.74 2.124 168,590 3.7 38,221 551.82 2.109 172,420 3.8 37,987 551.90 2.097 176,230 3.9 37,781 551.99 2.085 180,020 4.0 37,537 552.06 2.072 183,790 4.4 36,571 552.08 2.019 198,590 4.8 35,901 551.76 1.981 213,080 5.2 35,257 551.40 1.944 227,310 5.6 34,645 550.93 1.909 241,290 6.0 34,026 550.54 1.873 255,020 6.4 33,349 550.36 1.835 268,500 6.8 32,623 550.43 1.796 281,700 7.2 31,804 550.81 1.752 294,580 7.6 30,925 551.61 1.706 307,130 8.0 29,964 552.84 1.657 319,310 8.4 28,897 554.86 1.603 331,090 8.8 27,724 557.87 1.547 342,420 9.2 26,352 562.01 1.481 353,240 9.6 24,833 567.38 1.409 363,470 10.0 23,265 574.30 1.336 373,1 00 10.4 21,563 582.88 1.257 382,070 10.8 19,740 593.84 1.198 390,330 11.2 17,746 606.93 1.077 387,840 11.6 15,826 622.25 0.9848 404,530 12.0 14,016 641.05 0.8985 410,510 12.4 12,173 664.57 0.8469 415,740 12.8 10,659 690.03 0.7355 420,290
6.2-156 TABLE 6.2-5a (Cont'd)
Time (sec) Mass Flow Rate (lb/sec) Enthalpy (BTU/sec) Rate of Energy Release (10 7 BTU/sec) Integral Break Mass (lb) 13.2 9,396.0 714.82 0.6716 424,300 13.6 8,294.0 737.33 0.6115 427,830 14.0 6,701.8 773.66 0.5185 433,790 14.4 6,701.8 773.66 0.5185 433,790 14.8 6,068.8 786.73 0.4775 436,340 15.2 5,551.6 796.33 0.4405 438,660 15.6 5,097.0 803.99 0.4098 440,780 16.0 4,691.1 812.03 0.38 09 442,740 16.4 4,306.3 820.00 0.3531 444,540 16.8 3,951.3 827.32 0.3269 446,190 17.2 3,583.7 834.52 0.2991 447,700 17.6 3,236.1 834.28 0.2300 449,050 18.0 2,926.9 943.04 0.2467 450,290 18.4 3,175.1 737.49 0.2342 451,450 18.8 3,866.0 593.18 0.2293 452,870 19.2 4,300.3 515.09 0.2215 454,510 19.6 4,565.6 464.06 0.2119 456,280 20.0 4,708.3 425.28 0.2002 458,150 20.4 4,603.3 394.12 0.1814 460,010 20.8 4,280.6 369.16 0.1580 461,790 21.2 4,770.8 344.92 0.1646 463,440 21.6 5,938.0 318.91 0.1894 464,790 22.0 2,309.1 303.56 0.0701 465,860 22.4 1,066.6 316.40 0.0337 466,540 22.8 0.0 417.32 0.00 466,680
6.2-157 Mass Flow Time Rate (sec) (lb/sec) 0.0 0.0 0.025 30,889 0.05 59,169 0.075 56,036 0.1 48,661 0.125 49,879 0.15 50,947 0.175 49,549 0.2 48,698 0.225 49,920 0.25 19,567 0.275 48,527 0.3 49,002 0.325 49,204 0.35 48,458 0.325 47,986 0.4 48,622 0.425 48, 100 0.45 47,679 0.475 47,782 0.5 47,912 0.55 47,235 0.6 46,985 0.65 46,901 0.7 46,321 0.75 46,247 0.8 45,980 0.85 45,470 0.9 45,322 TABLE 6.2-58 (Historical)
SLOWDOWN DATA FOR 4.0 Ft2 COLD LEG GUILLOTINE BREAK Rate of Enthalpy Release (Btu/sec)
(10 Btu/sec) 544.69 0.0 539.84 1.688 549.44 3.210 542.20 3.038 541.50 2.635 541.65 2.702 541.78 2.760 541.65 2.684 541.58 2.637 541.73 2.704 541.71 2.685 541.63 2.628 541.70 2.654 541.74 2.666 541.69 2.625 541.67 2.599 541.77 2.634 541.75 2.606 541.74 2.583 541.78 2.589 541.83 2.596 541.84 2.559 541.89 2.546 541.97 2.542 542.01 2.511 542.11 2.507 547.18 2.488 542.26 2.466 542.36 2.458 6.2-158 Integral Break Mass (lb) 0.0 708.67 2,039.6 3,490.4 4,774.9 6,006.7 7,269.5 8,531.6 9,746.7 10,987 12,231 13,456 14,670 15,903 17,122 18,327 19,534 20,746 21,941 23, 133 24,331 26,700 29,062 31,401 33,734 36,049 38,348 40,635 42,905 Amendment No. 26 (11/13)
TABLE 6.2-5B (Cont'd)
Mass Flow Rate (lb/sec) Rate of Energy Release (10 7 Btu/sec) Integral Break Mass (lb) Time (sec) Enthalpy (Btu/sec) 0.95 45,906 542.47 2.446 45,162 1.0 44,858 542.58 2.434 47,412 1.05 44,679 542.69 2.425 49,649 1.1 44,420 542.79 2.411 51,875 1.15 44,223 542.90 2.401 54,093 1.2 44,051 543.02 2.392 56,299 1.25 43,816 543.13 2.380 58,496 1.3 43,617 543.25 2.370 60,683 1.35 43,410 543.37 2.359 62,858 1.4 43,177 543.50 2.347 65,022 1.45 42,959 543.63 2.335 67,176 1.5 42,722 543.77 2.323 69,318 1.55 42,472 543.90 2.310 71,448 1.6 42,234 544.04 2.298 73,565 1.65 41,985 544.17 2.285 75,671 1.7 41,729 544.30 2.271 77,764 1.75 41,509 544.44 2.260 79,844 1.8 41,264 544.57 2.247 81,914 1.85 41,006 544.70 2.234 83)971 1.9 40,746 544.83 2.220 86,014 1.95 40,469 544.96 2.205 88,045 2.0 40,195 545.08 2.191 90,061 2.1 39,608 545.33 2.160 94,051 2.2 39,010 545.56 2.128 97,982 2.3 38,4 14 545.79 2.097 101,850 2.4 37,773 546.00 2.062 105,660 2.5 37,117 546.21 2.027 109,410 2.6 36,584 546.42 1.999 113,090 2.7 36,055 546.62 1.971 116,720 2.8 35,529 546.80 1.943 120,300 2.9 35,202 546.97 1.925 123,830 3.0 34,965 547.12 1.913 127,340 6.2-159 TABLE 6.2- 5B (Cont'd)
Time (sec) Mass Flow Rate (lb/sec) Enthalpy (BTU/sec) Rate of Energy Rlease (107 BTU/sec)
Integral Break Mass (lb) 3.1 34,746 547.25 1.902 130,830 3.2 34,586 547.41 1.893 134,290 3.3 34,422 547.59 1.885 137,740 3.4 34,243 547.80 1.876 141,180 3.5 34,043 548.01 1.866 144,590 3.6 33,817 548.20 1.854 147,990 3.7 33,574 548.36 1.841 151,360 3.8 33,328 548.57 1.828 154,700 3.9 33,120 548.63 1.817 158,020 4.0 32,898 548.75 1.805 161,320 4.5 31,811 549.20 1.747 177,420 5.0 31,081 549.33 1.707 143,230 5.5 30,334 549.43 1.667 208,580 6.0 29,775 549.18 1.635 223,600 6.5 29,329 548.96 1.610 238,380 7.0 28,930 548.89 1.588 252,950 7.5 28,465 549.22 1.563 267,300 8.0 27,958 550.05 1.538 281,400 8.5 27,339 551.45 1.508 293,230 9.0 26,621 553.52 1.474 308,730 9.5 25,778 556.36 1.434 321,830 10.0 24,744 560.17 1.326 334,470 10.5 23,531 565.0 5 1.330 346,540 11.0 22,106 571.32 1.263 357,960 11.5 20,578 578.79 1.191 368,630 12.0 19,036 586.74 1.117 378,540 12.5 17,548 593.77 1.042 287,680 13.9 16,117 599.70 0.9665 396,090 13.5 14,619 607.25 0.8877 403,780 14.0 13,027 619.34 0.8068 410,670 14.5 11,471 636.22 0.7298 416,796 15.0 9,960.9 657.53 0.6550 422,150 6.2-160 TABLE 6.2- 5B (Cont'd)
Time (sec) Mass Flow Rate (lb/sec) Enthalpy (BTU/sec) Rate of Energy Rlease (107 BTU/sec)
Integral Break Mas s (lb) 15.5 8,579.3 683.04 0.5860 426,770 16.0 7,379.2 715.02 0.5276 430,760 16.5 6,369.3 743.90 0.4738 434,120 17.0 5,581.4 768.54 0.4290 437,160 17.5 4,931.1 787.61 0.3884 439,790 18.0 4,422.1 802.30 0.3548 442,120 18.5 3,989.4 816.16 0.3256 444,220 19.0 3,597.3 829.14 0.2983 446,120 19.5 3,240.8 841.36 0.2727 447,820 20.0 2,853.8 847.54 0.2419 449,366 20.4 2,636.6 851.68 0.2246 450,460 21.0 2,582.9 785.89 0.2030 451,959 21.4 3,276.4 620.59 0.2033 453,140 22.0 3,854.5 499.66 0.1926 455,310 22.4 4,139.0 452.29 0.1872 456,910 23.0 4,195.5 400.63 0.1681 459,430 23.4 3,923.7 375.06 0.1472 461,070 24.0 4,166.4 338.02 0.1408 463,410 24.4 2,225.0 307.05 0.0683 464,820 25.0 1,258.3 307.69 0.0387 466,066
6.2-161 TABLE 6.2-5c (Historical)
SLOWDOWN DATA FOR 3.44 FT 2 HOT LEG GUILLOTINE BREAK Time Mass Flow Total Rate of (sec) Rate Break Mass Enthalpy Release {10 4 lb/sec} (lb} ( 1 0 2 Btu/lb} (10 Btu/sec} 0.0 0.0 0.0 6.212 0.0 0.002 1.399 1.0x10 1 6.208 0.86850 0.004 2.673 5.0x10 1 6.200 1.6573 0.006 3.866 1.2x10 2 6.194 2.3946 0.008 4.734 2.1 x 10 2 6.182 2.9266 0.010 3.269 2.7 x 10 2 6.182 2.0209 0.014 3.268 4.0 x 10 2 6.182 2.0203 0.020 3.270 6.0 x 10 2 6.182 2.0215 0.024 3.271 7.7 x 10 2 6.183 2.0225 0.030 5.918 1.09x10 3 6.183 3.6591 0.034 5.979 1.33 x 10 3 6.184 3.6974 0.040 6.199 1.70x10 3 6.190 3.8372 0.044 6.174 1.95x10 3 6.189 3.8211 0.050 5.982 2.31 x 10 3 6.185 3.6999 0.054 5.961 2.55 x 10 3 6.184 3.6863 0.060 5.925 2.91x10 3 6.183 3.6634 0.064 5.919 3.14x10 3 6.183 3.6597 0.070 3.272 3.47 x 10 3 6.183 2.01'31 0.074 5.915 3.67 x 10 3 6.183 3.6572 0.080 3.272 3.96 x 10 3 6.183 2.0231 0.084 5.913 4.13x10 3 6.183 3.6560 0.090 3.271 4.37x10 3 6.183 2.0225 0:094 3.272 4.51 x 10 3 6.183 2.0231 0.100 3.272 4.71 x 10 3 6.183 2.0231 0.104 3.271 4.84 x 10 3 6.183 2.0225 0.110 3.271 5.04 x 10 3 6.183 2.0225 0.114 3.271 5.17x10 3 6.183 2.0225 0.120 5.912 5.39 x 10 3 6.183 3.6554 0.24 3.271 5.54 x 10 3 6.183 2.0225 6.2-162 Amendment No. 26 (11 /13)
TABLE 6.2-5c (Cont'd)
Mass Flow Rate (10 4 lb/sec) Total Break Mass (lb) Rate of Energy Release (10 7 Btu/sec) Time (Sec) Enthalpy (10 2 Btu/lb) 0.130 5.912 5.78 x 10 3 6.183 3.6554 0.134 3.270 5.93 x 10 3 6.183 2.0231 0.140 3.271 6.16 x 10 3 6.183 2.0225 0.144 5.912 6.31 x 10 3 6.183 3.6554 0.150 5.912 6.53 x 10 3 6.183 3.6554 0.154 3.271 6.67 x 10 3 6.183 2.0225 0.160 3.271 6.86 x 10 3 6.183 2.0225 0.164 3.271 7.00 x 10 3 6.183 2.0225 0.170 3.270 7.19 x 10 3 6.183 2.0218 0.174 3.269 7.32 x 10 3 6.183 2.0212 0.180 3.267 7.52 x 10 3 6.183 2.0200 0.184 3.266 7.65 x 10 3 6.183 2.0194 0.190 3.264 7.84 x 10 3 6.183 2.0181 0.194 3.261 7.98 x 10 3 6.183 2.0162 0.200 3.258 8.17 x 10 3 6.182 2.0141 0.220 3.242 8.82 x 10 3 6.182 2.0042 0.240 3.229 9.47 x 10 3 6.181 1.9958 0.2 60 3.219 1.011 x 10 4 6.181 1.9897 0.280 3.209 1.076 x 10 4 6.180 1.9832 0.300 3.192 1.140 x 10 4 6.179 1.9723 0.350 3.150 1.298 x 10 4 6.177 1.9458 0.400 3.133 1.455 x 10 4 6.175 1.9346 0.500 3.104 1.766 x 10 4 6.171 1.9154 0.600 3.105 2.077 x 10 4 6.170 1.9158 0.700 3.107 2.387 x 10 4 6.169 1.9167 0.800 3.103 2.697 x 10 4 6.169 1.9142 0.900 3.092 3.007 x 10 4 6.169 1.9075 1.00 3.007 3.317 x 10 4 6.168 1.8979 1.100 3.057 3.627 x 10 4 6.168 1.8856 1.20 3.06 3.927 x 10 4 6.169 1.8791 1.30 3.041 4.237 x 10 4 6.172 1.8769 1.40 3.034 4.537 x 10 4 6.174 1.8732 6.2-163 TABLE 6.2-5c (cont'd)
Mass Flow Rate (10 4 lb/sec) Total Break Mass (lb) Rate of Energy Release (10 7 Btu/sec) Time (Sec) Enthalpy (10 2 Btu/lb) 1.50 3.014 4.837 x 10 4 6.176 1.8614 1.60 2.991 5.137 x 10 4 6.178 1.8478 1.70 2.978 5.437 x 10 4 7.181 1.8407 1.80 2.974 5.737 x 10 4 6.185 1.8394 1.90 2.967 6.027 x 10 4 6.190 1.8366 2.00 2.951 6.327 x 10 4 6.194 1.8278 2.40 2.884 7.497 x 10 4 6.213 1.7918 2.60 2.858 8.067 x 10 4 6.225 1.7791 3.00 2.764 9.197 x 10 4 6.242 1.7253 3.40 2.737 1.029 x 10 5 6.264 1.7145 3.60 2.668 1.082 x 10 5 6.276 1.6744 4.00 2.572 1.187 x 10 5 6.198 1.5941 4.40 2.688 1.289 x 10 5 6.138 1.6499 4.60 2.743 1.338 x 10 5 6.072 1.6655 5.00 2.418 1.436 x 10 5 5.544 1.3405 5.40 2.508 1.533 x 10 5 6.034 1.5133 5.60 5.521 1.578 x 10 5 5.977 1.5068 6.00 2.260 1.669 x 10 5 5.934 1.3411 6.40 2.354 1.762 x 10 5 5.874 1.3827 6.60 2.421 1.806 x 10 5 5.964 1.4439 7.00 2.249 1.896 x 10 5 5.902 1.3274 7.40 2.342 1.983 x 10 5 5.771 1.3516 7.60 2.337 2.029 x 10 5 5.874 1.3728 8.00 2.073 2.111 x 10 5 5.813 1.2050 6.2-164 TABLE 6.2-5D ASSUMPTIONS IN RELAP 3 ANALYSIS 0F PRESSURIZER SUBCOMPARTMENT PRESSURE RESPONSE VOLUMES Volume Number Volume (ft
- 3) Volume Height (ft)
Lower Elevation (ft) 1 1981.84 10.28 76.698 2 1957.41 14.69 62.0 3 5167.1 9 32.5 29.5 4 597.1 14.0 62.0 5 597.1 14.0 62.0 6 77421.4 44.0 18.0 7 77421.4 44.0 18.0 8 2.0 x 10 6 121.0 62.0 JUNCTIONS
Junction Number Minimum Flow Area (ft 2) Elevation (ft) Junction Inertia (ft
-1) Friction Coefficient 1 28.8 76.7 0.43368 2.3186 x 10
-7 2 28.8 62.0 0.81944 2.7581 x 10
-7 3 101.38 39.9 0.33785 1.7399 x 10
-8 4 28.0 62.0 0.48214 2.1361 x 10
-7 5 251.05 62.0 0.11551 2.7254 x 10
-9 6 251.05 62.0 0.11551 2.7254 x 10
-9 7 279.4 9 76.0 0.050091 2.1266 x 10
-8 8 279.49 76.0 0.050091 2.1266 x 10
-8 9 424.5 62.0 0.10365 9.646 x 10
-10 10 424.5 62.0 0.10365 9.646 x 10
-10 11 1146.7 38.0 0.54504 1.2742 x 10
-1 0
6.2-165 TABLE 6.2-5E BLOWDOWN DATA FOR PRESSURE RELIEF LINE BREAK Time (sec.) Flow Rate (10 4 lb/sec) Enthalpy (Btu/lb) Flow Quality Flow Integral (10 2 lb) Break Node Pressure (psia) 0.0 0.0 754.5 0.130 0.0 2250.0 0.005 0.0676 754.5 0.130 0.034 2249.9 0.010 0.067 6 754.5 0.130 0.068 2249.8 0.015 0.0676 754.5 0.130 0.101 2249.7 0.020 0.0676 754.5 0.130 0.135 2249.6 0.040 0.0676 754.5 0.130 0.270 2249.2 0.060 0.0676 754.5 0.130 0.405 2248.8 0.080 0.0675 754.5 0.130 0.540 2248.4 0.10 0 0.0675 754.5 0.130 0.675 2248.0 0.120 0.0675 754.5 0.130 0.810 2247.7 0.140 0.0675 754.5 0.130 0.945 2247.3 0.160 0.0675 754.5 0.130 1.080 2246.9 0.180 0.0674 754.5 0.131 1.215 2246.5 0.200 0.0674 754.5 0.131 1.350 2246.1 0.220 0.0674 754.5 0.131 1.485 2245.7 0.240 0.0674 754.5 0.131 1.619 2245.3 0.260 0.0674 754.5 0.131 1.754 2244.9 0.280 0.0674 754.5 0.131 1.889 2246.6 0.300 0.0673 754.4 0.131 2.023 2244.2 0.320 0.0673 754.4 0.131 2.1 58 2243.8 0.340 0.0673 754.4 0.131 2.293 2243.4 0.360 0.0673 754.4 0.131 2.427 2243.0 0.380 0.0672 754.4 0.131 2.562 2242.6 0.400 0.0672 754.4 0.131 2.696 2242.3 0.420 0.0672 754.4 0.131 2.831 2241.9 0.440 0.0672 754.4 0.132 2.965 2241.5 0.460 0.0672 754.4 0.132 3.100 2241.1 0.480 0.0672 754.4 0.132 3.234 2240.7 0.500 0.0672 754.4 0.132 3.368 2240.4 6.2-166 TABLE 6.2-5E (Cont'd)
Flow Integral (10 2 lb) Break Node Pressure (psia) Time (sec.) Flow Rate (10 4 lb/sec) Enthalpy (Btu/lb) Flow Quality 0.600 0.0672 754.3 0.132 4.040 2238.5 0.700 0.0670 754.3 0.132 4.710 2236.6 0.800 0.0670 754.2 0.132 5.380 2234.8 0.900 0.0669 754.2 0.133 6.049 2232.9 1.000 0.0668 754.1 0.133 6.717 2231.1 1.500 0.0665 753.9 0.135 10.048 2221.9 2.000 0.0660 753.8 0.136 13.359 2211.9 2.500 0.0655 753.7 0.138 16.647 2201.0 3.000 0.0651 753.6 0.140 19.913 2190.7 3.500 0.0648 753.4 0.142 23.160 2180.8 4.000 0.0644 753.2 0.144 26.389 2170.9 5.000 0.0636 753.0 0.147 32.789 2150.8
6.2-167 TABLE 6.2-5F BLOWDOWN DATA FOR PRESSURIZER SPRAY LINE BREAK FLOW FROM PRESSURIZER Time (sec.) Flow Rate (10 4 lb/sec) Enthalpy (Btu/lb) Flow Quality Flow Integral (10 2 lb) Break Node Pressure (psia) 0.0 0.0 754.5 0.130 0.0 2250.0 0.005 0.0229 754.5 0.130 0.011 2250.0 0.010 0.0229 754.5 0.130 0.023 2249.9 0.015 0.022 9 754.5 0.130 0.034 2249.9 0.020 0.0229 754.5 0.130 0.046 2249.9 0.040 0.0229 754.5 0.130 0.091 2249.7 0.060 0.0229 754.5 0.130 0.137 2249.6 0.080 0.0229 754.5 0.130 0.183 2249.5 0.100 0.0229 754.5 0.130 0.229 2249.3 0.12 0 0.0229 754.5 0.130 0.274 2249.2 0.140 0.0229 754.5 0.130 0.320 2249.1 0.160 0.0229 754.5 0.130 0.366 2248.9 0.180 0.0229 754.5 0.130 0.412 2248.8 0.200 0.0229 754.5 0.130 0.457 2248.7 0.220 0.0229 754.5 0.130 0.503 2248.6 0.240 0.0229 754.5 0.130 0.549 2248.4 0.260 0.0229 754.5 0.130 0.594 2248.3 0.280 0.0229 754.5 0.130 0.640 2248.2 0.300 0.0229 754.5 0.130 0.686 2248.0 0.320 0.0229 754.5 0.130 0.731 2247.9 0.340 0.0229 754.5 0.130 0.7 77 2247.8 0.360 0.0229 754.5 0.130 0.823 2247.6 0.380 0.0229 754.5 0.130 0.868 2247.5 0.400 0.0229 754.5 0.130 0.914 2247.4 0.420 0.0229 754.5 0.130 0.960 2247.3 0.440 0.0229 754.5 0.130 1.005 2247.1 0.460 0.0229 754.5 0.130 1.051 2247.0 0.480 0.0229 754.5 0.130 1.097 2246.9 0.500 0.0229 754.5 0.130 1.142 2246.7 0.600 0.0228 754.4 0.131 1.371 2246.1 6.2-168 TABLE 6.2-5F (cont'd) Time (sec) Flow Rate (10 4 lb/sec) Enthalpy (Btu/lb) Flow Quality Flow Intragral (10 2 lb) Break Node Pressure (psia) 0.700 0.0228 754.4 0.131 1.599 2245.5 0.800 0.0228 754.4 0.131 1.827 2244.8 0.900 0.0228 754.4 0.131 2.055 2244.2 1.000 0.0228 754.4 0.131 2.283 2243.6 1.500 0.0227 754.3 0.132 3.420 2240.0 2.000 0.0227 754.3 0.133 4.555 2235.3 2.500 0.0226 754.2 0.134 5.686 2230.4 3.000 0.0225 754.2 0.134 6.814 2226.1 3.500 0.0225 754.2 0.135 7.939 2222.3 4.000 0.0224 754.1 0.136 9.061 2218.1 5.000 0.0223 754.1 0.138 11.297 2210.2
6.2-169 TABLE 6.2-5G SLOWDOWN DATA FOR PRESSURIZER SPRAY LINE BREAK -FLOW FROM COLD LEG Time Flow Rate Enthalpy Flow Flow Break Node (sec) (104 lb/sec) (Btu/lb) Quality Pressure (10 lb}
0.0 0.0 556.7 0.0 0.0 2308.0 0.005 0.152 556.4 0.0 0.077 2254.9 0.010 0.151 556.4 0.0 0.152 2249.0 0.015 0.154 556.6 0.0 0.229 2284.1 0.020 0.156 556.7 0.0 0.306 2317.4 0.040 0.156 556.7 0.0 0.617 2309.4 0.060 0.153 556.5 0.0 0.927 2272.6 0.080 0.156 556.7 0.0 1.237 2311.1 0.100 0.154 556.6 0.0 1.545 2293.9 0.120 0.155 556.6 0.0 1.855 2300.6 0.140 0.153 556.5 0.0 2.163 2276.9 0.160 0.155 556.6 0.0 2.471 2297.8 0.180 0.154 556.6 0.0 2.780 2286.5 0.200 0.153 556.5 0.0 3.087 2279.5 0.220 0.154 556.6 0.0 3.395 2288.5 0.240 0.153 556.5 0.0 3.702 2279.1 0.260 0.154 556.6 0.0 4.009 2285.3 0.280 0.153 556.5 0.0 4.316 2269.5 0.300 0.154 556.6 0.0 4.622 2284.6 0.320 0.153 556.5 0.0 4.929 2269.8 0.340 0.153 556.5 0.0 5.235 2277.7 0.360 0.153 556.5 0.0 5.541 2269.1 0.380 0.153 556.5 0.0 6.153 2270.5 0.420 0.153 556.5 0.0 6.458 2267.6 0.440 0.153 556.5 0.0 6.764 2270.5 0.460 0.152 556.5 0.0 7.069 2264.9 0.480 0.153 556.5 0.0 7.374 2268.9 0.500 0.152 556.5 0.0 7.679 2264.6 0.600 0.152 556.5 0.0 9.203 2261.9 6.2-170 TABLE 6.2-5G (Cont'd) Time Flow Rate Enthalpy Flow Flow Break Node (sec) (104 lb/sec) (Btu/lb) Quality Pressure (10 lb) (psia) 0.700 0.152 556.5 0.0 10.727 2264.9 0.800 0.152 556.5 0.0 12.250 2263.1 0.900 0.152 556.4 0.0 13.773 2263.1 1.000 0.152 556.4 0.0 15.297 2264.6 1.500 0.153 556.3 0.0 22.924 2265.3 2.000 0.152 556.1 0.0 30.538 2255.3 2.500 0.151 556.0 0.0 38.116 2242.9 3.000 0.151 555.8 0.0 45.658 2232.8 3.500 0.150 555.8 0.0 53.174 2223.8 4.000 0.149 555.9 0.0 60.660 2214.5 5.000 0.148 556.1 0.0 75.536 2195.3 6.2-171 TABLE 6.2-5H SLOWDOWN MASS AND ENERGY RELEASE RATES FOR 9.82 FT 2 DOUBLE ENDED DISCHARGE LEG SLOT BREAK TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 0.00 O.OOOOOE+OO O.OOOOOE+OO 0.01 7.51006E+04 4.10883E+07 0.02 7.44669E+04 4.06817E+07 0.03 7.48366E+04 4.08571 E+07 0.04 7.56952E+04 4.13273E+07 0.05 8.45197E+04 4.61587E+07 0.06 7.85727E+04 4.29206E+07 0.07 7.74614E+04 4.22947E+07 0.08 7.84992E+04 4.28552E+07 0.09 1.07509E+05 5.87667E+07 0.10 1.08453E+05 5.93118E+07 0.15 1.11939E+05 6.13947E+07 0.20 1.09651 E+05 6.02055E+07 0.25 1.08166E+05 5.94257E+07 0.30 1 . 07769E+05 5.92139E+07 0.35 1.06073E+05 5.82752E+07 0.40 1.06108E+05 5.82891 E+07 0.45 1.05195E+05 5.77809E+07 0.50 1.04560E+05 5.74318E+07 0.60 1.03939E+05 5.70975E+07 0.70 1.03379E+05 5.68131 E+07 0.80 1.00563E+05 5.52990E+07 0.90 9.71998E+04 5.35023E+07 1.00 9.74095E+04 5.37148E+07 2.00 7.45547E+04 4.24901 E+07 3.00 5.48175E+04 3.16045E+07 4.00 4.77191 E+04 2.87901 E+07 6.2-171a Amendment No. 26 (11/13)
TABLE 6.2-5H (continued)
SLOWDOWN MASS AND ENERGY RELEASE RATES FOR 9.82 FT 2 DOUBLE ENDED DISCHARGE LEG SLOT BREAK TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 5.00 3.56297E+04 2.36275E+07 6.00 3.28665E+04 2.15538E+07 7.00 2.57661 E+04 1.80279E+07 8.00 1.94331 E+04 1.49682E+07 9.00 1.27353E+04 1.13226E+07 10.00 7.69080E+03 7.76118E+06 11.00 6.22773E+03 6.30647E+06 12.00 4.88331 E+03 4.94075E+06 13.00 2.06953E+03 2.53507E+06 14.00 1.01689E+03 1.287 43E+06 14.10 9.33850E+02 1.19303E+06 14.20 8.67791 E+02 1.11164E+06 14.30 8.03195E+02 1.03139E+06 14.40 O.OOOOOE+OO O.OOOOOE+OO INTEGRAL 4.71007E+05 2.95676E+08 (lbm) (BTU) 6.2-171b Amendment No. 26 (11 /13)
TABLE 6.2-51 REFLOOD/POST-REFLOOD MASS AND ENERGY RELEASE RATES FOR 9.82 FT 2 DOUBLE ENDED DISCHARGE LEG SLOT BREAK, MAX SI TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 14.39 O.OOOOOE+OO O.OOOOOE+OO 14.40 1.0591 OE+02 1.38190E+05 17.40 4.08690E+02 5.30180E+05 20.20 6.80500E+02 8.75070E+05 22.20 7.31870E+02 9.36220E+05 22.21 3.65935E+02 4.68110E+05 23.00 3.66550E+02 4.68215E+05 25.80 3.67355E+02 4.67570E+05 28.60 3.66915E+02 4.65970E+05 31.40 3.65875E+02 4.6391 OE+05 34.20 3.6451 OE+02 4.61600E+05 37.00 3.62960E+02 4.59155E+05 39.80 3.61310E+02 4.56635E+05 42.60 3.59605E+02 4.54075E+05 45.40 3.57880E+02 4.51500E+05 48.20 3.56140E+02 4.48920E+05 51.00 3.54390E+02 4.46340E+05 53.80 3.52635E+02 4.43750E+05 56.59 3.50875E+02 4.41165E+05 56.60 7.01750E+02 8.82330E+05 66.30 6.47600E+02 8.13500E+05 76.00 5.99420E+02 7.52720E+05 85.70 5.58320E+02 7.00860E+05 95.30 5.25570E+02 6.59370E+05 105.00 4.99220E+02 6.25830E+05 114.70 4.78520E+02 5.99310E+05 124.40 4.6251 OE+02 5.78570E+05 134.00 4.50340E+02 5.62600E+05 6.2-171c Amendment No. 26 (11 /13)
TABLE 6.2-51 (continued)
REFLOOD/POST-REFLOOD MASS AND ENERGY RELEASE RATES FOR 9.82 FT 2 DOUBLE ENDED DISCHARGE LEG SLOT BREAK, MAX SI TIME MASS RATE ENERGY RATE (sec) (lbm/sec)
<BTU/sec) 143.70 4.40900E+02 5.50040E+05 153.40 4.33990E+02 5.40520E+05 163.10 4.28870E+02 5.33190E+05 172.70 4.12720E+02 4.94180E+05 182.40 3.85750E+02 4.53600E+05 192.10 3.5271 OE+02 4.14740E+05 201.70 3.22960E+02 3.79770E+05 201.80 3.19826E+02 3.80184E+05 202.80 3.22175E+02 3.76263E+05 205.00 3.18528E+02 3.75556E+05 208.30 3.17229E+02 3.72476E+05 212.60 3.1267 4E+02 3.67989E+05 218.10 3.06599E+02 3.60375E+05 224.60 2.97526E+02 3.50087E+05 232.20 2.86686E+02 3.36873E+05 241.00 2.73357E+02 3.21537E+05 250.80 2.39715E+02 2.81826E+05 261.60 2.10698E+02 2.47837E+05 273.60 1.83898E+02 2.16106E+05 286.70 1.59200E+02 1.87279E+05 300.90 1.37279E+02 1.61461E+05 316.10 1.18126E+02 1.38879E+05 332.40 1.01542E+02 1.19369E+05 332.41 O.OOOOOE+02 O.OOOOOE+OO INTEGRAL 1.128926E+05 1.38698E+08 (lbm) <BTU) 6.2-171d Amendment No. 26 (11 /13)
TABLE 6.2-5J SPILLAGE AND CONDENSATION MASS AND ENERGY RELEASE RATES FOR 9.82 FT 2 DOUBLE ENDED DISCHARGE LEG SLOT BREAK, MAX SI TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 14.40 0.00 0.00 22.10 0.00 0.00 22.20 5946.70 496050.68 24.20 5644.37 474479.33 26.20 5376.63 455225.72 28.20 5136.59 437865.19 34.90 4478.50 389903.79 39.90 4089.50 361337.54 44.90 3759.60 336997.45 49.90 3473.71 315819.93 54.90 3221.78 297084.38 55.00 331.24 84945.89 56.60 0.00 0.00 169.80 0.00 0.00 169.90 30.43 7799.48 179.90 66.18 16961.97 189.90 107.38 27521.14 199.90 139.74 35815.17 201.70 144.53 37042.07 211.70 255.80 65560.31 221.70 327.87 84029.30 231.70 372.09 95364.28 241.70 399.26 102325.94 251.70 451.47 115706.71 261.70 475.20 121788.49 271.70 493.11 126379.32 281.70 507.60 130093.46 291.70 519.35 133104.33 6.2-171e Amendment No. 26 (11 /13)
TABLE 6.2-5J (Continued)
SPILLAGE AND CONDENSATION MASS AND ENERGY RELEASE RATES FOR 9.82 FT 2 DOUBLE ENDED DISCHARGE LEG SLOT BREAK. MAX SI TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 301.70 528.76 135516.00 311.70 536.60 137525.55 321.70 543.29 139239.15 331.70 549.37 140799.51 332.38 0.00 0.00 6.2-171f Amendment No. 26 (11 /13)
TABLE 6.2-5K REFLOOD/POST-REFLOOD MASS AND ENERGY RELEASE RATES FOR 9.82 FT 2 DOUBLE ENDED DISCHARGE LEG SLOT BREAK. MIN SI TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 14.30 O.OOOOOE+OO O.OOOOOE+OO 14.40 1.04260E+02 1.36040E+05 17.40 3.95430E+02 5.1311 OE+05 20.20 6.60860E+02 8.50290E+05 22.20 7.31500E+02 9.36030E+05 22.21 3.65750E+02 4.68015E+05 23.00 3.66400E+02 4.68150E+05 25.80 3.67300E+02 4.67575E+05 28.60 3.66900E+02 4.66000E+05 31.40 3.65880E+02 4.63960E+05 34.20 3.64525E+02 4.61660E+05 37.00 3.62985E+02 4.59220E+05 39.80 3.61335E+02 4.56700E+05 42.60 3.59635E+02 4.54140E+05 45.40 3.57905E+02 4.51565E+05 48.20 3.56165E+02 4.48980E+05 51.00 3.54415E+02 4.46395E+05 53.80 3.52655E+02 4.43810E+05 56.59 3.50895E+02 4.41220E+05 56.60 7.01790E+02 8.82440E+05 72.70 5.53320E+02 6.97310E+05 88.70 4.37270E+02 5.52950E+05 104.70 3.55350E+02 4.50560E+05 120.80 3.01290E+02 3.82660E+05 136.80 2.69290E+02 3.42240E+05 152.80 2.51930E+02 3.2011 OE+05 6.2-1719 Amendment No. 26 (11/13)
TABLE 6.2-5K (Continued)
REFLOOD/POST-REFLOOD MASS AND ENERGY RELEASE RATES FOR 9.82 FT 2 DOUBLE ENDED DISCHARGE LEG SLOT BREAK. MIN SI TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 168.90 2.43140E+02 3.08710E+05 184.90 2.38980E+02 3.03080E+05 200.90 2.37080E+02 3.00280E+05 217.00 2.36250E+02 2.98810E+05 233.00 2.35930E+02 2.97960E+05 249.00 2.35830E+02 2.97390E+05 265.10 2.35800E+02 2.9691 OE+05 281.10 2.35860E+02 2.96510E+05 297.10 2.35920E+02 2.96100E+05 297.20 2.44051 E+02 2.89982E+05 299.20 2.39165E+02 3.12010E+05 303.40 2.62266E+02 3.19039E+05 309.70 2. 70788E+02 3.44456E+05 318.00 2.73309E+02 3.17300E+05 328.50 2.68405E+02 3.21368E+05 341.00 2.52528E+02 2.94016E+05 355.60 2.38979E+02 2.84066E+05 372.30 2.21830E+02 2.59326E+05 391.10 2.06893E+02 2.44821 E+05 412.00 1.92613E+02 2.257 44E+05 434.90 1. 78828E+02 2.10938E+05 460.00 1.38349E+02 1.62409E+05 487.10 1.21798E+02 1.43496E+05 516.40 1.01333E+02 1.19003E+05 547.70 9.25325E+01 1.08920E+05 547.71 O.OOOOOE+OO O.OOOOOE+OO INTEGRAL 1.33816E+05 1.65596E+08 (lbm) (BTU) 6.2-171h Amendment No. 26 (11 /13)
TABLE 6.2-5L SPILLAGE AND CONDENSATION MASS AND ENERGY RELEASE RATES FOR 9.82 FT 2 DOUBLE ENDED DISCHARGE LEG SLOT BREAK, MIN SI TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 14.40 0.00 0.00 22.10 0.00 0.00 22.20 5682.24 476956.02 24.20 5379.81 455392.21 26.20 5112.03 436146.77 28.20 4872.00 418792.50 34.90 4213.96 370842.08 39.90 3825.02 342280.15 44.90 3495.19 317945.10 49.90 3209.35 296771.20 54.90 2957.46 278038.52 55.00 331.26 84950.72 56.60 0.00 0.00 297.10 0.00 0.00 317.00 0.00 0.00 317.10 43.67 11193.27 327.10 74.20 19016.65 337.10 101.46 26002.96 347.10 121.85 31228.80 357.10 137.20 35164.11 367.10 148.84 38145.90 377.10 158.12 40525.06 387.10 165.43 42397.31 397.10 171.21 43880.38 407.10 175.92 45087.49 417.10 179.86 46096.54 6.2-171i Amendment No. 26 (11/13)
TABLE 6.2-5L (Continued)
SPILLAGE AND CONDENSATION MASS AND ENERGY RELEASE RATES FOR 9.82 FT 2 DOUBLE ENDED DISCHARGE LEG SLOT BREAK, MIN SI TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 427.10 183.23 46960.70 437.10 206.00 52796.65 447.10 218.64 56035.98 457.10 228.60 58588.83 467.10 236.65 60651.10 477.10 243.55 62420.66 487.10 249.32 63898.87 497.10 254.14 65134.52 507.10 258.25 66186.52 517.10 261.80 67096.19 527.10 264.90 67892.07 537.10 267.65 68595.85 547.10 270.10 69224.15 547.63 0.00 0.00 6.2-171j Amendment No. 26 (11/13)
TABLE 6.2-5M SLOWDOWN MASS AND ENERGY RELEASE RATES FOR 9.82 FT 2 DOUBLE ENDED SUCTION LEG SLOT BREAK TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 0.00 O.OOOOOE+OO O.OOOOOE+OO 0.01 7.551 OOE+04 4. 13574E+07 0.02 7.45564E+04 4.07763E+07 0.03 7.41284E+04 4.05002E+07 0.04 7.40535E+04 4.04384E+07 0.05 7.40933E+04 4.04572E+07 0.06 7.40716E+04 4.04525E+07 0.07 7.39202E+04 4.03828E+07 0.08 7. 36890E+04 4.02728E+07 0.09 7.33993E+04 4.01305E+07 0.10 7.30548E+04 3.99574E+07 0.15 7.27921 E+04 3.98865E+07 0.20 7.33685E+04 4.03057E+07 0.25 7. 33583E+04 4.03500E+07 0.30 7.39725E+04 4.07549E+07 0.35 7.35223E+04 4.05428E+07 0.40 7.39240E+04 4.08213E+07 0.45 7.32790E+04 4.05079E+07 0.50 7.35650E+04 4.07201 E+07 0.60 7.30371 E+04 4.05276E+07 0.70 7.25088E+04 4.03439E+07 0.80 7.21671E+04 4.02748E+07 0.90 7. 18389E+04 4.02091 E+07 1.00 7. 15052E+04 4.01376E+07 2.00 6.38934E+04 3.63972E+07 3.00 4.87024E+04 2.86350E+07 4.00 3.50182E+04
- 2. 15404E+07 6.2-171k Amendment No. 26 (11 /13)
TABLE 6.2-5M (continued)
SLOWDOWN MASS AND ENERGY RELEASE RA TES FOR 9.82 FT 2 DOUBLE ENDED SUCTION LEG SLOT BREAK TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 5.00 3.21661 E+04 2.00738E+07 6.00 2.76937E+04 1.80397E+07 7.00 2.49120E+04 1.65822E+07 8.00 2.24587E+04 1.52489E+07 9.00 2.04383E+04 1.41121 E+07 10.00 1.83848E+04 1.29881 E+07 11.00 1.60880E+04 1.17754E+07 12.00 1.28233E+04 1.01239E+07 13.00 1.02417E+03 8.32580E+06 14.00 8.13115E+03 6.80158E+06 15.00 6.36439E+03 5.49771 E+06 16.00 4.98096E+03 4.37373E+06 17.00 4.79010E+03 3.11290E+06 18.00 2.85744E+03 1.77095E+06 18.10 2.63900E+03 1.72279E+06 18.20 2.42945E+03 1.63946E+06 18.30 2.24851 E+03 1.55232E+06 18.40 2.08220E+03 1.46868E+06 18.50 2.02652E+03 1.43087E+06 18.60 O.OOOOOE+OO O.OOOOOE+OO INTEGRAL 4.68198E+05 2.95826E+08 (lbm) (BTU) 6.2-1711 Amendment No. 26 (11 /13)
TABLE 6.2-5N REFLOOD/POST-REFLOOD MASS AND ENERGY RELEASE RATES FOR 9.82 FT 2 DOUBLE ENDED SUCTION LEG SLOT BREAK. MIN SI TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 18.59 O.OOOOOE+OO O.OOOOOE+OO 18.60 1.39890E+02 1.80660E+05 22.50 8.96670E+02 1.14216E+06 24.40 1.14839E+03 1.44601 E+06 24.41 5.74195E+02 7.23005E+05 26.20 5.77295E+02 7.22115E+05 29.90 5.75605E+02 7.14820E+05 33.60 5.69920E+02 7.04880E+05 37.30 5.62985E+02 6.94170E+05 41.00 5.55400E+02 6.82975E+05 44.70 5.48055E+02 6.72200E+05 48.40 5.40820E+02 6.61610E+05 52.10 5.15455E+02 6.17735E+05 55.80 4.86205E+02 5.83020E+05 59.50 4.58825E+02 5.50515E+05 63.20 4.33100E+02 5.19960E+05 66.90 4.08825E+02 4.91120E+05 70.60 3.84885E+02 4.62680E+05 74.29 3.62235E+02 4.35760E+05 74.30 7.24470E+02 8.71520E+05 81.10 6.60550E+02 7.92610E+05 87.80 5.74850E+02 6.92120E+05 94.50 4.68090E+02 5.72510E+05 101.30 3.94280E+02 4.8291 OE+05 108.00 3.41740E+02 4.19050E+05 114.70 3.04740E+02 3.74070E+05 121.40 2.80600E+02 3.44520E+05 6.2-171m Amendment No. 26 (11 /13)
TABLE 6.2-5N (Continued)
REFLOOD/POST-REFLOOD MASS AND ENERGY RELEASE RATES FOR 9.82 FT 2 DOUBLE ENDED SUCTION LEG SLOT BREAK, MIN SI TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 128.20 2.65830E+02 3.26320E+05 134.90 2.57 410E+02 3.15800E+05 141.60 2.37570E+02 2.85940E+05 148.30 2.15750E+02 2.59960E+05 155.10 1.96620E+02 2.37170E+05 161.80 1.8041 OE+02 2.17830E+05 168.50 1.66470E+02 2.01200E+05 175.20 1.54500E+02 1.8691 OE+05 175.30 1.65481 E+02 1.79889E+05 180.10 1.49788E+02 1.95111 E+05 189.70 1.60212E+02 1.83291 E+05 204.20 1.39261 E+02 1.76434E+05 223.50 1.35350E+02 1.59504E+05 247.60 1.22176E+02 1.51866E+05 276.60 1.201 OOE+02 1.44187E+05 310.40 1.14896E+02 1.41316E+05 349.00 1.14224E+02 1.38230E+05 392.40 1.11259E+02 1.36241 E+05 440.60 1.09530E+02 1.32943E+05 493.70 1.06047E+02 1.29505E+05 551.60 1.02727E+02 1.24816E+05 614.40 9.82780E+01 1.19834E+05 681.90 9.38701 E+01 1.14106E+05 754.30 8.98316E+01 1.07441E+05 754.40 O.OOOOOE+OO O.OOOOOE+OO INTEGRAL 1.26084E+05 1.53632E+08 (lbm) (BTU) 6.2-171n Amendment No. 26 (11 /13)
TABLE 6.2-50 SPILLAGE AND CONDENSATION MASS AND ENERGY RELEASE RATES FOR 9.82 FT 2 DOUBLE ENDED SUCTION LEG SLOT BREAK, MIN SI TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 18.60 0.00 0.00 24.30 0.00 0.00 24.40 6736.36 591360.46 26.40 6273.50 558594.00 28.40 5872.63 529636.92 34.90 4849.75 454168.19 39.90 4253.48 409408.37 44.90 3766.99 372464.52 49.90 3356.55 341084.56 54.80 2872.72 298124.92 54.90 3043.39 343521.02 59.90 2760.86 337484.46 64.90 2522.51 334046.62 69.90 2321.42 333611.80 70.00 893.30 229005.56 74.30 501.00 128401.60 74.90 499.35 127978.19 79.90 166.61 42701.71 84.90 39.31 10074.75 139.90 23.78 6094.45 149.90 54.82 14050.30 159.90 78.02 19996.21 169.90 96.11 24631.33 175.20 104.12 26683.78 185.20 197.54 50627.99 195.20 226.28 57993.19 205.20 237.68 60915.94 6.2-1710 Amendment No. 26 (11 /13)
TABLE 6.2-50 (Continued)
SPILLAGE AND CONDENSATION MASS AND ENERGY RELEASE RATES FOR 9.82 FT 2 DOUBLE ENDED SUCTION LEG SLOT BREAK, MIN SI TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 215.20 243.57 62424.76 225.20 247.37 63398.13 235.20 250.15 64109.88 245.20 252.29 64659.80 255.20 254.02 65103.15 265.20 255.38 65452.46 275.20 256.51 65740.87 285.20 257.45 65982.42 295.20 258.26 66188.84 305.20 258.96 66369.49 315.20 259.59 66531.67 325.20 260.18 66681.00 335.20 260.73 66821.93 345.20 261.26 66957.72 355.20 261.78 67090.88 365.20 262.29 67223.26 375.20 262.81 67356.24 385.20 263.34 67490.77 395.20 263.87 67627.53 405.20 264.41 67766.97 415.20 264.97 67909.36 425.20 265.54 68054.82 435.20 266.12 68203.39 445.20 266.71 68355.02 455.20 267.31 68509.61 465.20 267.93 68667.54 475.20 268.55 68827.97 485.20 269.19 68990.46 495.20 269.83 69155.11 505.20 270.48 69321.80 6.2-171p Amendment No. 26 (11 /13)
TABLE 6.2-50 (Continued)
SPILLAGE AND CONDENSATION MASS AND ENERGY RELEASE RATES FOR 9.82 FT 2 DOUBLE ENDED SUCTION LEG SLOT BREAK. MIN SI TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 515.20 271.14 69490.35 525.20 271.80 69660.58 535.20 272.47 69832.26 545.20 273.15 70005.25 555.20 273.83 70179.35 565.20 274.51 70354.39 575.20 275.17 70523.85 585.20 275.89 70707.71 595.20 276.59 70886.21 605.20 277.28 71063.73 615.20 277.97 71241.16 625.20 278.66 71418.61 635.20 279.35 71595.99 645.20 280.05 71773.23 655.20 280.74 71950.22 665.20 281.43 72126.88 675.20 282.11 72303.12 685.20 282.80 72478.86 695.20 283.48 72654.03 705.20 284.16 72828.57 715.20 284.84 73002.43 725.20 285.52 73176.09 735.20 286.86 73519.07 745.20 290.26 74391.36 754.25 0.00 0.00 6.2-171q Amendment No. 26 (11 /13)
TABLE 6.2-5P BLOWDOWN MASS AND ENERGY RELEASE RATES FOR 19.24 FT 2 DOUBLE ENDED HOT LEG SLOT BREAK TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 0.00 O.OOOOOE+OO O.OOOOOE+OO 0.01 1.68385E+05 1.04871 E+08 0.02 1.62589E+05 1.00944E+08 0.03 1.65073E+05 1.02631 E+08 0.04 1.55596E+05 9.67255E+07 0.05 1.36097E+05 8.42866E+07 0.06 1.32715E+05 8.18943E+07 0.07 1.42680E+05 8.84347E+07 0.08 1.42387E+05 8.84242E+07 0.09 1.34188E+05 8.31689E+07 0.10 1.35261 E+05 8.37242E+07 0.15 1.37538E+05 8.54279E+07 0.20 1.29315E+05 8.03996E+07 0.25 1.21802E+05 7.56211 E+07 0.30 1.15486E+05 7.16113E+07 0.35 1.12802E+05 6.98383E+07 0.40 1.09400E+05 6.75873E+07 0.45 1.06243E+05 6.55579E+07 0.50 1.04544E+05 6.44494E+07 0.60 1.00829E+05 6.20822E+07 0.70 9.52003E+04 5.85836E+07 0.80 9.18375E+04 5.65383E+07 0.90 8.84850E+04 5.46271 E+07 1.00 8.52772E+04 5.28254E+07 2.00 6.89190E+04 4.27475E+07 3.00 6.03580E+04
- 3. 76156E+07 4.00 5.16043E+04 3.26213E+07 6.2-171r Amendment No. 26 (11 /13)
TABLE 6.2-5P (continued)
SLOWDOWN MASS AND ENERGY RELEASE RATES FOR 19.24 FT 2 DOUBLE ENDED HOT LEG SLOT BREAK TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 5.00 4.37226E+04 2.82913E+07 6.00 3.38714E+04 2.33294E+07 7.00 2.35163E+04 1.84552E+07 8.00 1.65501 E+04 1.38794E+07 9.00 9.26016E+03 9.65760E+06 10.00 3.63331 E+03 4.10033E+06 10.10 3.24586E+03 3.69025E+06 10.20 2.84525E+03 3.26451 E+06 10.30 2.51560E+03 2.91769E+06 10.40 2.21444E+03 2.61169E+06 10.50 1.91659E+03 2.30069E+06 10.60 1.66072E+03 2.01835E+06 10.70 1.44485E+03
- 1. 76554E+06 10.80 1.24960E+03 1.53473E+06 10.90 1.08213E+03 1.33311 E+06 11.00 O.OOOOOE+OO O.OOOOOE+OO INTEGRAL 4.62873E+05 3.04235E+08 (lbm) (BTU) 6.2-171s Amendment No. 26 (11 /13)
TABLE 6.2-50 MASS AND ENERGY RELEASE RATES FOR 100.3% POWER MSLB WITH FAILURE OF A CONTAINMENT SPRAY PUMP TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 0.0 6810.49 8.15098E+06 1.0 6055.73 7.26478E+06 2.0 5498.75 6.60632E+06 3.0 5093.85 6.12565E+06 4.0 4782.06 5. 75419E+06 5.0 4542.79 5.46839E+06 6.0 4359.55 5.24911 E+06 7.0 4218.4 5.07995E+06 8.0 4106.65 4.94589E+06 9.0 4007.35 4.82664E+06 10.0 3908.39 4. 70770E+06 11.0 3806.29 4.58491 E+06 12.0 3703.25 4.46089E+06 130 3605.53 4.34321 E+06 14.0 3518.54 4.23837E+06 15.0 3443.96 4.14844E+06 16.0 3379.61 4.07082E+06 17.0 3321.22 4.00036E+06 18.0 3264.8 3.93225E+06 19.0 3208.36 3.86410E+06 20.0 3152.24 3.79632E+06 22.0 3047.94 3.67027E+06 24.0 2959.54 3.56339E+06 26.0 2872.26 3.45781 E+06 28.0 2787.12 3.35478E+06 30.0 2706.68 3.25740E+06 32.0 2635.14 3.17076E+06 34.0 2570.57 3.09255E+06 36.0 2508.73 3 01762E+06 38.0 2449.17 2.94545E+06 40.0 2393.58 2.87807E+06 42.0 2341.59 2.81504E+06 44.0 2291.46 2.75425E+06 46.0 2242.87 2.69533E+06 48.0 2196.53 2.63912E+06 50.0 2152.4 2.58560E+06 6.2-171t Amendment No. 26 ( 11 /13)
TABLE 6.2-50 (continued)
MASS AND ENERGY RELEASE RA TES FOR 100.3% POWER MSLB WITH FAILURE OF A CONTAINMENT SPRAY PUMP TIME MASS RATE ENERGY RATE (sec) (lbm/sec) (BTU/sec) 52.0 2109.81 2.53393E+06 54.0 2068.52 2.48384E+06 56.0 2028.82 2.43568E+06 58.0 1968.15 2.36207E+06 60.0 1920.2 2.30388E+06 62.0 1876.41 2.25075E+06 64.0 1834.19 2.19952E+06 66.0 1794.1 2.15087E+06 68.0 1753.88 2.10207E+06 70.0 1711.89 2.05112E+06 720 1671.41 2.00203E+06 74.0 1634.37 1.95712E+06 76.0 1598.97 1.91419E+06 78.0 1564.22 1.87206E+06 80.0 1530.99 1.83176E+06 82.0 1499.79 1.79394E+06 84.0 1469.93 1.75775E+06 86.0 1431.31 1.71094E+06 88.0 1336.28 1.59579E+06 90.0 1205.08 1.43689E+06 92.0 1071.9 1.27573E+06 94.0 943.035 1.11997E+06 96.0 827.885 980765 98.0 716.441 846187 100.0 436.048 513711 105.0 221.878 261014 110.0 145.816 171477 115.0 106.452 125159 120.0 135.814 164581 125.0 3.49764 4408.15 130.0 2.77609 3504.17 135.0 2.45378 3100.84 140.0 2.36089 2986.59 145.0 2.247 2844.99 6.2-171u Amendment No. 26 (11/13)
TABLE 6.2-50 (continued)
MASS AND ENERGY RELEASE RA TES FOR 100.3% POWER MSLB WITH FAILURE OF A CONTAINMENT SPRAY PUMP TIME MASS RATE ENERGY RATE (sec) !lbm/sec)
!BTU/sec) 150.0 2.10224 2663.97 155.0 2.04254 2590.26 160.0 1.9345 2454.97 165.0 1.86303 2365.83 170.0 1.79446 2280.13 175.0 1.71997 2186.75 180.0 1.66485 2117.81 185.0 1.60325 2040.50 190.0 1.55034 1974.12 195.0 1.5008 1911.94 200.0 1.45196 1850.54 205.0 1.40938 1797 05 210.0 1.36739 1744.24 215.0 1.32785 1694.47 220.0 1.29036 1647.28 225.0 1.25426 1601.79 230.0 1.22039 1559.10 235.0 1.18772 1517.92 240.0 1.15666 1478.74 245.0 1.12699 1441.30 250.0 1.0988 1405.71 255.0 1.08401 1387.25 260.0 1.00293 1283.93 265.0 0.981088 1256.19 270.0 0.916355 1173.50 275.0 0.911979 1168.06 280.0 0.879567 1126.68 285.0 0.857845 1099.00 290.0 0.84299 1080 08 295.0 0.818053 1048.25 300.0 0.803303 1029.46 300.0 0.803279 1029.43 6.2-171v Amendment No. 26 (11 /13)
- 1. TABLE 6.2-6 DESCRIPTION OF ASSUMPTIONS USED IN SHIELD BUILDING ANNULUS TRANSIENT ANALYSES Initial Conditions Containment pressure, psia Containment vessel free volume, ft 3 Containment air temperature, °F Steel wall and annulus air initial temperature, °F Constant outside air pressure, psia Constant outside air temperature, °F Annulus free volume, ft 3 Annulus pressure, psia Steel cylinder and dome internal radii, ft Steel building and concrete shielq building cylinder heights: From annulus floor to effective height of secondary shield wall (for representation of thermal radiation from concrete secondary shield wall to surrounding steel), ft; from secondary shield wall top to spring line, ft Thickness of steel cylinder, in. Thickness of steel dome, in. Thickness of concrete shield building cylinder, ft Thickness of concrete shield building top (approximated for heat transfer calculations by a dome with a 74 ft radius), ft. Coefficient of linear expansion (from temperature) for steel walls, in.fin.-°F Modulus of elasticity for steel, psi 14.7 2.511x10 5 120 120 14.7 95 540,000 14.7 70 52 74 1.91 0.95 3 2.5 0.65 x 10-5 30 x 10 6 2. Limiting LOCA Case at EPU conditions
- 3. Containment Pressure, Temperature profile for the limiting LOCA case DEHLS break, min SI, 1 CS, 2 CFCs 6.2-172 Amendment No. 26 (11 /13)
TABLE 6.2.6A Containment Pressure and Temperature vs. Time for the Limiting LOCA Case (DEHLS Min SI. 1 CS and 2 CFCs) Time Pressure Temperature (sec) (oF) 0.0 0.8 120.0 0.6 7.6 171.2 1.1 11.7 192.0 2.2 18.7 216.8 3.2 24.0 230.7 4.2 28.5 240.7 6.2 35.4 253.8 7.2 38.0 258.1 8.2 39.9 261.2 9.2 41.2 263.2 9.4 41.4 263.5 9.6 41.5 263.7 9.8 41.6 263.9 10.2 41.8 264.1 11.0 41.7 264.0 18.2 42.8 265.6 20.2 42.7 265.5 30.4 42.4 265.1 40.4 41.9 264.3 50.4 41.4 263.5 60.4 40.9 262.8 80.4 39.7 260.9 100.4 38.7 259.3 150.4 36.8 256.2 200.4 35.5 253.9 300.4 33.2 249.8 400.4 31.1 245.9 499.9 29.6 242.8 608.0 28.4 240.3 6.2-172a Amendment No. 26 (11 /13)
TABLE 6.2-6 (Cont'd) 4. Containment Leakage Rates
- Into shield building from containment vessel Into shield building from outside environment Out of shield building to outside environment Temperature of outside air leaking into annulus, °F Humidity of outside air leaking into annulus 5. Heat Transfer Properties Concrete conductivity, Btu/hr-ft-
°F Concrete heat capacity, Btu/ft 3 -°F Steel conductivity, Btu/hr-ft-
°F Steel heat capacity, Btu/ft 3-°F 6. Heat Transfer Coefficients Containment vapor to steel vessel Steel cylinder to annulus air Steel dome to annulus air Annulus air to concrete cylinder Steel emissivity for radiation Concrete emissivity
- varies linearly with the pressure differentials 6.2-173 0.5% of containment volume per day @ 44 psig 5% of annulus volume per day @ annulus llP of 0.25 in. H20 g negative 5% of annulus volume per day @ annulus llP of 0.25 in. H 2 0 g positive 95 100% 1.0 31.9 25.9 53.57 Figure 6.2-23 GOTHIC Heat Transfer option GOTHIC Heat Transfer option GOTHIC Heat Transfer option 0.79 Btu/hr-ft 2-°F 0.90 Btu/hr-ft 2-°F Amendment No. 26 ( 11 /13)
TABLE 6.2-7 (2) CONTAINMENT STRUCTURE PRESSURE & RADIATION INSTRUMENTATION APPLICATION
Indication Alarm(l) Recording Control Function Instrument Range(3) Normal Operating Range Instrument Accuracy(3) System Parameter & Location Local Control Roo m High Low Containment Atmosphere
- 1. Pressure *
- 1. High pressure signal initiates CIS and SIAS on 2/4 logic 0 2. High-high pressure signal (2/4 logic) combines with SIAS to initiate CSAS
- 2. Radiation * *
- High radiation signal initiates CIS on 2/4 logic
- 3. Negative pressure differential with relation to shield building annulus
- Opens vacuum relief valves FCV-25 -7 & -8 on high negative pressure differential
-0.25 to +3.0 w.g.
(1) All alarms and recordings are in the control room unless otherwise indicated.
(2) Refer to Table 7.3-1 for instrument setpoints. (3) Instrument ranges are selected in accordance with standard engineering practices. Instrument accuracies are selected such that existing instrument loop performance and safety analysis assumptions remain valid. Where applicable, instrument accuracies are also evaluated for their impact on setpoints in accordance with the FPL Setpoint Methodology.
6.2-174 Amendment No. 17 (10/99)
TABLE 6.2-8 DESIGN DATA FOR CONTAINMENT SPRAY SYSTEM COMPONENTS
- 1. Containment Spray Pumps Historical Data -Reflects the Original Pump Procurement Requirements Quantity Type Number of stages Rotational speed, rpm Material Codes Liquid Pumped Temperature Maximum, °F Minimum, °F Pressure, psig Capacity each, gpm Total dynamic head, ft NPSH available calculated, ft NPSH required, ft Temperature transient Connections Discharge, inches Suction, inches 2 Heavy duty vertical centrifugal with mechanical seals (designed to operate at 300°F) backed up by a bushing to collect leakage past the mechanical seals 1780 ASTM A-351, Gr. CF8M (casing), Gr. CF8 (impeller)
Stainless Steel for pressure parts in contact with borated water Motor: NEMA Pump: Standards of the Hydraulic Institute, Draft ASME Nuclear Pump & Valve Code, Nov. 1968, for Class 2 pumps Borated water (concentration 0 to 1720 ppm) 300 40 300 Suction from Refueling Water Tank 2750* 470 See Table 6.2-9A See Table 6.2-9A 40°F to 210°F in 10 seconds 8 12 Suction from Containment SUMP 3425 430 See Table 6.2-9A See Table 6.2-9A *Includes 50 gpm for minimum recirculation flow to refueling water tank. 6.2-175 Amendment No. 26 ( 11 /13)
TABLE 6.2- 2. Mo tor Quantity one per pump Type 500 hp, 4000 volt, 60 Hz, 3 phase induction , 1.15 service factor Insulation Class B Powerhouse Enclosure & Ventilation Drip proof Shaft Solid vertical Coupling Type Spacer 3. Piping, Fittings and Valves
- a. Suction Side (except strainer system)
Material Type 304 or 316 stainless steel Pressure, psig 60 Temperature, F 300 Pipe Sizes 2 in. and smaller Schedule 40 S wall thickness 21/2 in. through 12 in Schedule 10 S or higher wall thickness 14 in. through 24 in.
0.250 in. nominal wall thickness Connections 2 in. and smaller Socket weld 21/2 in. and larger Butt weld Valves 2 in. and smaller Stainless steel, socket weld, 600 lb design 21/2 in. and larger Stainless steels butt weld, wafer, and/or flanged 150 lb design Code ANSI B 31.7 Class II, 1969 Testing as required by ANSI B 31.7, 1969
- b. Discharge Side Material Type 304 or 316 stainless steel Design Pressure, psig 500* Design Temperature, F 300
- Some items upgraded to 550 psig per PCM 01059 6.2-176 Amendment No. 22 (05/07)
TABLE 6.2- Pipe Sizes 6 in. and smaller schedule 40 S or higher wall thickness 8 in. through 12 in.
0.250 in. nominal wall thickness Connection s 2 in. and smaller Socket weld 21/2 in. and larger Butt weld Valves 2 in. and smaller Stainless steel, socket weld 600 lb design 21/2 in. and larger Stainless steel, butt weld, wafer and/or flanged, 300 lb design Code ANSI B 31.7 Class II, 1969 Testing as required by ANSI B 31.7, 1969
- c. Strainer System Material Type 304 stainless steel Pressure, psid
-20 Temperature, F 300 Pipe Sizes 12 in. and 18 in.
Schedule 10 S Connections 12 in. (interconnecting) 18 in. (RDT area)
Qualified clamp couplings Butt weld and flange Code ASME 111/NC
- 4. Spray Nozzles Quantity 178 nozzles per spray header Type hollow cone, whirljet Material Type 304 stainless steel Flow per nozzle, gp m 15.2 Pressure drop, psi 40 when passing 15.2 gpm Spray droplet size, microns 700 (3.93 x 10
-5 in. mean value) 6.2-177 Amendment No. 22 (05/07)
- 5. Containment Spray Pump Flow Orifice Quantity Size Material Design Pressure, psig Design Temperature, °F Pressure Loss Coefficient Train A Train B TABLE 6.2-8 (Cont'd.)
2 12" NPD Type 316/316L stainless steel 550 350 79 77 6.2-177a Amendment No. 26 (11/13)
TABLE 6.2-9 DESIGN DATA FOR CONTAINMENT COOLING SYSTEM COMPONENTS
- 1. Containment Cooling Fans Quantity Type Air flow each, cfm Air mixture density, lb/ft 3 Fan static pressure, in. wg Fan speed, rpm Heat removal capacity each, Btu/hr Air temperature, inleUoutlet, °F Cooling water temperature, inleUoutlet, °F Cooling water flow each, gpm (includes 50 gpm for fan motor) 2. Motor Quantity Type Insulation Enclosure and Ventilation Cooling Water Flow, gpm Code 3. Cooling Coils Tube material Fouling factor Number of coil banks Face area per bank, ft 2 Tube O.D., in. Minimum wall thickness in. Fins per inch Fin Material Coil frame Type 4 centrifugal type, direct-driven, backwardly curved airfoil blades Normal Conditions Post-Accident Conditions*
60,000 58,000 0.0654 0.153 4.0 9.4 596 591 7.9 x 10 5 60 x 10 6 120/103.1 264/260 100/101.8 100/211.8 1200 1200 One per fan 150 hp, 460 volt, 60 Hz, 3 phase induction type, fan-cooled (piped air) with integral air to water heat exchanger Class F Thermolastic epoxy (tested to radiation exposure of 2 x 10 8 RAD) Totally Enclosed 50 NEMA CLASS F, TEAO (piped air) copper 0.001 two banks of 3 coils each 105.8 518 0.049 6 coppery ASME SA-240 UNS S 30400 Plate fin/tube NOTE: Reactor Containment Cooling Coil replacements are procured to ASME Section Ill, Class 2 requirements without 'N' Stamping.
- Note that these values represent conditions specified for procurement purposes.
The actual heat load will vary based on the accident analysis.
6.2-178 Amendment No. 26 (11 /13)
Pages 6.2-182 through 6.2-188 have been deleted.6.2-181Amendment No. 16, (1/98)
TABLE 6.2-10SINGLE FAILURE ANALYSIS - CONTAINMENT HEAT REMOVAL SYSTEMComponentIdentificationAnd QuantityFailureEffect on SystemMethod DetectionMonitorRemarksContainment spraypump(2)Fails to startLoss of one spray subsystem.Pump start failure/ CSAS override
& pump motor overload alarm/ trip.
CRIOne spray subsystem remains operablesupplemented by system.Shutdown HX (2)Loss ofshell- sidecoolingLoss of onerecirculation modesubsystem.Containment spray water hightemperature indication & CCW HXshellside outlet low flow alarm.
CRIOne recirculation modesubsystem remainsoperable supplemented by the containment cooling system.Spray Line Flow control valve I-FCV-07-1A/B(pneumatic) (2)Loses air supplyNo effect on system -
fail open valves.Full flow indication upstream of valve & valve position indicating lights CRIFails to openLoss of one spray subsystemNo flow indication upstream of valve & valve position indicatinglights CRIOne spray subsystemremains operablesupplemented bycontainment cooling systemSpray header check valve V07193 or V07192Fails to openLoss of one spray subsystemNo flow indication upstream of valve.CRIOne spray subsystem remains operable supplemented by containment cooling system.Spray nozzles (178) per subsystemCloggedClogging of up to 10% of the nozzles can be toleratedbefore the spray flowwould decrease measurably.Low flow indicationCRIThe spray nozzles are of the open throat design and clogging of asignificant number isimprobable. One spray subsystem remains operable supplemented bycontainment coolingsystem.6.2-189Amendment No. 17 (10/99)
TABLE 6.2-12CONTAINMENT COOLING SYSTEM INSTRUMENATION APPLICATIONIndicationAlarm(l)System Parameter & LocationLocalControlRoomHighLow (1)RecordingControl FunctionInstrumentRange(3)NormalOperatingRangeInstrumentAccuracy (3)Cooling Unit Air (2)105-120 F1.Flow temperature
- 2.Fan discharge flow
- 60,000(1)All alarms & recordings are in the control room unless otherwise indicated.(2)Cooling water instrumentation is contained in Table 9.2-4.
(3)Instrument ranges are selected in accordance with standard engineering practices. Instrument accuracies are selected such that existinginstrument loop performance and safety analysis assumptions remain valid. Where applicable, instrument accuracies are also evaluated fortheir impact on setpoints in accordance with the FPL Setpoint Methodology.6.2-192Amendment No. 17 (10/99)
TABLE 6.2-13DESIGN DATA FOR SHIELD BUILDING VENTILATION SYSTEM COMPONENTS1.SBVS FansQuantity2, one per filter trainTypeCentrifugal type, direct-driven with airfoil bladesMaterialASTM - A36, carbon steelActual air flow @ inlet, per fan, cfm6000 nominalAir density, lb/ft 30.075Static pressure, in. wg 21Fan performance, eachCapacity (cfm)Static Pressure (in.wg)6,000 216,500 20.56,750 19.47,500 17.88,500 15.8 CodeAir Moving and Conditioning Association (AMCA), Anti-Friction BearingManufacturer's Association (AFBMA)2. MotorsQuantity2, one per fanType60 hp, 480 volt, 60 Hz, 3 phase horizontal induction typeInsulationClass B (Minimum)Enclosure ventilationDripproof CodeNEMA Class B3. Demister CellsQuantity12, 6 per filter trainAir flow, cfm 6000Face velocity, fpm250Cell size24 in. high, 24 in. wide, 2 in. deep6.2-193Amendment No. 18, (04/01)
TABLE 6.2-13 (Cont'd.)Bulk density (bone dry), lb/ft 328 to 30Loading capacity6000 gm of stable iodine and 360 gm of radioactive iodineincluding 300 grams of CH 3 INominal charge/cell, lb 46Particle size distribution8 thru 14 meshCell size24 in. wide, 8 in. high, 30 in. deepCell arrangement2 wide x 9 highBed thickness, in. nominal 2Quantity36, 18 per filter trainAir flow, cfm 6000Efficiency99.9 percent minimum of iodides with 5 percent in the form of methyl iodide, CH 3I, when operating at 70 percentrelative humidity and 150 FMax. air resistance, in. wg 1.15Nondestructive testUSAEC Report DP-1082 ANSI N510-1975ASTM D3803-19897. DuctsMaterialGalvanized sheet metal, ASTM Specification A-525, Class E8. HeatersQuantity4, 2 per filter trainType30 KW, 480 volt, 60 HZ, 3 phase /1.5 KW, 480 volt, 60 HZ, 3 phaseAir Flow-cfm6000/300Air Temperature difference, F 156.2-195Amendment No. 18, (04/01)
TABLE 6.2-13A (Cont'd.)RegulatoryPosition ItemShield BuildingVentilation SystemECCS Area ExhaustSystemControl RoomHVAC SystemHydrogen Control System (1)(hydrogen purge andrecombiner systems)2iAll systems comply with regulatory position. No filter bypasses are provided.2jBecause of the length of the filter trains in these systems (24-40 ft) some amount of disassembly will be needed for maintenance and replacement.2k-1All systems comply with regulatory position.3aAll systems comply with regulatory position except that demister wires are stainless steel, which is adequately corrosion resistant, and not Teflon covered.3bRefer to Section 6.2.3 for a discussionof shield building ventilation systemNo electric heaters are provided in the ECCS, hydrogen purgesystem of the control ventilation system.3c-dAll systems comply with regulatory position.3eThe height of the filter in this system is 8 feet 3inches instead of 7 feet.System complies with regulatory position.System complies with regulatory position.System complies with regulatory position.3f-gAll systems comply with regulatory position.3hAll painted carbon steel surfaces are either blasted clean in accordance with Steel Structure Painting Council (SSPC) surface preparation specification No.-SP-10, "Near White Blast Cleaning" or pickled in accordance with SSPC specification N-8. "Pickling". If the steel is pickled, the shop coat of paint isapplied while the steel plate is still warm, but not before it has completely dried. If the steel is blasted, the shop coat is applied within eight hours of blast cleaning. The shop coat is one coat of Carbon Zinc 11, 3 mil dry film thickness, applied in accordance with the manufacturer's specifications.6.2-197Amendment No. 19 (10/02)
TABLE 6.2-13A (Cont'd.)RegulatoryPosition ItemShield BuildingVentilation SystemECCS Area ExhaustSystemControl RoomHVAC SystemHydrogen Control System (1)(hydrogen purge andrecombiner system)3iAll systems comply with regulatory positions.Report No.CarbonLoadingWithout Breakthrough(MG/G)Elemental Iodine:DP 778 BC 4166.04ORNL-7N-2040MSA 8585166ORNL-7M-2040 BC 72764Methyl Iodide:ORNL 4040MSA 858513.5ORNL 4040 BC 72716ORNL 4180NACAR G6015.23jSystem design does not include water sprays.System design includes provisions for preventing adsorber fires by ensuring continued cooling of adsorbers by air flow even in the event of a singlefailure. This is accomplished by providing cross connections between redundant fans and filter trains. See Section 6.2.3.3.1 for a more detaileddiscussion of decay heat removal from filter adsorbers.3k-nAll systems comply with regulatory position.4aAll systems comply with regulatory position.4bSee part 3e for a discussion of this regulatoryposition.System complies withregulatory position.System complies with regulatory position.System complies with regulatory position.4cSystem design does Therefore, door vacuumbreakers are not required not include vacuumbreakers.Filter casings are seldom, if ever, entered while the fan is in operation.System complies with regulatory position.System complies with regulatory position.4dThe regulatory position has not beenmet in all sections of this system.System complies with regulatory position.System complies with regulatory position.System complies with regulatory position.4e-mAll systems comply with regulatory position.6.2-198Amendment No. 19 (10/02)
TABLE 6.2-13A (Cont'd.)RegulatoryPosition ItemShield BuildingVentilation SystemECCS Area ExhaustSystemControl RoomHVAC SystemHydrogen Control System (1)(hydrogen purge andrecombiner system)5aAll systems comply with regulatory position.5bAll systems comply with regulatory position except that the in-place HEPA DOP test conforms to ANSI N 510-1975 which exceeds the requirements ofANSI N101.-1972, and periodic testing is in accordance with the plant Technical Specifications.5cAll systems comply with regulatory position except that activated carbon adsorber sections are tested in accordance with ANSI N 510-1975 instead ofUSAEC Report DP-1082, and periodic testing is in accordance with the plant Technical Specifications.Notes:(1)This system is listed for information only. The hydrogen purge system is not credited as an ESF atmosphere clean-up system andtesting in accordance with RG 1.52 is not required. Testing is performed in accordance with plant procedures.6.2-199Amendment No. 19 (10/02)
TABLE 6.2-14 SINGLE FAILURE ANALYSIS - SHIELD BUILDING VENTILATION SYSTEMComponentIdentificationand QuantityFailure ModeEffect on SystemMethod ofDetectionMonitorRemarksDamper downstream of fan(2)Fails to openLoss of one fan & filtersubsystemLow air flow alarm down-stream of fanCRIOne 100% capacityfan & filter subsystem operable.Filter train (2)ClogsLoss of one fan & filtersubsystemLow air flow alarm down-stream of fanCRIOne 100% capacityfan & filter subsystem operable.Outside cooling air valve (2)Fails to openSub-system will operatesatisfactorily untilcharcoal adsorbertemperature reaches 300F.High temperature alarm on charcoal adsorbersCRIOne 100% capacityfan & filter subsystemoperable.Fan (2)FailsLoss of one fan & filtersubsystemLow air flow alarm down-stream of fanCRIOne 100% capacityfan & filter subsystem operable.Diesel generator set (2)Fails to startLoss of one fan & filtersubsystemDiesel generatormalfunction alarmCRIOne 100% capacityfan & filter subsystemoperable.CRI-Control Room Indication 6.2-200
TABLE 6.2-16 CONTAINMENT PENETRATION AND ISOLATION VALVE INFORMATION tration Number 1 & 2 5&6 10 11 Main Steam Feedwater Auxiliary Feedwater Steam Generator Blowdown Primary Makeup Water Station Alf Supply Instrument Air Supply Containment Purge Air Exhaust Containment Purge Supply 12.13 Spare 14 15. 17 19. 21 Nitrogen Supply to Reactor Containment Building Containment Fan Coolers Cooling Water Return Essential Q'.J. x x x Main Steam Feedwater Auxil!ary Feedwater Slowdown Makeup Water Station Air Instrument Air Heating & Ventilating Heating & Ventilating Waste Management Component Cooling tration Ill tion c c c A1 A2 A1 A1 A1 A1 c c c c c c c c Flow tion Out In In In In In In In In Out In In In Out In In Out Out Out Out Out Out Out Out Location Reference to Containment Vessel Outside Outside Outside Outside Outside Outside Outside Outside Outside Outside Outside Inside Outside Outside Outside Outside Inside Outside Inside Outside Inside Outside Outside Outside Outside Outside Outside Outside Outside Outside Outside Valve Type and Tag Number Stop (HCV-08-1A.B}
Gate (HCV-09-7,8)
Gate (MV-09-1.2) 131 Check (V09280) Check (V09248) Check (V09135) Check (V09119) Check (V09157) Check (V09151) Globe (FCV-23-3,5)
Check (V15326) Check (V15328) Gate (MV-15-1) 11°' Globe (V18794) 1'°1 Globe (V18796) 11°' Gate (MV-18-1) 110' Check (V18195) Butterfly (FCV-25-5) 1101 Butterfly (FCV-25-4) 11°' Butterfly (FCV-25-2) 1101 Butterfly (FCV-25-3) 1101 Globe (V6741) 1'°1 Check (V6779) Butterfly (MV-14-7)
Butterfly (SB14344)
Butterfly (SB14520)
Butterfly (SB14331)
Butterfly (MV-14-8)
Butterfly (SB14518)
Butterfly (SB14320)
Butterfly (SB 14309) (1) When unit is in MODE 6, valve operability is required.
However, closure time limits are not applicable.
(2) At main steam operating pressure with equalizing valve closed. (3) Isolation function is provided to terminate main feedwater flow additions.
not for containment isolation.
(10) Valve covered by Technical Specification 3/4.6.3. (11) Valves not operated in Modes 1 through 4. 6.2-202 Pipe Size 34" 20" 20" 20" 20" 4" 4" 4" 4" 2" 2" 2" 2" 48" 48" 1" 8" 6" 8" 6" Primary Method of Closure MSIS SIAS SIAS, MSIS Automatic Automatic Automatic Automatic Automatic Automatic CIS Automatic Automatic CIS Manual Manual CIS Automatic CIS(111 C!S(11) CIS(11 l CIS Automatic Manua! Manual Manual Manual Manual Manual Manual Manual CIS Actuation Channel A B A A B B A B Secondary Method of Closure Gas Accumulator Maximum Closure Time (Sec) 6 Local Manual 20 Handwheel 60 Handwheel Handwheel Handwheel Handwheel Handwheel Handwheel Handwheel Handwheel Handwheel 10 19 28 Iii Iii 111 "' Normal Valve Posltlon Open Open Open Open Closed Locked Closed Locked Closed Open Closed Closed Closed Closed Closed Open Open Closed Open Open Closed Open Open Valve Position with Power Failure Open(2 l As Is As Is Closed As Is As Is Closed Closed Closed Closed Closed As Is As Is Closed As Is As Is Closed As Is As Is Amendment No. 26 (11/13) Accident Position Closed Closed Closed Closed Closed Closed Closed Closed Closed Closed Closed Closed Closed Open Open Closed Open Open Closed Open Open
TABLE 6.2-16 (Cont'd) Location Maximum Valve Pene-Essential Pene-Isola-Flow Reference to Valve Type and Pipe Primary CIS Secondary Closure Normal Position Post-tration Service System System tration ti on Di rec-Containment Tag Number Size Method of Actuation Method of Time Valve with Accident Number Q<J. 1= Class t1on Vessel Closure Channel Closure Position Power Position Fallure 57 Hydrogen Purge Filter x Containment H&V A1 Out Outside Ball (FCV-25-20) 3" CIS A Handwheel 30 Closed Closed Closed Train Hydrogen Purge Outside Ball (FCV-25-21) 3" CIS B Handwheel 30 Closed Closed Closed (H&V) Containment 58 Hydrogen Purge Hydrogen H&V A2 Out Outside Gate (V25015) 1'°1 3" Manual Locked Exhaust Purge Closed Closed (H&V) Outside Gate (V-25-14,16)
"°' Manual Locked Closed Closed 59&60 Do Not Penetrate Containment Vessel 61to63 Do Not Penetrate Containment Vessel 64 Refer to penetration No. 40 65 &66 Do Not Penetrate Containment Vessel 67 &68 Containment Vacuum x A1 In Inside Check (V-25-20,21) 24" Automatic Outside Butterfly (FCV-25-7.8) <'O) 24" Closed Closed Closed (1 O) Valve covered by Technical Specification 3/4.6.3. 6.2-206 Amendment No. 26 (11 /13)
TABLE 6.2-18 SINGLE FAILURE ANALYSIS -HYDROGEN CONTROL AND SAMPLING SYSTEM Component Method of Identification and Failure Mode Effect on System Detection Quantit Recombiner Fails Temporary loss of (1) hydrogen recombining capacity-recombiner can be repaired and returned into service Air flow inlet valves Fails to open Loss of use of filter train FCV-25-20
& FCV-25-21
-air flow may be (remote manual) or established to fans by FCV-25-9 opening bypass valves V25015 & V-25-16 Filter train Clogs Loss of use of filter train-Low flow alarm air flow may be established to fans by opening bypass valves V25015 & V-25-16 Exhaust Fans Fails to operate Loss of one hydrogen Low flow alarm purge fan-alternate must be started to reestablish air flow Valve to plant vent Fails One analyzer out of System failure V-25-17 (manual)11 l service alarm (1) System initiation and operation is manual and under direct administrative control. (2) Instrumentation is local to enable personnel to immediately detect equipment malfunction.
(3) Alarms and monitors in control room. 6.2-211 Monitor (1) (3) CRI CRI (3) Remarks Second recombiner available.
Hydrogen purge system available as backup. Filter train will be bypassed & air flow exhausted to shield building ventilation system. Filter train will be bypassed & air flow exhausted to shield building ventilation system. Hydrogen purge fans are redundant
& 100% capacity Redundant analyzer is available and alternate grab sample method is available Amendment No. 26 (11 /13)
TABLE 6.2-19 COMPARISON OF MHA HYDROGEN GENERATION ASSUMPTIONS AEC Safety Guide 7 Model Assumptions Applicant Model Assumptions
- 1. Fraction of 53,500 pounds of Zirconium Alloy that reacts (total Zr in core) 0.05 0.02 2. Fraction of core gammas absorbed in coolant 0.10 0.0328 3. Fraction of core betas absorbed in coolant 0.0 0.0 4. Fraction of released beta and gamma intimately mixed with coolant that are absorbed 1.0 1.0 5. G(H 2) in-core 0.5 mol/100 e.v.
0.45 mol/100 e.v. 6. G(H 2) out-of-core 0.5 mol/100 e.v.
0.45 mol/100 e.v.
- 7. Fission products released from core 100% of the noble gasses 100% of the noble gasses 50% of the halogens 50% of the halogens 1% of the solids 1% of the solids
- 8. Corrosion of metals 180,000 ft 2 of galvanized surface are with temperature dependent corrosion rate.
180,000 ft 2 of galvanized surface are with temperature dependent corrosion rate.
UNIT 1 6.2-212 Amendment No. 27 (04/15)
TABLE 6.2-21 CONTAINMENT HYDROGEN PURGE & SAMPLING SYSTEM INSTRUMENTATION Indication Control Alarm\1 J Recording(1) Control Instrument Normal Instrument System Parameter
& Location Local Room High Low Function Range(3) Operating Accurac/3)
RanQe Hydrogen Purge System 1) Flow rate * ---2) Purge gas temperature downstream of *
- 120°F demister 3) Purge gas temperature upstream of HEPA
- 120°F filters 4) Moisture element downstream of HEPA filter *
- 50-85% 5) Charcoal adsorbers temperature
- 120°F 6) Purge gas temperature downstream of *
- 120°F charcoal adsorbers Sampling System Sampling flow rate * * *(1) ---(2) ---Calibration gas pressure *(1) ---(2) ---Sample hydrogen concentration * * *
- Sample or hot box temperature
- (1) ---(2) ---Main Power Failure *(1) ------Analyzer Cell Failure *(1) ---(2) ---(1) All alarms & recordings are in the control room unless otherwise indicated.
(2) Local alarm and/or recording.
(3) Instrument ranges are selected in accordance with standard engineering practices.
Instrument accuracies are selected such that existing instrument loop performance and safety analysis assumptions remain valid. Where applicable, instrument accuracies are also evaluated for their impact on setpoints in accordance with the FPL Setpoint Methodology.
6.2-214 Amendment No. 26 (11/13)
TABLE 6.2-22 (Cont'd.)
Droplet Size, Volume mean diameter 763 microns Flow, power nozzle 15.2 gpm (40 psi drop) Spray Velocity 32.5 ft/sec Nozzle Diameter 0.438 in. Spray Solution at Spray Nozzles Composition 1540 to 2640 ppm boron,0.23 to 0.61 WT% NaOH pH 11.0 maximum Recirculating Solution Composition 1540 to 2600 ppm boron,0.23 to 0.41 WT% NaOH(4) pH 8.5-11.0 Containment Volume (Free), ft 3 2.5 x 10 6 Diameter, ft 140 Refueling Water Requirements Minimum Usable Volume, gallons 411,260 Maximum Volume, gallons(3 l 458,800 8. Iodine Removal Rate Constant Calculation Parameter (SJ a. Gas Film mass transfer coefficient:
- b. Liquid Film mass transfer coefficient
- c. Iodine Partition:
H d. Droplet mean fall height: h, ft e. Spray Flow Rate: F, gpm f. Net containment free volume, V, ft 3 g. Droplet diameter:
D fi h. Spray droplet terminal velocity:
U, -*----sec 6.2-216 Kg, cm 16 .4 sec k cm 50000 /.' sec 6.58xl0-4 140 2550 2.445x10" 700 9.23 Amendment No. 26 (11 /13)
TABLE 6.2-22 (Cont'd.)
- i. Particulate iodine adsorption efficiency of the spray droplet (2): E 0.0015 (1) This table covers both removal trains. (2) Eis taken as the minimum value observed in CSE Tests. (3) Total tank volume less the 66,200 gallons below the RAS setpoint.
(4) When NaOH addition extends to the recirculation mode, the spray composition changes to 0.68 to 1.21 WT% Na OH. (5) Iodine removal rates have been reassessed consistent with the guidance provided in RG 1.183 as discussed in UFSAR Section 15.4.1.5.
6.2-217 Amendment No. 26 (11/13)
- * ---Core Supj)Ort t:ln:cl Inlet f 3
- Outlet 24 /loz. z le a Fuel Alicncent
-__
/_r1acc lf-l. s 1
- J-----. ----?' --*I n 6 *, ,---
19 f 1a Shield I I flov Skirt Fuel Asscr.tbly Lowc:n: Plenum ""Upper End i'ittinz *Lower End Fitting Core Sur?ort Plate Core Support Barrel Bot tom ?late FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT l REACTOR PRESSURE 1*1cunt 6.2-1 en *;;; (]) 5 V> V> (]) a: 40 30 25 20 15 -St. Lucie 1 LOCA Containment Analysis Pressure vs Time DEHLS, Min SI (Peak Pressure Response Case) 10 **--*-*-****** -****-***-*-********-
- ---****-... 5 1 E-01 lE+OO lE+Ol 1E+02 1E+03 Time (sec) 1E+04 1E+05 1E+06 Amendment No. 26 (11/13) 1E+07 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 LOCA CONTAINMENT ANALYSIS PRESSURE VS TIME DEHLS, MIN SI FIGURE 6.2-1A St. Lucie 1 LOCA Containment Analysis Temperature vs nme DEDLS, Min SI (long Term Temperature Response Case} 300 250 200 I / v 100 50 0 lE-01 lE+-00 J lE+OT --------1E+02 1E+03 Time(sec)
"' \ TE+-04 1 E+-05 lE+-06 Amendment No. 26 (11 /13) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 LOCA CONTAINMENT ANALYSIS TEMPERATURE VS TIME DEDLS, MIN SI FIGURE 6.2-1 B 1E+o7 0 N 0 0 0 0 0 0 6 0 0 q 0 0 0 0 0 ()\ <lJ E f= Amendment No. 26 (11/13) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 COMPONENT COOLING WATER ANALYSIS CCWHX OUTLET TEMPERATURE VS TIME DEHLS, MIN SI FIGURE 6.2-1C
- *
- DELETED AMENDMENT NO. 12 (12/93) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 ENERGY DISTRIBUTION IN CONTAINMENT VS. TIME FOR 9.82 rr2 DOUBLE ENDED SUCTION LEG BREAK FIGURE 6.2-1 D
- *
- DELETED AMENDMENT NO. 12 (12/93) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 ENERGY DISTRIBUTION IN CONTAINMENT STRUCTURES VS. TIME FOR 9.82 n2 DOUBLE ENDED SUCTION LEG BREAK FIGURE 6.2-1 E
- *
- DELETED AMENDMENT NO. 12 ( 12/93) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 HEAT TRANSFER COEFFICIENT FOR STEEL VS. TIME FOR ALL COLD LEG BREAK SIZES FIGURE 6.2-1 F
- *
- DELETED AMENDMENT NO. 12 (12/93) DOUBLE-ENDED DISCHARGE LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT PRESSURE VS. TIME FOR 9.82 FT2 GUILLOTINE BREAK FIGURE 6.2-2A
- *
- DELETED AMENDMENT NO. 12 (12/93) DOUBLE-ENDED DISCHARGE LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT VAPOR PRESSURE VS. TIME FOR 9.82 n2 FIGURE 6.2-28
- *
- DELETED AMENDMENT NO. 12 (12/93) DOUBLE-ENDED DISCHARGE LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT ATMOSPHERE
& SUMP WATER TEMPERATURES VS. TIME FOR 9.82 FT 2 GUILLOTINE BREAK FIGURE 6.2-2C
- *
- DELETED DOUBLE-ENDED DISCHARGE LEG AMENDMENT NO. 12 (12/93) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT PRESSURE VS. TIME FOR 7.86 FT2 GUILLOTINE BREAK FIGURE 6.2-3A
- *
- DELETED AMENDMENT NO. 12 (12/93) DOUBLE-ENDED DISCHARGE LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT VAPOR PRESSURE VS. TIME FOR 7.86 FT2 GUILLOTINE BREAK FIGURE 6.2-38
- *
- DELETED AMENDMENT NO. 12 (12/93) DOUBLE-ENDED DISCHARGE LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT ATMOSPHERE
& SUMP WATER TEMPERATURES VS. TIME FOR 7.86 FT2 GUILLOTINE BREAK FIGURE 6.2-3C
- *
- DELETED AMENDMENT NO. 12 (12/93) DOUBLE-ENDED SUCTION LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT PRESSURE VS. TIME FOR 5.89 FT 2 SLOT BREAK FIGURE 6.2-4A
- *
- DELETED DOUBLE-ENDED SUCTION LEG AMENDMENT NO. 12 (12/93) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT VAPOR PRESSURE VS. TIME FOR 5.89 n2 SLOT BREAK FIGURE 6.2-48
- *
- DELETED AMENDMENT NO. 12 (12/93) DOUBLE-ENDED SUCTION LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT ATMOSPHERE
& SUMP WATER TEMPERATURES VS. TIME FOR 5.89 FT2 SLOT BREAK FIGURE 6.2-4C
- *
- DELETED AMENDMENT NO. 12 (12/93) DOUBLE -ENDED DISCHARGE LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT PRESSURE VS. TIME FOR 5.89 FT 2 GUILLOTINE BREAK FIGURE 6.2-SA
- *
- DELETED AMENDMENT NO. 12 ( 12/93) DOUBLE-ENDED DISCHARGE LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT VAPOR PRESSURE VS. TIME FOR 5.89 n2 GUILLOTINE BREAK FIGURE 6.2-58
- *
- DELETED AMENDMENT NO. 12 (12/93) DOUBLE-ENDED DISCHARGE LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT ATMOSPHERE
& SUMP WATER TEMPERATURES VS. TIME FOR 5.89 n2 GUILLOTINE BREAK FIGURE 6.2-5C
- *
- DELETED AMENDMENT NO. 12 (12/93) DISCHARGE LEG SLOT BREAK FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT PRESSURE VS. TIME F"OR 3.0 FT2 SLOT BREAK FIGURE 6.2-6A
- *
- DELETED AMENDMENT NO. 12 ( 12/93) DISCHARGE LEG SLOT BREAK FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT VAPOR PRESSURE VS. TIME FOR 3.0 FT2 SLOT BREAK FIGURE 6.2-68
- *
- DELETED AMENDMENT NO. 12 ( 12/93) DISCHARGE LEG SLOT BREAK FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT ATMOSPHERE
& SUMP WATER TEMPERATURES VS. TIME FOR 3.0 FT2 SLOT BREAK FIGURE 6.2-6C
- *
- DELETED AMENDMENT NO. 12 (12/93) DOUBLE-ENDED HOT LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT PRESSURE VS. TIME FOR 19.2 n2 SLOT BREAK FIGURE 6.2-7 A
- *
- DELETED AMENDMENT NO. 12 ( 12/93) DOUBLE-ENDED HOT LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT ATMOSPHERE
& SUMP WATER TEMPERATURES VS. TIME FOR 19.2 FT2 SLOT BREAK FIGURE 6.2-78
- *
- DELETED AMENDMENT NO. 12 (12/93) SINGLE-ENDED HOT LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT PRESSURE VS. TIME FOR 9.62 FT2 SLOT BREAK FIGURE 6.2-8A
- *
- DELETED AMENDMENT NO. 12 (12/93) SINGLE-ENDED HOT LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT ATMOSPHERE
& SUMP WATER TEMPERATURES VS. TIME FOR 9.62 n2 SLOT BREAK FIGURE 6.2-88
- *
- DELETED AMENDMENT NO. 12 ( 12/93) HOT LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT PRESSURE VS. TIME FOR 5.0 n2 SLOT BREAK FIGURE 6.2-9A
- *
- DELETED AMENDMENT NO. 12 ( 12/93) HOT LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT ATMOSPHERE
& SUMP WATER TEMPERATURES VS. TIME FOR 5.0 FT2 SLOT BREAK FIGURE 6.2-98
- *
- DELETED AMENDMENT NO. 12 ( 12/93) HOT LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT PRESSURE VS. TIME FOR 2.0 n2 SLOT BREAK FIGURE 6.2-1 OA
- *
- DELETED AMENDMENT NO. 12 (12/93) HOT LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT ATMOSPHERE
& SUMP WATER TEMPERATURES VS. TIME FOR 2.0 FT2 SLOT BREAK FIGURE 6.2-1 OB
- *
- DELETED AMENDMENT NO. 12 (12/93) HOT LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTAINMENT PRESSURE VS. TIME FOR 0.5 n2 SLOT BREAK FIGURE 6.2-11 A
- *
- DELETED AMENDMENT NO. 12 ( 12/93) HOT LEG FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT -UNIT 1 CONTMNMENT ATMOSPHERE
& SUMP WATER TEMPERATURES VS. TIME FOR 0.5 FT2 SLOT BREAK FIGURE 6.2-11 B 45 40 35 30 25 "' E: II.I ..... ::l "' "' 20 a.. 15 10 5 0 0 Containment Pressure Response 100.3% Power Limiting Peak Pressure Case Steamline Break r" \.__ I I I I I I I I 50 100 '-......_ -------150 Time(sec) 200 250 Amendment No. 26 (11 /13) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 300 CONTAINMENT PRESSURE RESPONSE 100.3% POWER LIMITING PEAK PRESSURE CASE STEAMLINE BREAK FIGURE 6.2-12 0 0 N 0 (JI ...-0 ..... ...-0 0 <II I.ti VI ...-Ill 0 u "¢ CIJ QJ "' ,__ ...-c: :J 0 0 ..... M ...-Ill <II CIJ n. 0 ._ ru ro 0 :l 1-(LI ...... ..:.:: .... ...-u e IQ CD ) QJ cu 4l v a.a. c 8 / cu E rn= ...-.!;; E 0 ra JV 0\ 'EE!!! Cl.I :::i Vl 0 E ,_ ( CD c <II *-0 !9 0 I ,.... c: Q. 0 m '° ci \ 0 0 ..... \ "' 0 \ ... 0 .., M "" 0 "' N I'.... 0 ........ r----t--0 0 8 0 8 0 8 0 8 0 0 I.ti I.ti ll'l I.ti Lt'I "" "" .... m N N ...-(:Jc) ilJrlll"Jacfwa,LlUaillU!l":J-UOJ Amendment No. 26 (11 /13) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 CONTAINMENT TEMPERATURE RESPONSE 100.3% POWER LIMITING PEAK TEMPERATURE CASE STEAMLINE BREAK FIGURE 6.2-13 DELETEDAmendment No. 18, (04/01)FLORIDA POWER & LIGHT COMPANYST. LUCIE PLAN UNIT 1CONTAINMENT PRESSURE VS. TIMEFOR A 105% POWER (2698 MWT) 85%BREAK AREA (5.355 FT
- 2) STEAMLINE BREAKFIGURE 6.2-14
- NOTES: 1. VIEW FROM RPV NOZZLE TOWA.RDS PRIMARY SlilELD WALL 2. ltlSULATION IS IGNORED l. NOT TO SCALE
- CROSS SECTION OF PIPE END HAVING lUERAL DISF'lACEMEtlT CROSS SECTIOHAL AREA OF PIPE AH ACHED TO RPV CRESC:EHT AREA PRIMARY SHIELD WALL
- FLORIDA POWER & LIGHT COMPANY St. Lucie Plant AREA Of FLOW GUILLOT IN( BREAK or RlACTOR COOLANT P!Pl INTO REACTOR CAVITY FIGURE 6.2-IS
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Amendment No. 26 (11/13) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 REACTOR CAVITY MODEL FIGURE 6.2-17B (Historical)
J76 J15 V36 V34 REl.IEF DA."'!PERS J65 V35 J66 Amendment No. 26 (11/13) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 RELIEF DAMPERS MODEL FIGURE 6.2-17C (Historical) ltUl,lif.lTIOM TillCl(Hfil
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Amendment No. 26 (11 /13) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 REACTOR CAVITY PLAN AND SECTIONS FIGURE 6.2-17E (Historical)
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G Q I ..c u 4 2 ,§, 0 "' QJ i ! ' )---L. **-. -2 i -!--6 0 100 200 300 Time (sec) 400 500 Amendment No. 26 (11/13) FLORIDA POWER & LIGHT COMPANY ST LUCIE PLANT UNIT 1 SHIELD BUILDING ANNULUS PRESSURE TRANSIENT FOR THE LIMITING LOCA CASE (DEHLS) FIGURE 6.2-22A 10 100 Time (sec) 1000 Amendment No. 26 (11/13) FLORIDA POWER & LIGHT COMPANY ST LUCIE PLANT UNIT 1 CONDENSING HEAT TRANSFER COEFFICIENT VS TIME FOR THE LIMITING LOCA CASE (DEHLS) FIGURE 6.2-23 u:-2... 2: :::J 160 150 140 '§ 130 <lJ Q. E <lJ 1-120 110 100 / 0 / ------100 200 Time (sec) ----------300 I 400 500 Amendment No. 26 (11 /13) FLORIDA POWER & LIGHT COMPANY ST LUCIE PLANT UNIT 1 SHIELD BUILDING ANNULUS TEMPERATURE TRANSIENT FOR THE LIMITING LOCA CASE (DEHLS) FIGURE 6.2-24 DELETED Amendment No. 26 (11 /13) FLORIDA POWER & LIGHT COMPANY ST LUCIE PLANT UNIT 1 ANNULUS STEAM PRESSURES VS TIME FOR A 9.82 FT 2 DOUBLE-ENDED SUCTION LEG BREAK FIGURE 6.2-25 DELETED Amendment No. 26 (11 /13) FLORIDA POWER & LIGHT COMPANY ST LUCIE PLANT UNIT 1 SHIELD BUILDING ANNULUS AND CONTAINMENT PRESSURE VS TIME FOR A 2.04 FT 2 BREAK AREA FIGURE 6.2-26
"' "' 0 .,,, Ul 0.. "' 0 * . 1rP * *,o* 10 4 TIHE, SEC * .FLORIDA POWER & LlliHl COMPANY ST. LUCIE PUNT UNIT l COtfTAlllMfHT PRWU-kE-VS.
lllAE roR J.04 FtJ OQ(AIC WITH ()NL y 'SPRAY 0114 FIGURE U-17 . _.._.__,_ff
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PLANT tJNJ:T 1 FLOW DIAGRAM CONTAINMENT SPRAY AND REFUELING WATER SYSTEMS FIGURE 6.2-28 Amendment No. 16, (1/98)
- 600 470 430 oeo1*1 t:: w *t.' 300 ... Q <C w 200 :r ..J <C .... 0 100 .... 0 1000 2000 3000 4000 FLOW (GALLONS PER MINUTE! 100°* t-------;
130 2750' 3515' n 74 JC so "° JO 20 10 0 5000 'INCLUDES 50GP"1 MIHIFLOW
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120 160 200 240 280 CAPACITY, 100 CFM 320 380 FLORIDA POWER !. LIGHT COMPANY St. Lucie Plant SHIELD BUILDING VENTILATION SYSTEM FAN CHARACTERISTICS FIGURE 6.2-32
- 19 17 15 -13 LL q-* 0 11 -z 0 j:: 9 <( cc w z w 7 (!) N ::c 5 3 1 0 0
- ST LUCIE NO. 1 REANALYSIS OF H2*GENERATION (TEMPERATURE HISTORY FROM FIG 6.2*6) TOTAL H 2 TOTAL H2 WITH RECOMBINER 3.5% VOL *-*-*-*-*---*--* ---*-coNCENTRATION RADIOLYSIS ZINC -* -*-*-. INSTANTANEOUS ( Zr*H20l ----*-*-*
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Zr-BASE PAINT 4 6 8 10 12 TIME DAYS 14 16 18 20 FLORIDA POWER & LIGHT COMP ANY ST. LUCIE PLANT UNIT 1 TOTAL HYDROGEN PRODUCTION REANALYSIS RESULTS INCLUDING NAOH SPRAYS; ZINC BASE PAINT & OTHERS FIGURE 6.2*33a
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- FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT I TOTAL RADIOLYTIC HYDROGEN PRODUCTION APPLICANT MODEL FIGURE 6.2*34
- 100 , I, ... I .. . I.' i 1 I , , I 200
- I. 300 TIME AFTER MHA, DAYS ** j.
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- TIME AFTER MHA, DAYS
- FLORIDA POW[R & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 TOT AL HYDROGEN PRODUCTION (REFERENCE CASE) -APPLICANT MODEL FIGURE 6.2-36
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-APPLICANT MODEL FIGURE 6.2-37
- 100 200 300 TIME AFTER MHA, DAYS 400
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-**-. 60 80 TIME (HRS) r ----' . -----------------t--r--I I ' 100 120 uo 160 i I ------1 I FLORIDA POWER & LIGHT COMPANY St. Lucie Plant SBVS CHARCOAL DECAY HEATING vs_ TIME FOLLOWING DBA FIGURE 6.2-41
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- DESI GM COOLING A.IR FLOW . -' fil.t] 300 400 soo* AIR FLOW (CFM) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UN IT i SBVS CHARCOAL ADSORBER AIR TEMPERATURE RISE AT TIME OF MAXIMUM DELAY HEATING FOLLOWING OBA VS. COOLING AIR FLOW -FIGURE 6.2-42
- *
- EXHAUST . COOLING AIR FLOW ORIFICE ELECTRIC HEATER INTAKE FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 ELECTRIC HYDROGEN RECOMBINER OJTAWAY FIGURE 6. 2-45A
- *
- STEEL CONTAINMENT <?02 I I 1-V-18-957-1 I I ____.. cLAss*1 AIR ACCUMULATOR ON VACUUM RELIEF VALVE ) 1-V-18-944-(TYP) (TYPICAL FOR ONE VALVE) SHIELD BUILDING 1-2*1A-14 7 CLASS-1 PENETRATION P-62 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 INSTRUMENT AIR TO VACUUM RELIEF VALVES f IGURE 6.2*47
- *
- FIGURE 6.2-48A HAS BEEN INTENTIONALLY DELETED
- *
- FIGURE 6.2-48B HAS BEEN INTENTIONALLY DELETED
- *
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- Refer to drawing 8770-G-220 Sheet 1 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 CONTAINMENT SPRAY PIPING PLAN FIGURE 6.2-50 Amendment No. 15 (1 /97)
- ------------Refer to drawing 8770-G-221
- FLORIDA POWER & LIGHT COMPANY
- ST. LUCIE PLANT UNIT 1 CONTAINMENT SPRAY PIPING SECTIONS FIGURE 6.2-51 Amendment No. 15 (1/97)
- *
- FIGURE 6.2-52 HAS BEEN INTENTIONALLY DELETED
- *
- OPTICS TELEVISION CAMERA 0 0 0 0 0 SPRAY NOZZLE GRAPH RECORDER LIGHT SOURCE (STROBE) C21C2JCZJ
(!) a . El NINE COUNTING METERS -Ill CONSOLE FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 SPRAY ANALYZER FIGURE 6.2-53
- *
- 275 250 225 200 175 150 >< > u 125 100 75 50 25 0 0 'i/ I I NOTE: 1 SECOND CIRCUITRY 7 DELAY ASSUMED J I I J I / v 7 / v t.-----10 20 30 40 50 60 70 80 90 100 2 3 DISC ANGLE (DECREES) 4 s 6 7 8 TIME (SECONDS)
FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 FLOW COEFFICIENT VS DISC ANGLE AND OPENING TIME FIGURE 106 I i 105 I I TOO°' HUMIOtTT I ,/ I v-I I I I /, 40" HUllllDITY 1o4 I Iv /4 I I I w 1ol ... I ! "' .. l g ..J .. '-MOT!: SPRAY WATll
- 60 F C0MPOH9'T COOLING H.TH
- 60 F '--I I i 102 I --*-,__ __ I '-'--I i 101 I I I I 0 .04 .OR .12 16 .20 .24 .28 .32 .)6 .40 .44 .48 .l2 .l6 .60 ,64 .68 DIFFERENTIAL PRESSURE {PSI) FLORIDA POWER & L GHT COMPANY ST. LUCIE PLANT UHIT 1 VACUUM RELi EF FLOW RATE VS DIFFERENTIAL PRESSURE FIGURE 6.2-55 0.70 0.60 o.so ;;:; w 0:: :::> V'I V'I w D.40 0:: a. ...I -< j::: z w 0:: w 0.30 u. u. a 0:20 0.10 10*1 TIME (SEC) NOTE: SPRAY WATER* 60 F COMPONENT COOLING WATER -60 F 1003 104 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PL.,NT UNIT 1 DIFFERENTIAL PRESSURE VS TIME FIGURE 6.2-56
Once the load sequencing time delay relays for one of the diesel generators are actuated, two low pressure injection valves and the high pressure injection valves are opened. One low pressure safety injection pump is started, with a high pressure safety injection pump started approximately 3 seconds later. This sequence is shown on Table 8.3-2. The LOCA load sequencing delay relays for the other diesel generator follow the same time sequence in operating safety injection system equipment.
These load sequencing delay relays open two low pressure and the alternate high pressure injection valves. They also start the second high pressure safety injection pump and the other low pressure safety injection pump. The HPSI valves are designed to open against the full shutoff head of the HPSI pumps. However, during the expected operating sequence, the valve will be partially opened before the pump reaches full speed. At 100 percent voltage the pump develops design head in less than 4 seconds. The maximum valve opening time is not more than 10 seconds. Shown in Table 6.3-1 is a tabulation of pressure and flow rate at various locations in the safety injection system. The data presented are expected values during safety injection system operation under faulted, emergency and test conditions.
6.3.2.1.2 System Operation in Recirculation Mode The safety injection system transfers automatically from the injection mode of operation to the recirculations mode of operation on receipt of the recirculation actuation signal (RAS). The RAS is described in Section 7.3 and is produced by a low level signal from the refueling water tank. The recirculation mode of operation must not be initiated until at least 20 minutes have elapsed since initiation of safety injections.
At this time the core decay heat will be less than the heat removal capacity of one high pressure safety injection pump taking suction from the containment sump. For this reason the injection mode of operation must be maintained for at least 20 minutes and sufficient refueling water tank volume for this operation must be provided.
On receipt of the RAS, the containment sump isolation valves are opened and the refueling water tank outlet valves are closed. Opening the sump isolation valves results in a transfer of the safety injection and spray pump suction from the tank to the containment sump. Closing the outlet valves provides double isolation between the recirculation coolant and the tank. The RAS also acts to shut down the low pressure safety injection pumps and closes the isolation valves in the pump recirculation line (V3659 and V3660). Recirculation flow is normally provided by at least one high pressure safety injection pump. Plant procedures require that, just prior to RAS, with at least one Containment spray pump running, a portion of the cooled water from the containment spray system be directed to the high pressure pump suction. This is not necessary to meet core cooling requirements.
There are two flow paths that can be implemented during the recirculation mode to provide for Hot Leg Injection (HLI) using the LPSI or HPSI systems to preclude the formation of boric acid crystals on fuel surfaces.
(1) Align the LPSI pump to discharge through the Shutdown Cooling System warm-up line to the opposite train's hot leg suction line, and into the hot leg. (2) Align the HPSI pump to discharge through the charging system using the bypass line around the regenerative heat exchanger to the auxiliary spray line for discharge into the pressurizer.
Note that the containment spray system may also be used during recirculation flow to provide a method for hot leg injection (HLI) as described in Section 6.2.2.2.1 6.3.2.2 Component Description A summary of design parameters for the major components is given in Table 6.3-2. 6.3-4 Amendment No. 26 (11 /13) 6.3.2.2.1 Refueling Water Tank The refueling water tank is an atmospheric tank containing water borated to greater than 1900 ppm. The P&I diagram for the system is shown in Figure 6.2-28. The refueling water tank was non-destructively tested during construction in accordance with the codes indicated in Table 6.3-2 and was given additional inspection by 100 percent radiography of the vertical joints on the first shell ring. A fiberglass reinforced vinyl ester liner was installed over the tank bottom during the 1994 refueling outage. The liner was approved by the NRC as an alternative non-code repair per 10 CFR 50.55a(3).
NRC letter dated November 25, 1994 provided a Safety Evaluation and approved this temporary repair until the steam generator refueling outage. By NRC letter dated May 27, 1997, the use of the tank liner, along with visual or hands-on inspections during each refueling outage, was approved for the remainder of the second 10-year interval of plant operation.
The use of the liner for the third 10-year interval (starting February, 1998) was approved by the NRC on 6/18/99 as relief request (RR) 7, which addresses the requirements applicable to the tank for the edition of the Code applicable to the third interval.
Relief Request RR-7A, which requested authorization to modify the augmented inspection program for the third ten-year interval to specify hands-on inspection of the RWT liner every sixth outage (beginning with SL 1-20) in lieu of every third outage, was approved by the NRC via letters dated 2/27/01 and 6/22/01. The refueling water tank (RWT) is provided with a high level and a low level alarm which annunciates in the control room. The high level condition will alarm to warm personnel of an impending tank overflow condition.
The low level condition alarms to warn of the minimum technical specification tank level being approached.
The high level alarm is 6 inches below the tank overflow pipe which accounts for a 7350 gallon margin between alarm and spillover.
Assuming that the pump with the largest capacity is being used to fill the tank (primary water pumps at 300 gpm) the operator has at least 24 minutes to shut the pump off before the tank overflows.
The operation or use of this tank is limited during power operation, and any use of it would be under strict administrative control. Should the refueling water tank overflow, the discharge would flow to a local catch basin east of the tank and eventually enter the plant storm drainage system. 6.3-5 Amendment No. 26 (11 /13)
The tank is vented to atmosphere through the overflow.
The refueling water tank is sized to contain sufficient water to fill the refueling canal, transfer tube and the refueling cavity to a depth of 24 feet above the reactor vessel flange joint. This required volume is 500,000 gallons. The actual tank volume is 525,000 gallons. The RWT's safety function is to provide a reservoir of borated water for the injection mode operation of the safety injection system. In this mode, it must supply approximately 411,260 gallons of borated water into the RCS and containment for strainer submergence (at a minimum injection time of 20 minutes).
This amount, combined with the coolant displaced from the LOCA, supplies enough inventory in the containment sump to provide the NPSH requirements for the simultaneous operation of all safeguards pumps so that an uninterrupted transition from the injection phase to the recirculation phase can occur.
The minimum injection time of 20 minutes ensures that the decay generation is low enough for one HPSI pump on recirculation to provide sufficient core cooling. With the recirculation actuation signal (RAS) set to actuate at a RWT level of approximately 66, 100 gallons (nominal setpoint plus tolerances), a total tank volume of 477,360 gallons is established as a safeguards minimum.*
Post RAS the minimum water level in containment will be approximately 24 feet. This is approximately 32 feet above the suction nozzles of the engineered safety features pump. This elevation provides adequate NPSH for the pumps. (NPSH requirements are discussed in Section 6.3.2.3 and Table 6.2-9A). Since the refueling water tank is not provided with missile shielding, the safety injection tanks have been credited as a backup water source for RCS makeup during safe shutdown (see Section 6.13 of Appendix 3F, and Section 9.3.4.3.1
). 6.3.2.2.2 Safety Injection Tanks The four safety injection tanks are used to flood the core with borated water following a depressurization as a result of a large break LOCA. The design characteristics of the safety injection tanks are presented in Table 6.3-2. The tank gas/water fractions, gas pressure, and outlet pipe size are selected to allow the tanks to cover the core before significant clad melting or zirconium-water reaction can occur. The tanks contain borated water at greater than 1900 ppm which is the minimum required boron concentration assumed in the large break LOCA accident analyses.
Redundant and diverse level and pressure instrumentation is provided to monitor the availability of the tanks during plant operation (discussed further in Section 6.3.5). Provisions have been made for sampling, filling, draining, venting and adjusting boron concentration.
Since the refueling water tank is not provided with missile shielding, the safety injection tanks have been credited as a backup water source for RCS makeup during safe shutdown (see Section 6.13 of Appendix 3F, and Section 9.3.4.3.1
). 6.3.2.2.3 Low Pressure Safety Injection Pumps The low pressure safety injection pumps serve two functions.
The first is that of injecting large quantities of borated water into the reactor *477,360 gallons is the Technical Specification minimum tank volume. 6.3-6 Amendment No. 26 (11 /13)
6.3.2.2.6 Valves The location of valves, the type and size of the valve, type of operator, position of the valve during the normal operating mode of the plant and failure position of the valve are shown in Figure 6. 3-1 and Figure 6.3-2. The design bases and actuator capabilities for HCV-3615, HCV-3625, HCV-3635, HCV-3645, MV-03-1A, MV-03-1 B, V3206, V3207, V3432, V3444, V3452, V3453, V3456, V3457, V3480, V3481, V3651, V3652, HCV-3616, HCV-3626, HCV-3636, HCV-3646, HCV-3617, HCV-3627, HCV-3637, HCV-3647, V3654, V3656, V3659, V3660, V3662, V3663, and MV-03-02 have been reviewed in accordance with the requirements of Generic Letter 89-10, "Safety Related Motor Operated Valve Testing and Surveillance", as noted in Section 3.9.2.4. As a result of evaluations performed to address NRC Generic Letter 95-07, "Pressure Locking and Thermal Binding of Safety Related Power Operated Gate Valves," the valve bodies of V3651, V3652 & V3481 have been modified to include a bypass line around the RCS side seat to eliminate the potential for pressure locking. V3480 did not require modification based on differences in valve disc design. Protection against overpressure of components within the safety injection system is provided by conservative design of the system piping, utilizing appropriate valving between high pressure sources and low pressure piping and relief valves. All lines within the high and low pressure systems are designed for full reactor coolant system pressure up to and including the safety injection valve. In addition, the high pressure header to which the charging pumps discharge is designed for full reactor coolant system pressure up to and including the header isolation valve. All relief valves are totally enclosed, pressure tight valves. A tabulation of relief valves is provided below: a) Safety Injection Tank Relief Valves V3211, V3221, V3231, V3241 The 1 inch relief valves on the safety injection tanks discharge to the containment and are sized to protect the tanks against overpressure resulting from applying the maximum fill rate of liquid or gas into the safety injection tanks. The set pressure is 280 psig and the capacity is 329 scfm (minimum required).
b) Safety Injection Tank Outlet Drain to Rwr Relief Valve V3466 A 2 inch x 3 inch backpressure compensated relief valve is provided on the safety injection test and leakage return line. This relief valve is sized to protect against overpressure of the line when filling a safety injection tank. The set pressure is 350 psig and the capacity 180 gpm. c) Low Pressure Safety Injection Header Relief Valve V3439 This 1 inch x 2 inch backpressure compensated valve protects the low pressure safety injection line and header against the pressure developed due to fluid thermal expansion.
The set pressure is 535 psig and the capacity 5 gpm. This set pressure and capacity provides thermal overpressure protection consistent with the requirements of the piping design code. d) Shutdown Cooling Return Relief Valves V3468, V3483 Each of the shutdown cooling return relief valves is sized to protect the shutdown cooling system from overpressure due to the simultaneous running of the charging pumps and the shutdown cooling system with no gas phase in the primary system. This is a backpressure compensated valve. The set pressure is 350 psig and the capacity is 155 gpm. 6.3-9 Amendment No. 26 (11 /13)
This provides four separate flow paths from the safety injection system to the reactor core. During shutdown cooling the low pressure safety injection pumps take suction from each of the reactor coolant system hot leg pipes. The two motor operated valves in each suction line are interlocked with two pressurizer pressure measurement channels to preclude their being opened when reactor coolant system pressure is above the design pressure rating of the downstream piping. The interlocks are designed to meet the intent of IEEE 279. The piping from the refueling water tank (RWf) to the chemical and volume control system (eves) has three functions:
a) To supply refueling water to the suction of the three charging pumps b) To supply borated water to the refueling tank from the eves c) To supply small quantities of concentrated boric acid to the refueling water tank for maintaining the refueling water boron concentration (1900 ppm) Local sample points are incorporated in the piping system and on the RWf for boron concentration measurement.
Remote operators are provided for taking samples from piping that may be inaccessible after an accident or may contain high temperature or radioactive water. A sample connection is provided at the bottom of each safety injection tank. Safety injection pump discharge can be sampled by the sampling system. A direct connection from the pump miniflow lines to the sampling system is provided for this purpose. A connection to the sampling system is also provided on the shutdown cooling suction lines. A connection is provided from the safety injection tank recirculation line to the waste management system. Leakage through the four check valves in the safety injection lines adjacent to the reactor coolant loops can be bled to the waste management system through this connection.
A regulated nitrogen supply is provided to the safety injection tanks to maintain tank pressure.
6.3-13 Amendment No. 26 (11 /13)
Similarly, suitable redundancy is provided in the low pressure safety injection subsystem.
Active components necessary for low pressure safety injection are sized and arranged to provide two trains capable of providing the required flow. Two motor operated injection valves and one low pressure safety injection pump operate from each diesel generator (Pump 1A, valves HCV-3615 and HCV-3625; pump 1 B, valves HCV-3635, and HCV-3645).
Low pressure safety injection flow will therefore be available assuming the failure of one diesel generator occurring simultaneously with the loss of offsite power. Passive components such as piping do not require redundancy since the low pressure safety injection system is not required to operate during the recirculation mode of core cooling. Header valve, FCV-3306, is a fail-open pneumatically operated valve and the air signal to close is locked out electrically by a key switch in the control room. At the time of this construction permit, single valve that is locked out in accordance with administrative control procedures was considered a passive component, thus not subject to redundancy requirements which accommodate single active component failure. The Staff has required in their safety evaluation report that a redundant valve be provided.
A motor operated locked open 10 inch bypass valve is in place for this purpose. The addition of this bypass valve obviates the need for administrative control of FCV-3306.
The addition of the 1 O inch motor operated bypass valve was in concurrence with the requirements of 10 CFR 50.109. Safety injection pumped flow is not available until 30 seconds following a safety injection actuation signal (SIAS). This allows for the startup and loading of diesel generators in the event of a loss of offsite power. The diesel generators and emergency power system are designed to start the safety injection pumps within 16 seconds after SIAS with loss of off site power. The HPSI valves have an opening time not greater than 10 seconds. The LPSI valves have an opening time not greater than 15 seconds. In the accident analyses in Chapter 15, the elapsed period between the time of an accident and the time when the safety injection system starts to pump emergency cooling water into the core is 30 seconds for the case of loss of offsite power. Core cooling water from the safety injection tanks is initiated within this time period for a range of pipe break sizes when the reactor coolant system pressure decreases to between 230 psig and 280 psig. The delay time used in the analyses is slightly longer than the sum of the times to 1) actuate and bring the diesel generator up to speed and voltage, 10 seconds, 2) sequentially energize the safety injection pumps and valves as shown in Table 8.3-2, 6 seconds, and 3) raise each pump to rated speed and to fully open each of the motor operated safety injection valves, 15 seconds maximum. This elapsed time between SIAS and the safety injection system operation is 25 seconds and the basis for the use of 30 seconds in the analyses.
For the case of offsite power available, the corresponding delay time is 15 seconds. During a LOCA, the passive safety injection tanks begin to inject flow to the reactor coolant system as soon as the system pressure drops below the tank pressure and the time lag between the break and the time the tanks begin to inject is dependent on the break size. The rapid depressurization associated with the large breaks allows the tanks to inject immediately providing rapid core recovering before the pumps start. The tanks are designed such that flow from the tanks continues until after the pumps have started thus assuring a continuous flow to the core. 6.3-15 Amendment No. 26 ( 11 /13)
(3)
By integrating:
(5)
Where:
or, Reference (9) (6)
that the important vortex formation parameters are the radius (r), the peripheral velocity (v) and the available head.
The following St. Lucie Unit 1 parameters determine the required head of water to impede vortex formation:
r = radius available in the sump = 2.5 ft
g = 32.2 ft/s 2
h = water above sump suction inlet (conservative minimum) = 15 ft.
V = intake velocity (considering one HPSI, one LPSI, and one containment spray pump, conservatively not taking credit for reduced velocity at the screen and assumes 100%
blockage of horizontal screen and 80% blockage of vertical screen covering the sump suction line entrance, i.e., the screen within the sump covering the intake)= 5.4 ft/sec Note LPSI flow greater than 2 29 gpm is initiated at 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> post-LOCA for boron precipitation control. This flow is added to the flow at RAS.
Then, C 3 = vr = (5.4 ft/sec) (2.5 ft) = 13.5 ft 2 /sec
The analysis indicates that the suction velocity is sufficiently low that vortex formation is not possible with the 15 ft of water available.
6.3-33 Amendment No.
26 (11/13) Required Head =
To further substantiate the fact that vortex formation cannot occur, a comparison of the vortex parameters for St. Lucie Unit 1 was made with a pressurized water unit that actually conducted the recirculation test. The controlling parameters for the units are listed below:
Vortex Parameters Parameter St. Lucie Trojan Radius 2.5 ft. 4 ft. Intake velocity 4.5 ft/sec 9.5 ft/sec Required head 0.5 ft 1.4 ft Water available 15 ft 5 ft In order to provide an overall comparison of the units, consider the following margin defined as:
Margin = Head available Required head
The above term considers all parameters which affect vortex formation and allows for an easy comparison of units. The margin calculated for St. Lucie is 30.
The above clearly indicates that both units have sufficient margin in that they cannot support vortex formation or associated air binding. The in situ recirculation test verified that the sump could not support vortex formation, that air binding was not realized based on the margins established supra, it is concluded that pump performance will not be affected by vortex formation, air binding or operational transients at St. Lucie.
In addition to the in situ plant tests, experimental tests were conducted on vortex formation.(11) When applied to St. Lucie, the results of these tests indicate that the minimum submergence required is approximately 3 ft of water.
Since the St. Lucie sump has 15 ft of water available, vortex formation is not possible. It should be noted also that the in situ plant test results indicate that the above experimental predictions are conservative. Experimental test results indicate that Trojan would require approximately 7 ft of water. However, the in situ test was conducted satisfactorily at 5 ft.
It must also be noted that possible transient conditions are minimized by the sump design. The sump isolation valves open in approximately 40 seconds following receipt of RAS, thus there is a gradual commencement of flow from the sump since suction is still being maintained at the RWT (RWT isolation valve closes approximately 90 seconds after receipt of RAS). The overlap in pump suction source reduces sump initial velocities and therefore precludes the possibilities of vortex formation, air binding, or other operating transient effects.
NPSH calculations were conducted in accordance with Regulatory Guide 1.1 and are summarized in Table 6.2-9A.
UNIT 1 6.3-34 Amendment No.
27 (04/15)
TABLE 6.3-2 COMPONENT DESIGN PARAMETERS 1. Refueling Water Tank Quantity 1 Code ANSI B96.1, 1967 Volume (Total), gal.
525,000 (Useful), gal.
500,000 Design Pressure Atmospheric Design Temperature, F 125 Fluid, Borated Water, ppm boron (nominal) 190 0 Materials Tank Aluminum Flanges ASTM B246, 6061T6 Skirt and Plate ASTM B209, 6061T6 Rods and Bars ASTM B308, 6061T6 Pipe ASTM B241, 6061T6 Shell Manway Cover ASME SA-240 TP 316 2. Low Pressure Safety Injection Pum ps Quantity 2 Type Single Stage, Centrifugal Code API Standard 610, 1965 Centrifugal Pumps for General Refinery Service Design Pressure, psig 550 Design Temperature, F 350 Design Flow Rate, gpm 3000 (includes 40 gpm bypass)
Design Head, ft 350 Maximum Flow Rate, gpm 4500 Head at Maximum Flow Rate, ft 235 Materials Stainless Steel ASTM
-A-351 Gr CF8M Seals Mechanical Motor Horsepower 400 Motor Speed, rpm 1800 3. High Pressure Safety Injection Pumps Quantity 2* Type Multistage, Centrifugal Code API Standard 610, 1965 Centrifugal Pumps for General Refinery Service Design Pressure, psig 1600 Design Temperature, F 350 Design Flow Rate, gpm 345 (includes 30 gpm bypass flow)
- HPSI Pump 1C has been abandoned in place.
UNIT 1 6.3-44 Amendment No.
2 7 (04/15)
Design Head, ft Maximum Flow Rate, gpm Head at maximum Flow Rate, ft Materials Shaft Seal Motor Horsepower Motor Speed, rpm 4. Safety Injection Tanks Quantity Code Design Pressure Internal/External, Psig Design Temperature, F Volume, Total, ft 3 Liquid, ft 3 Fluid, Borated Water, ppm boron( minimum) Material Shell and Heads 5. Piping and Valves Valves Code ANSI Rating (psig) Piping Code TABLE 6.3-2 (Cont'd.)
2500 640 1300 Stainless Steel ASTM-A-351 Gr CF8M Mechanical 400 3600 4 ASME 111, Class C, Winter 1969 28010 200 2020 1090 to 1170 1900 ASTM SA-264 with SA-240 TP304 Clad Draft ASME Code for Pumps and Valves, Nov. 1968; Issued for Trial Use and Comment. Code Class 1, 2, 3; refer to Figures 6.3-1 and 6.3-2 1500,900,300 ANSI Standard Code for Pressure Piping, ANSI B 31.7, 1969. Code Class 1,2,3; refer to Figures 6.3-1 and 6.3-2 6.3-45 Amendment No. 26 (11 /13)
TABLE 6.3-2A (Cont'd)NOTES: (1) Piping is painted.
(2) Exposure on side 1 has been separated into containment vapor (elevation
³ 25 ft) and containment sump (elevation 25 ft) where applicable.
(3) Only outside surface applicable to this HVAC ductwork.
(4) The given surface area for a concrete wall has been reduced to represent both sides of the wall since the faces often have different areas. An
- in the exposure side 2 column identifies where this has been done and should be taken to mean both sides are exposed to the environment of exposure side 1. The given thickness
is that of the full wall.
(5) Unless otherwise indicated, the given surface area is represented equally in exposure sides 1 and 2 and the
thickness is representative of the full thickness.
(6) Exposure on side 2 is not applicable since it ranges from surfaces previously given to ground.
(7) The interior surface is not readily subject to the exposure of side 1 since that environment has no free path to
the inner surface. The surface area represents the outer surface only and the heat sink is considered to be
the full thickness.
(8) Where the steel is buried in concrete or backed by concrete, this is indicated in the exposure side 2 column.
In these cases the surface area represents that area exposed to the environment of the exposure side 1
column.(9) The exposure of sides 1 or 2 to containment liquid does not apply until RAS and should be considered as
exposure to containment vapor.
6.3-86
Refer to drawing 8770-G-078, Sheets 130A & BAmendment No. 16, (1/98)FLORIDA POWER & LIGHT COMPANYST. LUCIE PLAN UNIT 1FLOW DIAGRAMSAFETY INJECTION SYSTEMFIGURE 6.3-1 Refer to drawing 8770-G-078, Sheets 131A & BAmendment No. 16, (1/98)FLORIDA POWER & LIGHT COMPANYST. LUCIE PLAN UNIT 1FLOW DIAGRAMSAFETY INJECTION SYSTEMFIGURE 6.3-2
- *
- Brake Horse Power 400 Percent Efficiency 80 Total Head 70 in Feet 60 600 50 400 40 30 200 20 10 0 0 0 FLORIDA POWER.& LIGHT CO. St. Lucie Plant F otal Head NPSH 1 2 3 4 5 Thousand Gallons per Minute Low Pressure Safety Injection Pump Performance 300 200 100 NPSH, ft 20 10 0 13-/ Figure 6.3-3
- * * .. o..g :I: 0 *S 0 Xoi;:r 0 V) N co 0.. z 1. -0 0 0 0 0 0 0 co ,_ U"\ oi:::r ("I'\ N ...... 0 .. --LU q \ 8 \ '° \ \ ' c:::> %* 0 Ll"I d CL> to :s:' -0 0 :J . 0 c: -4 ""'*-z, . 0::: ' (..!) CL> c... I . 0.. V') I (/'I 0 c: 00 10 m= re 0.. <.::> :I: ct:\ 0 0 N § -FLORIDA POWER & LIGHT co. High Pressure Safety Injection Pu mp Performance St. Lucie Plant 13-15 Figure 6.3-4
- *
- THE FOLLOWING FIGURES HAVE BEEN DELETED Figures 6.3-5 thru 6.3-11 Amendment No. 16, (1/98) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT l DELETED FIGURES EIG-u:R.E 6.3-5 thru 6.3-ll
' .._,, 'Xl ),A, < ** _.*\> << '" * .,.,,,.,,u
... ,.
OWG NO. SK-8770-M-300 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 CONTAINMENT
\\'ATER LEVEL POST LOCA FIGURE 6.3*12
The systems included in this definition are: a) the control room, which provides an envelope for limiting the exposure of control room personnel due to airborne activity and direct radiation from the containment b) the control room air conditioning and ventilation system which: 1) limits airborne radioactivity in the control room following a LOCA by recirculating control room air through charcoal filters 2) air conditions the control room under normal and accident operation
- 3) supplies fresh air makeup to maintain safe levels of carbon dioxide and oxygen under normal and accident conditions
- 4) includes a smoke detector in each air intake with annunciating the control room. c) radiation monitoring and various status lights and control switches which indicate and control operability of the habitability systems d) the containment isolation signal (CIS) which isolates the control room vent system intake and exhaust ducts and actuates control room air recirculation e) miscellaneous medical, kitchen and sanitary supplies which facilitate habitability of the control room The performance objectives of the control room ventilation and air conditioning system, provisions for air intake, monitoring, and filtering are discussed in Section 9.4.1. The system flow diagram is shown on Figure 9.4-1 and the control diagram is given on Figure 9.4-3. System design data are given in Table 9.4-1. See Sections 9.4, 12.2, and 15.4 for related information concerning the Control Room HVAC. 6.4.1.3 System Evaluation The minimum period of control room habitability is based on the time required to monitor and control operation of engineered safety features and their supporting systems, to monitor radioactive releases and to assure that control room personnel do not receive radiation exposure in excess of 5 REM total effective dose equivalent.
Under normal meteorological conditions, a shift change could be made within several hours after a LOCA. However, if adverse meteorological conditions existed, this time would be lengthened in proportion to the duration of the postulated adverse condition.
The loss of AC power during a station blackout (SBO) event will result in a loss of control room air conditioning.
Alternate AC power is assumed to be unavailable for the first hour of the event, and the station copes on DC power during that time. The control room ventilation system is assumed not to function during the one-hour DC coping period. Calculated temperatures for the control room during the DC coping period remain within the station's heat stress procedural guidelines; therefore, the control room remains habitable for continuous occupancy during an SBO event. The peak calculated control room temperature is essentially equal to the acceptable steady state temperature for equipment operability per NUMARC 87-00, Rev. 0 "Guidelines and Technical Bases for NUMARC Initiatives Addressing Station Blackout at Light Water Reactors," and therefore, operability requirements for safe shutdown equipment in the control room are met. The number of personnel in the control room during the accident was originally assumed to be ten. The plant evacuation plan (see Chapter 13, and Emergency Plan) calls for the removal of non-essential plant personnel immediately following a LOCA. Therefore, only the operators on shift at the time of the postulated accident should be in the control room. Additional plant personnel such as health physicists were accounted for by assuming 10 occupants.
6.4-2 Amendment No. 26 (11 /13)
APPENDIX 6A DESCRIPTION OF THE SGNIII DIGITAL COMPUTER CODE USED IN DEVELOPING MAIN STEAM LINE BREAK MASS ENERGY RELEASE DATA FOR CONTAINMENT ANALYSIS 6A-i ABSTRACT The information contained in this appendix is considered historical and the original content should not be deleted. It may be acceptable to update this appendix (i.e., add text) to annotate plant changes or current operating conditions, if such changes are determined by the UFSAR Update Group to be appropriate.
This appendix details the SGNlll digital computer program. This code calculates the transient response of the primary coolant system, pressurizer, and steam generators to steam line breaks to develop mass/energy releases for containment design. The model consists of fluid flow and heat transfer representations in the reactor core, hot leg plena and piping, pressurizer, steam generators, cold leg piping and plena, and steam generator secondary side. Reverse heat transfer from the intact steam generators to the reactor coolant loop is considered.
A two-lump core fuel model is used together with a point kinetics representation and non-linear moderator, Doppler, boron, and CEA reactivity effects. Time dependent reactivity and coolant flow functions may also be inputted into the code. The secondary side of each steam generator is represented by a finite two-node quasi-static balance of energy flux and secondary fluid thermodynamics.
The steam lines to the turbine are modeled. The following control systems are represented:
CEA's, primary and secondary safety valves, and main steam line isolation valves. A full range of superheated steam, saturated steam and water, and sub-cooled water thermodynamic states is available in the pressurizer representation.
SGNlll is a coupled primary, secondary and containment model which simultaneously determines the time dependent containment pressure and temperature response with the mass & energy release. The containment in the SGNlll is represented by the integration of the NRC approved CONTRANS coding as described in Reference (14). The differential equations used in the models are presented.
In the simulation, the equations are in finite difference form and are numerically integrated in time. The SGNlll inpuUoutput format is given along with typical results. This description of the SGNlll digital code is generic. The code has been used to generate steam line break mass/energy release data for containment design for many plants in addition to Systems 80 type plants. Accordingly description of certain models may not apply explicitly to Systems 80 type plants. However, the code input data is constructed conservatively for each plant for the purpose of steam line break analysis.
If the plant design changes in areas important to the description of the steam line break accident, then additional models are added to the basic code described herein, if these design changes can not be conservatively described through manipulation of the code input data. 6A-ii Amendment No. 26 (11 /13)
TABLE OF CONTENTS Page No.ABSTRACT 6A-ii LIST OF TABLES 6A-v LIST OF FIGURES 6A-v NOMENCLATURE 6A-vi SUBSCRIPTS 6A-viii I.INTRODUCTION 6A-1 II.MATHEMATICAL MODEL 6A-2 A.Neutron Kinetics 6A-2 B.Fuel Temperature Equations 6A-3 C.Reactor Coolant Flow Equations 6A-4 1.Conse rvation Equations 6A-4 2.Implicit Numerical Solution 6A-6 D.Steam Generator Secondary Side 6A-7 1.Description of Thermodynamic Systems 6A-7 2.Conservation Equations 6A-8 3.Additional Relationships 6A-8 4.Steam Flow Rates 6A-9 5.Discrete Formulation 6A-9 a.Qualities 6A-10 b.Interregion Mass Flows 6A-10 c.Heat Flux Terms 6A-12 d.Main Steam Flow 6A-13 6.Iterative Solution of Discrete Sys tem Equations 6A-13 7.Nonsaturated Conditions 6A-14 E.Main Steam Line Flow Equations 6A-16 1.Slot Break 6A-16 a.Case 1 6A-17 b.Case 2 6A-18 2.Guillotine Break 6A-18 a.Intact Ste am Generator(s) 6A-19 b.Ruptured Steam Generator 6A-20 6A-iii Amendment No. 17 (10/99)
TABLE OF CONTENTS (Cont.)Page No.F.Pressurizer 6A-22 1.Conservation Equations 6A-22 2.Explicit Numerical Solution 6A-23 G.Plant Controls 6A-24 1.Turbine Admission Valve 6A-24 2.Main Steam Line Isolation Valves 6A-2 5 3.Steam Generator Pressure Relieving Systems 6A-25 a.Steam Dump 6A-25 b.Bypass 6A-26 c.Secondary Safety Valves 6A-26 4.Primary Safety Valves 6A-26 5.Feedwater Controller 6A-27 6.CEA Controller 6A-28 7.Pressurizer Water Level and Pressure System 6A-30 a.Charging and Letdown System 6A-30 b.Spray 6A-31 c.Heaters 6A-31 H.Reactor Trip Modes 6A-32 I.Regenerative Heat Exchanger (RHX) 6A-32 J.Physical Properties 6A-32 III.SGNIII INPUT DATA 6A-34 IV.SGNIII OUTPUT DATA 6A-42 A.Long Form Printout 6A-42 B.Short Form Printout 1 6A-43 C.Short Form Printout 2 6A-44 D.Short Form Printout 3 6A-44 E.Graph 6A-45 REFERENCES 6A-46 6A-iv Amendment No. 17 (10/99)
LIST OF TABLES Table No.Title Page No.6A-1 Defining Variables for SGNIII Steam Generator Secondary Model 6A-47 6A-2 Moody Critical Flow Rates (fL/D = 0.0) 6A-48 6A-3 Moody Critical Flow Rates (fL/D = 5.0) 6A-49 6A-4 Moody Critical Flow Rates (fL/D = 10.0) 6A-50 LIST OF FIGURES Figure No.
Title 6A-1 Steam Generator Secondary Flow Model 6A-2 Main Steam Line Model 6A-3 Schematic f or Slot Break 6A-4 Schematic f or Guillotine Break 6A-5 Valve Area Programs 6A-v Amendment No. 17 (10/99)
NOMENCLATURE NOMENCLATURE (Cont.)A Area, ft2 GNM2 Gain on integral mass error, sec
-1 B Normalized reactor power GNM3 Feedwater control option BT Normalized reactor power after reactor trip GNPOW Gain on regulating CEA controller power error signal C Constant GNTWR Gain on regulating CEA controller temperature signal C Boron concentration, ppm GNTRIP Additional gain on steam generator level (mass) error signal following trip C D Discharge coefficient h Specific enthalpy, Btu/1bm C P Specific heat, Btu/1bm/
o F H Film heat transfer coefficient, Btu/hr/ft 2/o F D Delayed neutron precursors HA Heat transfer coefficient, Btu/sec/
o F d Diameter, ft J Conversion factor 778 ft-1bf/Btu Do/Di Ratio of RHX tube OD to ID k Line flow resistance DBNDP CEA controller power deadband, power fraction k Thermal conductivity, Btu/hr/ft/
o F DBNDT CEA controller temperature deadband, o F L Length, ft DCAY Decay heat function, power fraction 1*Neutron lifetime, sec F Volumetric flow rate, ft 3/sec M Mass, 1bm F Fraction m Coolant mass flow rate, 1bm/sec FLFR Normalized reactor coolant mass flow P Pressure, psia G Mass flux, 1bm/ft 2-sec PR Prandtl number g Acceleration of gravity 32.2 ft/sec 2 PK Feedwater pipe resistance, psi/(1bm/sec) 2 g c Gravitational constant 32.2 1`bm-ft/1bf-sec 2 Q Time dependent core heat generation rate, Btu/sec G k=o Moody critical flow for fL/D=0, 1bm/ft 2/sec q Generalized heat generation rate, Btu/sec G k=5 Moody critical flow for fL/D=5, 1bm/ft 2/sec R s Gas constant for steam, 85.83 1bf-ft/1bm o R G k=10 Moody critical flow for fL/D=10, 1bm/ft 2/sec RDINST Regulating CEA position, fraction of length GNF1 Gain on feedwater flow-steam flow difference error RDSPDN Regulating CEA insertion speed, fractional travel/sec GNF2 Gain on integral of flow error, sec
-1 RDSPUP Regulating CEA withdrawal speed, fractional travel/sec GNM1 Gain on steam generator level error 6A-vi NOMENCLATURE (Cont.)NOMENCLATURE (Cont.)RDSP Regulating CEA speed, fractional travel/sec D T Temperature error signal, oF RDSPSC Regulating CEA insertion speed on trip, fractional travel/sec D t Time step, sec RM1 Rod controller normalized motion signal D r Density change, 1bm/ft3 Rm Steam generator tube heat transfer resistance, (Btu/hr/ft 2/o F)-1 s P Pressure correction term, psi SGSPSC Shutdown CEA insertion speed on trip, fractional
travel/sec s r Change in reactivity T Temperature, o F D q Loop transit time, sec T Average temperature, o F (Volume error, ft3 t Time, sec z Steam velocity multiplier U Overall steam generator heat transfer coefficient
Btu/hr/ft2/
o F m Viscosity, 1bm/ft/hr URHX Overall RHX heat transfer coefficient, Btu/hr/ft 2/o F r Density, 1bm/ft3 V Volume, ft 3 r C p Heat capacitance, Btu/ft3/of v Specific volume, ft 3/1bm s Surface tension (1b/sec2)
V g Superficial steam velocity, ft/sec t Time after reactor trip, sec VK Feedwater valve resistance, psi/(1bm/sec) 2 t i Delayed neutron decay constant, sec-1 VL Feedwater valve lift, % opening y Weighting factor VS Valve speed, %/second W Volumetric flow rate, gpm W Boron worth, %
D r /ppm WL e Pressurizer water level error, ft X Quality a Steam void fraction b Total delayed neutron fraction g Ratio of steam specific heat, C p/C v=1.3 D B Normalized power error signal D P Pressure iteration increment, psi 6A-vii SUBSCRIPTS SUBSCRIPTS (Cont.)active Steam generator secondary volume to top of tubes hlc Hot leg coolant b Break (containment) pressure hlm Hot leg metal bh Backup heaters i Delayed neutron and precursor groups boil Boiling in pressurizer id Inside diameter bor Boron in Into a region of the system bp Bypass valve j Header c Reactor core coolant l Saturated liquid clc Cold leg coolant line Primary safety valve line clm Cold leg metal liq Subcooled liquid cond Condensing in pressurizer lo Letdown orifice cp Charging pump loop Rcs loop cr Regulating CEA max Maximum value crit Critical min Minimum value dem Demand signal mod Moderator reactivity feedback dop Doppler reactivity feedback ns Net surge dp Dump valve od Outside diameter f Core fuel and clading out Out of a region of the system f Saturated liquid p Reactor coolant system fc Valve fully closed ph Proportional heaters fg Vaporization press Pressurizer fo Valve fully opened rv Relief valve fp Full power s Steam fw Feedwater sat Saturation g Saturated vapor sec Steam generator secondary side h Pressurizer heaters sg Steam generator 6A-viii SUBSCRIPTS (Cont)sgc Steam generator tube coolant sgm Steam generator tube metal si Safety injection sp Spray flow sr Shutdown CEA surge Pressurizer mass surge based on primary loop density change sv Safety valve sys Steam generator secondary volume (fixed) tot Steam generator secondary volume as calculated
based on water masses and specific volumes t Old time step t+D t New time steop tf Time function trip Reactor trip I Pressurizer or steam generator steam region II Pressurizer or steam generator liquid region 1 Fuel region 1 or steam generator tubes contacting
steam 2 Fuel Region 2 or steam generator tubes contacting
two phase 12 From Region I to Region II 21 From Region II to Region I 6A-ix
If the flow is subcritical, m4 is obtained from Equation 99. The flow from the ruptured steam generator m 5 , is the sum of the flow out the break and the flow from the steam line. (81) (b) Case 2 In Case 2 flow in the main steam lines from the intact units is in the normal direction.
Flow in the line from the ruptured unit is reversed.
Flow in the steam lines is assumed to be subcritical and governed by orifice flow equations.
An iteration on the header pressure (P J) is made until the sum of the flows at the header equals zero. A pressure P J is chosen. Flow in the steam lines are given by (82) (83) where k, = K;/2.lgc /144 and K; are code inputs. The quality at the header VJ is determined by the pressure and enthalpy at the header. The enthalpy at the header is the enthalpy of the flow at the nozzle of the intact units. (84) The flow to the turbine is given by Equation 78. The sum of the flows at the header must equal zero. If not, a new pressure is assumed until convergence is reached. The break flow is obtained assuming Moody critical flow (References 4 and 5) with zero resistance factor. m4 =A4 K4 Gk=o (P2,X2) (85) If the flow is subcritical, m 4 is obtained from Equation 99. The flow from the ruptured steam generator m 5 is the sum of the flow out the break and the flow from the steam line. 2. Guillotine Break Figure 6A-4 shows a schematic for a guillotine break. Node 1 is the intact steam generator(s), Node 2 is the ruptured unit, and Node J is (86) 6A-18 Amendment No. 26 (11 /13)
APPENDIX 6C Response to Regulatory Staffs Letter of June 3, 1975. This appendix documents an FPL response to an NRC letter. As such, this appendix is considered historical and the original content should not be deleted. It may be acceptable to update this appendix (i.e., add text) to annotate plant changes or current operating conditions, if such changes are determined by the FSAR Update Group to be appropriate.
This appendix has been updated to support the implementation of the Extended Power Uprate (EPU). 6C-1 Amendment No. 26 (11/13)
1.0 INTRODUCTION
On June 3, 1975, the Regulatory Staff requested additional information on the ECCS re-evaluation for St. Lucie Unit 1. The Staff concerns as expressed in questions 6.28, 6.29, 6.30, 6.31, and 6.32 are discussed in the following sections of this appendix.
This appendix has been updated to support the implementation of the Extended Power Uprate (EPU). 6C-3 Amendment No. 26 (11 /13) 2.0 BORON PRECIPITATION 2.1 BACKGROUND Increasing attention has been focused on the performance of the Emergency Core Cooling System (ECCS) during extended periods of time following a loss-of-coolant accident (LOCA). Following a cold leg break, term residual heat removal is accomplished by continuous boiloff of fluid in the reactor vessel. As borated water is delivered to the core region via safety injection and virtually pure water escapes as steam, unacceptably high concentrations of boric acid and other solution additives may accumulate in the reactor vessel. For a hot leg break, safety injection flow introduced via the cold legs will travel down the annulus, through the core, and out the break. A flushing path is established through the reactor vessel, precluding the buildup of solids in the core region. However, for a cold leg break, only that amount of injected water required for decay heat removal is delivered to the core; the remainder spills out the break. Therefore, because of the geometry of the Reactor Coolant System, there is no flushing flow through the core for a cold leg break with cold leg injection and the boric acid concentration will increase.
The analysis performed (in specific response to the Regulatory Staffs question 6.28 in the July 3, 1975 letter) was based on a boric acid makeup tank concentration of 12 weight percent. Subsequent changes allow for a reduction to 2.5-3.5 weight percent. This reduction in concentration resulted in this analysis becoming more conservative and thus no analysis revision was required or performed.
2.2 CEN-152 GUIDANCE Following the Three Mile Island Unit 2 (TMl-2) accident, the NRC established requirements with the objective of improving the quality of operational information plant operators would have to respond to emergency events. For the Combustion Engineering Owners Group (CEOG), one of the documents implementing the NRC'S requirements is CEN-152. This report contains the methodology used to develop and validate the emergency procedure guidelines (EPG's) and information on guideline implementation.
The NRC issued a Safety Evaluation Report (SER) on CEN-152, Revision 01 in July, 1983. Revision 03 incorporated improvements in understanding and comments received from the NRC and was submitted to the NRC in May, 1987. As of mid-1996, no SER has been issued. Revision 03 of these EPG's represents the best available guidance for the mitigation of accident consequences for CE plants. St. Lucie Unit 1 has developed its emergency procedures based on this guidance as implemented through Plant Specific Technical Guidelines for Emergency Operating Procedure at St. Lucie Unit 1. A circulation flow through the reactor vessel will be established to flush solids from the core region and insure continued operability of the ECCS independent of break size or break location.
The calculations discussed in Item 2.3 (historical) show that a minimum core through flow of 20 gpm is required within 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> post-LOCA to assure that boron does not precipitate.
The requirements for flushing flow has been revised as described in Item 2.4 for EPU. For EPU, a minimum flushing flow of 20 gpm is required within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> post-LOCA to assure that boron does not precipitate.
Ultimately, subcooled cooling of the core is achieved and a quasi-normal shutdown cooling mode can be initiated.
6C-4 Amendment No. 26 (11 /13)
Item 2.5 provides a summary of the operating philosophy for hot and cold leg injection.
Depending on the method of hot leg injection utilized, HPSI, LPSI or containment spray pumps may be used to ensure an adequate amount of flow is injected through the hot leg so that boron precipation will not occur. Present guidance to operations personnel indicates that use of LPSI pumps to provide hot leg injection through the hot leg suction line is the preferred method; with this method LPSI flow is determined to be greater than 229 gpm. When using HPSI pumps to provide injection via the pressurizer auxiliary spray line, flow should be maintained at a minimum 229 gpm at 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> following the event. A third available alternative is to provide hot leg injection through the hot leg suction line using a containment spray pump. Current procedural requirements call for maintaining a minimum of 229 gpm flow on PIC-3306 when using this lineup. In all cases, if the normal shutdown cooling flow path for long-term decay heat removal can not be established within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> following an event, hot leg injection (simultaneous with cold leg injection) is to be initiated.
Each of these flow injection modes should insure the minimum required boron flushing flow through the core that is required to avoid boron precipitation.
2.3 MATHEMATICAL MODEL AND ASSUMPTIONS (Historical)
In response to questions from the NRC during Unit 1 licensing, a mathematical model and computer code has been developed to predict the buildup of boric acid in the post-LOCA reactor vessel. In addition, this model is used to perform parametric studies to determine required core through-flows and flush initiation times. The concentration of boric acid in the reactor vessel has been modeled as a function of time by establishing a boric acid mass balance for the reactor vessel. Results of this model for the worst case break with no circulation, are presented in Figure 6C-1. Separate mass balances have been developed for the injection and recirculation modes of ECCS operation.
In each mass balance, it is conservatively assumed that the flow rate of influent to the reactor is only that required to replace boil-off, and that all boric acid in the influent remains in the 6C-4a Amendment No. 26 (11/13)
=
!"!"!"
During long term cooling, the steam generated within the core and exiting through the hot legs will not prevent the entry of hot leg injection ECC water 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after a LOCA. Taking ECC water injected by a LPSI pump into one hot leg through the 12 inch shutdown cooling line, the injected water flows along the bottom of the hot leg pipe and into the reactor. At ten hours after the LOCA, the steam generated by the core is 22 lb/sec which, at 20 psia, produces a velocity of 25 feet per second through each of the hot legs. The entrainment threshold velocity for gas passing over a free liquid surface is 53 feet per second at 20 psia (reference 10). Hence, no entrainment of ECC water by core generated steam would occur. The hot leg injection of ECC water through the auxiliary spray line is adequate to prevent boric acid precipitation.
Hot leg injection via pressurizer auxiliary spray utilizes both of the HPSI pumps. One pump is discharging through the cold leg safety injection nozzles while the other is discharging through the auxiliary spray line, pressurizer and surge line to the hot leg. In this case a break in a hot leg provides an adequate core flush in the normal direction from the safety injection nozzles through the core and out the hot leg break. The flow from the other pump through the spray line is not needed. In the case of a cold leg break, the flow from the HPSI pump feeding the cold leg safety injection nozzles is conservatively considered ineffective and both core cooling and flush are provided by the flow through the auxiliary spray line. Flow is adequate to provide both decay heat removal and core flush capability.
2.4 POST-LOCA BORIC ACID PRECIPITATION REANALYSIS The following information in this sub-section is retained for historical purposes.
This analysis (Reference
- 12) is performed in accordance with the methodology of ABB-SEMP's NRC accepted post-LOCA long term cooling evaluation model (Reference 13). The analysis uses the BORON computer code. BORON calculates the boric acid concentration in the core and the containment sump following a LBLOCA. The plant design data used as input to the analysis is provided in Table 6C-2. The results of the analysis are presented in Table 6C-3 and in Figures 6C-7 and 6C-8. Based on the results of this analysis, it is concluded that for St. Lucie Unit 1, a minimum simultaneous hot and cold side injection flow rate of 190 gpm (i.e., at least 190 gpm to the hot side and 190 gpm to the cold side of the RCS) in place between 4 and 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> (inclusive) after the start of the LOCA is required to maintain the core boric acid concentration below the boric acid solubility limit following a large break LOCA. However, the maximum switchover time is restricted to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> due to post-LOCA criticality as described in Section 2.5.1. The earliest time to initiate simultaneous hot and cold side injection is 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. This is determined from the more limiting of the times when 1. the hot leg steam velocity falls below a value that would entrain the hot side injection as determined by the boric precipitation reanalysis and 2. the injection flow rate considering a single failure with spillage out the break is sufficient to replace water lost due to core boil-off for both hot and cold leg breaks. This is based on a minimum hot leg injection flow of 190 gpm and a minimum cold leg injection flow of 235 gpm for the simultaneous hot/cold leg injection configuration.
The design analysis demonstrates conformance to Criteria 5, Long Term Cooling, of the ECCS acceptance criteria of 10 CFR 50.46. 6C-9 Amendment No. 26 (11 /13)
The discussions in Sections 2.4.1 to 2.4.6 address EPU conditions.
2.4.1 Introduction To support the EPU, post-LOCA long term core cooling analytical evaluations of boric acid precipitation were performed.
This analysis was performed in accordance with the Westinghouse post-LOCA long term cooling evaluation model for CE designed PWRs, CENPD-254-P-A (Reference 13), with the exceptions described below. This analysis uses the BORON computer code (Reference 13, Appendix C). BORON calculates the boric acid concentration in the core and the containment sump following a LBLOCA. This evaluation model complies with the requirements of Appendix K to 10 CFR 50 and was accepted by the NRC for referencing in licensing applications for CE PWRs. However, in a letter dated August 1, 2005 (Reference 14), the NRC identified concerns regarding the CENPD-254-P-A post-LOCA long term cooling evaluation model. The letter states the following: "Until the NRG staffs concerns are sufficiently resolved, the staff will not approve the use of TR CENPD-254-P for license applications." Based on discussions with the NRC staff, the issues identified in Reference 14 must be addressed to the staff's satisfaction for any plant change that impacts the post-LOCA long term cooling analysis and that requires NRC approval before implementation (e.g., a change that requires a license amendment, such as an EPU). This understanding was confirmed by the NRC in a letter dated November 23, 2005 (Reference 15), wherein the following is stated: "Until a supplement to TR CENPD-254-P is issued addressing the staff concerns, the following four items will also need to be addressed by licensees on a plant-specific basis in any future submittals regarding post-LOCA L TC." As indicated above, the NRC identified four items that must be addressed by licensees on a plant-specific basis in license submittals that are made prior to the ultimate resolution of concerns identified in Reference
- 14. The four items identified in Reference 15 are as follows: 1. The mixing volume must be justified; its calculation must account for void fraction.
- 2. The calculation of the mixing volume must account for the loop pressure drop between the core and the break. 3. The boric acid solubility limit must be justified, especially if crediting containment pressures greater than 14.7 psia or chemical additives in the sump water. 4. A decay heat multiplier of 1.2 must be used for all times if an Appendix K evaluation model is used. The modifications to the CENPD-254-P-A methodology to address NRC Items #1, #2, and #3 were previously included in the boric acid precipitation analysis that was performed in support of the Waterford 3 EPU. The methodology used in the Waterford 3 EPU boric acid precipitation analysis has since become known as the "Waterford approach." It has been recognized by the NRC (Reference
- 16) as an acceptable interim methodology for performing boric acid precipitation analyses prior to the establishment of a new approved methodology that addresses the issues identified in Reference
- 14. The St. Lucie Unit 1 EPU boric acid precipitation analysis was performed with the BORON computer code (Reference 13, Appendix C) using the CENPD-254-P-A post-LOCA boric acid precipitation analysis methodology as modified by the Waterford approach.
In addition, it used a decay heat multiplier of 1.2 for all times, and a core/containment pressure of 14.7 psia. Thus, the methodology used for St. Lucie Unit 1 EPU addressed the four items identified in Reference
- 15. There have been further changes made to the boric acid precipitation analysis since the Waterford approach was implemented.
See Item 2.4.3 for all assumptions accompanying this EPU analysis.
6C-9a Amendment No. 26 (11 /13) 2.4.2 Input Parameters The purpose of the boric acid precipitation analysis is to demonstrate that the maximum boric acid concentration in the core remains below the solubility limit, thereby preventing the precipitation of boric acid in the core. If boric acid were to precipitate in the core region, the precipitate could prevent water from remaining in contact with the fuel cladding and, consequently, result in the core temperature not being maintained at an acceptably low value. Therefore, the post-LOCA long term cooling analysis relies on precluding boric acid precipitation for satisfying the requirements of 10 CFR 50.46 Paragraph (b) Item (5). The major input parameters to the boric acid precipitation analysis include core power, boric acid concentrations, and water masses, which are the significant contributors to the containment sump inventory post-LOCA.
Important plant design data and selected input parameters used in the St. Lucie Unit 1 EPU boric acid precipitation analysis are given in Table 6C-2a. 2.4.3 Assumptions The boric acid precipitation analysis was performed with the BORON computer code (Reference 13, Appendix C) using the CENPD-254-P-A post-LOCA boric acid precipitation analysis methodology as modified by the Waterford approach.
The analysis assumptions are broken into three areas: (1) methodology assumptions employed by the Waterford approach (made in response to issues raised by the NRC during review of the EPU report), (2) analysis assumptions made since the Waterford approach (which address additional NRC issues), and (3) general assumptions used in the CENPD-254-P-A post-LOCA boric acid precipitation analysis.
These three areas of assumptions are as follows: Methodology Assumptions Made in the Waterford Approach The following are methodology assumptions employed by the Waterford approach, made in response to issues raised by the NRC during review of the EPU report. The post-LOCA boric acid precipitation analysis for Waterford incorporated a change in the calculation of the mixing volume. The mixing volume is the region in the reactor inner vessel wherein boric acid accumulates as a result of borated water injected by the HPSI, LPSI, and charging pumps replacing the unborated water that leaves the mixing volume in the form of steam produced by boiling in the core. The mixing volume has previously been defined as the entire lower plenum volume and the core region (includes the active core, guide tubes and core barrel/shroud bypass regions) from the bottom of the core to the bottom of the loop seals in the discharge legs. Furthermore, it was assumed that the mixing volume was subcooled, i.e., the void fraction was zero. The following methodology change in the calculation of the mixing volume was employed as a part of the Waterford approach.
St. Lucie Unit 1 follows the Waterford approach, and thus, incorporates this same methodology assumption.
- 1. To calculate the mixing volume, the reactor vessel liquid volume has been divided into three regions, Regions A, B, and C, as shown in Figure 6C-3a. The liquid volume in the core (Region B) and upper plenum (Region C) mixing volumes were calculated by applying the CEFLASH-4AS phase separation model to this region, thereby, incorporating void fraction dependence into the boric acid concentration calculation.
The phase separation model used in CEFLASH-4AS was previously approved by the NRC staff for computing the mixture level in the core following all small break LOCAs (References 17, 18, and 19). This model was shown to accurately predict the void fraction and the two-phase mixture level in regions experiencing high rates of heat addition following small break LOCAs. This methodology change satisfies NRC Item #1 (see Item 2.4.1 ), namely that the mixing volume must be justified and take into account the void fraction.
6C-9b Amendment No. 26 (11/13)
Furthermore, the mixing volume for computing the boric acid concentration was changed to include the additional volume from the top of the core to the top elevation of the hot leg piping at the reactor vessel outlet nozzles (Region C). This liquid volume in the outlet plenum is calculated by applying the core-to-outlet plenum area ratio to the core exit void fraction, which is calculated using the CEFLASH-4AS phase separation model as described above. The selection of the elevation of the top of the mixing volume is validated based on a hydrostatic balance between the head of liquid in the downcomer and the combination of the head of liquid in the mixing volume and the steam flow pressure drop between the core and the break (see Assumption
- 4 below). Lastly, the mixing volume included only 50% of the lower plenum region of the reactor vessel (Region A). Experimental testing simulating the CE designed PWR justified expending the mixing volume to include a portion of the lower plenum. The test results showed that the entire lower plenum volume contributed to the mixing. Hence, crediting only 50% of this volume is conservative.
In summary, the methodology change to the mixing volume in the Waterford approach, and used for St. Lucie Unit 1, is as follows: The volume of liquid in the core (Region B of Figure 6C-3a) was based on calculating the core void fraction axial profile using the CEFLASH-4AS core phase separation model. The volume of liquid in the outlet plenum (Region C of Figure 6C-3a) was based on calculating the core exit void fraction using the CEFLASH-4AS core phase separation model, up to the elevation of the top of the core support barrel nozzles (i.e., nominally, to the top of the hot legs). (Note that the selection of this elevation was validated based on a calculation of system effects. See Assumption
- 4 below). The mixing volume included 50% of the liquid volume of the lower plenum (Region A of Figure 6C-3a). In addition to the methodology assumption regarding the mixing volume, the Waterford approach also incorporated a methodology assumption concerning the mixing of the safety injection flows. 2. The boric acid make-up tank (BAMT) inventory, which is injected via the charging pumps, was mixed with the HPSI pump delivery flow taking suction from the refueling water tank (RWT) during the injection phase of the LOCA. The maximum BAMT concentration used is 6240 ppm whereas the RWT maximum concentration is conservatively set at 2300 ppm. The previously approved model assumed that the BAMT concentration was injected directly into the core without mixing in the cold legs, downcomer, and lower plenum. This methodology assumption is consistent with the NRC-accepted Waterford approach.
Analysis Assumptions Made Since the Waterford Approach The following analysis assumptions were made since the Waterford approach and satisfy NRC Items #2 through #4 (see Item 2.4.1 ). 3. Decay heat is represented with the 1973 ANS Standard (Reference 13). In accordance with NRC Item #4 (listed in Item 2.4.1 ), a 1.2 multiplier is employed for all times. This is a conservative treatment of decay heat following shutdown of the reactor. Previously, as described on page 5 of Amendment 1 to CENPD-254-P-A (Reference 13), the analysis traditionally used a decay heat multiplier of 1.2 up to 1000 seconds and 1.1 thereafter.
6C-9c Amendment No. 26 (11 /13)
- 4. The mixing volume (described in Assumption
- 1 above and shown in Figure 6C-3a) is a time-dependent quantity due to core decay heat, variations in core void fraction and changes to loop pressure drop. However, this variability is not modeled, and instead a constant value is selected for the mixing volume as justified below. As specified in NRC Item #2 (see Item 2.4.1 ), the pressure drop from the core to the break must be considered when calculating the mixing volume. In other words, the selection of the height of the mixing volume was justified with supporting calculations accounting for the loop pressure drop between the core and the break. The two steps of this justification for the height of the mixing volume are as follows: (1) First, the loop pressure drop was conservatively calculated at several time points. (2) Then it was confirmed for all times that the hydrostatic head for the coolant in the downcomer remains greater than the hydrostatic head for the two-phase mixture in the core plus the core to break pressure drop for the selected top elevation of the mixing volume. Any minor impact from steam superheating due to steam generator reverse heat transfer was neglected.
The steam flow rate is maximized by assuming saturated water enters the mixing volume. Frictional losses in the loop pressure drop calculation were increased by roughly 60% for conservatism and the geometric losses were conservatively modeled with a reactor coolant pump locked rotor hydraulic loss coefficient.
- 5. A core/containment pressure of 14.7 psia was used in the boric acid precipitation analysis for this bounding analysis scenario.
The core/containment pressure sets the solubility limit of boric acid in the core. It is also used to determine the saturation properties of the liquid in the core. A value of 14.7 psia (i.e., atmospheric pressure) was used because minimizing the pressure minimizes the solubility limit. A solubility limit of 29.27 wt% was used, which is the solubility limit associated with the saturation temperature of a boric acid solution at atmospheric conditions.
The use of atmospheric pressure is conservatively below the minimum containment pressure during this time period post-LOCA of roughly 20 psia. This assumed core/containment pressure of 14.7 psia is conservatively less than expected system pressures including the loop pressure drop, which would increase the solubility limit beyond that at the assumed 14. 7 psia upper plenum pressure.
Furthermore, basing the solubility limit on atmospheric pressure provides conservative margin to accommodate sudden or rapid depressurization of the RCS in later stages of the emergency response actions for LOCA. Lastly, no credit was taken for increased solubility due to boiling point elevation from the high solids concentration (i.e., the effects of containment sump buffer chemical additives).
Also, the effects of dirt, paint, and general post-LOCA containment debris were neglected.
A solubility limit at a core/containment pressure of 14.7 psia without crediting a sump additive is in accordance with NRC Item #3. General Assumptions Used in the CENPD-254-P-A Methodology The boric acid precipitation analysis evaluation model for St. Lucie Unit 1 was based on the following assumptions and features:
- 6. Boric acid precipitation is prevented by producing a flushing flow through the core via safety injection flows (see Item 2.4.4). For a cold leg break, there is no natural flushing flow, as the safety injection flow would tend to flow around the downcomer and exit the cold legs without being forced through the reactor vessel. For hot leg breaks, however, there is a natural flushing flow created by the safety injection lined up to the cold legs. Simultaneous hot and cold side injection must be aligned in order to produce a flushing flow through the core if the break is in the cold leg. Thus, cold leg breaks are limiting for the boric acid precipitation analysis.
It should also be noted that for a cold leg break, one-quarter of the HPSI flow initially injected into the core spills out the break. There is no spillage if the break is in the hot leg (prior to simultaneous hot and cold side injection).
6C-9d Amendment No. 26 (11/13)
In addition, a large break results in a low reactor coolant system pressure, which yields a conservatively low boric acid solubility limit compared to a smaller break size (see Assumption
- 5 above). Therefore, the use of a large cold leg break scenario is intended to be bounding for all break sizes and locations.
- 7. The boric acid concentration is treated as spatially uniform within the mixing volume (i.e., complete mixing). This has been confirmed by laboratory testing. 8. Uniform concentration of boric acid in the containment sump was assumed. Entrapment of sump fluid in isolated cavities was not considered.
- 9. Without hot side injection flushing flow, the only injection into the reactor vessel used for the boric acid concentration calculation was that flow required to replace core boil-off.
That is, cold side injection flow constantly replenishes the downcomer inventory to the bottom of the cold leg (i.e., the bottom elevation of the cold leg break) as needed to replace core boil-off.
- 10. No credit was taken for subcooling of the injection flow and no condensation of steam was calculated.
This conservatively maximizes core boil-off, which in turn, maximizes boric acid concentration.
- 11. The steam exiting the core is not assumed to contain any boric acid. No credit was taken for boric acid volatility.
Furthermore, it is assumed that any possible boric acid plate-out in the steam generator U-tubes would be negligible considering the primary side flow area of the tubes for core-generated steam and the small amounts of boric acid being considered, and therefore would have an insignificant impact on loop pressure drop calculations.
- 12. Entrainment of liquid from the core during the initial injection phase was neglected.
The entrainment removes large amounts of liquid in the early time period following reflood of the core, which minimizes the boric acid build-up during this period. In later time periods, core inventory carryover was neglected based on confirmatory evaluations that preclude potential entrainment of hot side injection flow after two hours post-LOCA.
- 13. HPSI pump delivery flow to the reactor vessel was conservatively modeled to maximize the boric acid concentration in the core. The worst single failure of ECCS equipment assumed in the boric acid precipitation analysis was the failure of an emergency diesel generator, which results in a loss of one HPSI pump and one LPSI pump. However, the analysis showed that the injection flow rate considering the worst single failure with spillage out the break was still sufficient to replace water lost due to core boil-off.
- 14. For conservatism, minimum HPSI, LPSI, and containment spray pump flow rates were modeled in the boric acid precipitation calculation in order to maximize the duration of injection flow from the RWT. Minimum injection flow rates are sufficient to keep the downcomer filled to the level of the break, so there is no impact on the rate at which inventory is added to the core. Since the RWT boric acid concentration exceeds the calculated concentration in the sump, prolonging the injection flow from the highest concentration source maximizes the rate of boric acid accumulation in the mixing volume. 15. The boric acid precipitation analysis assumes that long term loop seal refilling does not significantly impact the loop pressure drop calculations, which are used to justify the mixing volume. St. Lucie Unit 1 is designed with a loop seal elevation that is above the elevation of the top of the core. Therefore, the loop resistance from possible refilling and re-clearing of the loop seals for breaks located above the bottom of the cold leg is not significant compared to the core and downcomer hydrostatic pressure drops, which dominate the pressure balance analysis in the inner vessel. 6C-9e Amendment No. 26 (11/13) 2.4.4 Description of Analyses and Evaluations Boric acid precipitation is prevented when the appropriate amount of simultaneous hot and cold side injection is provided in a specified window of time. Simultaneous hot and cold side injection provides the flushing flow necessary to ensure that precipitation does not occur, regardless of the break location.
In the boric acid precipitation analysis, the flushing flow is the difference between the reactor vessel injection flow rate and the boil-off flow rate. In particular, boric acid precipitation would be prevented by the safety injection flushing flow to the hot leg for a cold leg break, and by the safety injection flushing flow to the cold legs for a hot leg break. Boric acid precipitation is mitigated for a break in the hot legs by the flow that is produced by the safety injection lineup to the cold legs (i.e., safety injection flows through the cold legs and through the reactor vessel on its way out the hot leg break). In doing so, a flushing flow is created which prevents boric acid from precipitating.
This is not true for cold leg breaks, in which the safety injection flow exits the break and is not forced through the reactor vessel, where the downcomer remains filled to the elevation of the break and thus only core boil-off is replenished (i.e., there is no flushing flow). Thus, the cold leg break is the limiting break location for the boric acid precipitation results. A requirement for simultaneous hot and cold side injection is that the total flow entering the reactor vessel must meet or exceed core boil-off at the early end of the hot and cold side injection time window. If it does not, core uncover could occur. Initiating simultaneous hot and cold side injection no earlier than when the core boil-off drops below the combined injection to the reactor vessel (after accounting for spillage out the break) prevents the potential for core uncovery after the switch-over to simultaneous hot and cold side injection.
At EPU conditions, the boil-off rate will be higher at a given time compared to current conditions.
A decay heat multiplier of 1.2 for all times (addressing NRC Issue #4, see Item 2.4.1 above) also increases the boil-off flow rate compared to earlier methodology assumptions.
Incorporating both will push out the time that simultaneous hot and cold side injection may be initiated compared to current conditions.
This defines the early side of the simultaneous hot and cold side injection window. The end of the simultaneous hot and cold side injection window is determined using calculations of the time that the boric acid concentration in the core reaches the solubility limit (29.27 wt%). Simultaneous hot and cold side injection must be initiated prior to the time at which the solubility limit is reached. The calculation of the mixing volume, or the space in the reactor vessel where boric acid accumulates, is a main driver in determining the rate at which boric acid concentrates in the core. Addressing NRC concerns related to the mixing volume calculation (NRC Issues #1 and #2, see Item 2.4.1 above) decreases the amount of the inner vessel volume that may be credited compared to earlier methodology assumptions.
A smaller mixing volume increases the rate at which the concentration of boric acid rises during the transient, and thus forces the end of the simultaneous hot and cold side injection window to occur earlier in time than calculated for current conditions.
The analysis process included sufficient time between the beginning and end of the simultaneous hot and cold side injection window to allow time for operator action to align simultaneous hot and cold side injection.
2.4.5 Results The results of the post-LOCA boric acid precipitation analysis for EPU along with a comparison to the current results are summarized in Table 6C-3a. The boric acid precipitation analysis determined that minimum simultaneous hot and cold side injection flow rates of 229 gpm to the hot side and 275 gpm to the cold side of the RCS, initiated between four and six hours post-LOCA, maintains the boric acid concentration in the core below the solubility limit of 29.27 wt% for the limiting break (i.e., a large cold leg break). Furthermore, with an injection of 229 gpm to the hot side and 275 gpm to the cold side at six hours, which is the later end of the hot and cold side injection window, the maximum RCS boron concentration was determined to be 29.1 wt%. In addition, it was shown that a flushing flow rate of 20 gpm started at six hours post-LOCA is sufficient to prevent the core boric acid concentration from reaching the solubility limit. With no hot side injection flow, the boric acid concentration was calculated to reach the solubility limit at 9.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. Figure 6C-8a shows the results of the post-LOCA boric acid precipitation analysis by comparing the boric acid concentration as a function of time for no hot side injection, 229 gpm of hot side injection initiated at 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> post-LOCA, and a 20 gpm core flushing flow initiated at 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> post-LOCA.
6C-9f Amendment No. 26 (11/13)
In separate studies, the analysis also determined that the potential for entrainment of the hot let injection by the steam flowing in the hot legs ends prior to two hours post-LOCA.
Figure 6C-7a shows the reactor vessel flow rate comparison, which confirms a more generalized statement of the result that the minimum simultaneous flow rate to the hot and cold legs of the RCS, after accounting for spillage out the break, must equal or exceed core boil-off at the time the simultaneous injection is initiated.
The impact of the EPU and of the NRC imposed methodology changes increased the required minimum simultaneous hot and cold side injection flow rate as follows: (1) from 190 gpm for the current condition to 229 gpm to the hot side for the EPU, and (2) from 235 gpm for the current condition to 275 gpm to the cold side for the EPU. These results require a minimum hot and cold side injection flow rate of 229 gpm to the hot side and 275 gpm to the cold side to be available within the four-to six-hour window post-LOCA for the EPU. The EPU post-LOCA boric acid precipitation analysis demonstrated that the four-to six-hour switchover time window for simultaneous injection remains acceptable to control boric acid concentration and prevent boron precipitation in the core. This switchover time is also shown to be after the time that entrainment of the hot side injection is predicted to occur. Also, the core is assured to remain covered with a two-phase mixture as the total flow rate entering the reactor vessel meets or exceeds the core boil-off rate at the early end of the switchover time window. 2.4.6 Conclusions Based on the results of this analysis, it is concluded that for St. Lucie Unit 1 for EPU, a minimum simultaneous hot leg and cold flow rates of at least 229 gpm to the hot side and at least 275 gpm to the cold side of the RCS in place between four and six hours (inclusive) after the start of the LOCA is required to maintain the core boric acid concentration below the boric acid solubility limit following a large break LOCA. This value is consistent with the maximum switchover time of six hours due to post-LOCA criticality as described in Item 2.5.1. The earliest time to initiate simultaneous hot leg and cold leg injection is four hours. This is determined from the more limiting of time when: 1. the hot leg steam velocity falls below a value that would entrain the hot side injection as determined by the boric precipitation reanalysis, and 2. the injection flow rate considering a single failure spillage out the break is sufficient to replace water lost to core boil-off for both hot and cold leg breaks, which is based on a minimum hot leg injection flow of 229 gpm and a minimum cold leg injection flow of 275 gpm for the simultaneous hot/cold leg injection configuration.
The design analysis demonstrates conformance to criteria for Long Term Cooling within the ECCS acceptance criteria of 10 CFR 50.46. 6C-9g Amendment No. 26 (11 /13)
REFERENCES TO SECTION 2.0 (1) D.E. Byrnes, WE. Foster, WCAP-1570, January 1961. (2) Cohen, "Water Coolant Technology of Power Reactors", Gordon and Breach, New York 1969. (3) U. S. Borax and Chemical Corporation Technical Bulletin.
(4) E.L. Muetterties, The Chemistry of Boron and Its Compounds, Wiley, New York 1967. (5) N.H. Nachtrieb, R. Noma, Inorganic Chemistry, 6, 1189, 1967. (6) D. Smith, Jr., R.J. Wiersema, Inorganic Chemistry.
Vol. II No. 5, 1972, 1152-1154.
(7) H.A. Klein, "Use of Coordinated Phosphate Treatment to Prevent Caustic Corrosion in High Pressure Boilers", Combustion, October 1962. (8) Handbook of Chemistry and Physics, 50th Edition, 1969-1970.
(9) CENPD-137P C-E Topical Report (Proprietary) "Calculative Method for the C-E Small Break LOCA Evaluation Model" August 197 4. (1 O) G.B. Wallis, "One Dimensional Two Phase Flow", McGraw Hill, 1969. (11) Fischer and Porter Engineering Report DP #2224-1, Report #002, September 14, 1970. (12) ABB Letter F2-99-077, G. Gurdip (ABB) to R.J. Rodriguez (FPL), "Transmittal of Design Analysis Report for Post-LOCA Boric Acid Precipitation for St. Lucie Unit 1," July 19, 1999. (13) CENPD-254-P-A, "Post-LOCA Long Term Cooling Evaluation Model," June 1980. (14) NRC Letter "Suspension of NRC Approval for use of Westinghouse Topical Report CENPD-254-P, 'Post-LOCA Long-Term Cooling Model,' Due to Discovery of Non-Conservative Modeling Assumptions During Calculations Audit", R. A. Gramm, August 1, 2005. (ADAMS No. ML051920310)
(15) NRC letter "Clarification of NRC Letter Dated August 1, 2005, Suspension of NRC Letter "Clarification of NRC Letter Dated August 1,2005, Suspension of NRC Approval for Use of Westinghouse Topical Report CENPD-254-P, 'Post-LOCA Long-Term Cooling Model,' Due to Discovery of Non-Conservative Modeling Assumptions during Calculations Audit (TAC No. MB1365),
D.S. Collins, November 23, 2005. (ADAMS No. ML053220569)
(16) S. E. Peters (NRC) to S.L. Rosenberg (NRC), "Summary of August 23, 2006 Meeting with the Pressurized Water Reactor Owners Group (PWROG) to Discuss the Status of Program to Establish Consistent Criteria for Post Loss-of-Coolant (LOCA) Calculations," October 3, 2006. (ADAMS No. ML062690017)
(17) CENPD-133, Supplement 3-P, "CEFLASH-4AS, A Computer Program for the Reactor Slowdown Analysis of the Small Break Loss of Coolant Accident," January 1977. (18) CENPD-137, Supplement 1-P, "Small Break Model, Calculative Methods for the C-E Small Break LOCA Evaluation Model," January 1977. (19) K. Kniel (NRC) to A. E. Scherer (C-E), "Evaluation of Topical Reports CENPD-133, Supplement 3-P and CENPD-137, Supplement 1-P," September 27, 1977. 6C-12b Amendment No. 26 (11/13)
TABLE 6C-2 PLANT DESIGN DATA USED IN THE PRE-EPU BORIC ACID PRECIPITATION ANALYSIS Parameter Rated core power Power measurement uncertainty Maximum RCS boron concentration BAMT parameters Maximum number of tanks Maximum liquid volume per tank Maximum boric acid concentration Minimum liquid temperature RWf parameters Maximum volume Maximum boron concentration Minimum liquid temperature SIT parameters Pumps Maximum number of tanks Maximum liquid volume per tank Maximum boron concentration Minimum liquid temperature Maximum pressure Maximum number of charging pumps Minimum number of HPSI pumps Minimum number of LPSI pumps Minimum number of CS pumps Maximum charging pump flow rate Minimum flow HPSI delivery curve Minimum flow LPSI delivery curve Minimum CS pump flow rate RCS Geometry Hot Leg Diameter Pump Discharge Leg Diameter Pump Suction Leg Diameter Distance from Bottom of Inside of Suction Leg to Centerline of Reactor Vessel Inlet Nozzle Distance from Bottom of Inside of Discharge Leg to Bottom of Active Core Core Flow Area Guide Tube Flow Area Core Barrel/Shroud Bypass Flow Area Lower Plenum Volume Maximum RCS Water Mass 2700 Mwt 2% 2440 ppm 2 9975 gal 4.0 wt% 36F 705,000 gal 2700 ppm 51F 4 1202 ft 3 2700 ppm 85.5F 265 psig 3 1 1 1 49 gpm Ref. 12 Ref. 12 2700 gpm 42 inches 30 inches 30inches 87inches 15. 7 ft 53.46 ft 2 6.34 ft 2 11.25 ft 2 871 .5 ft 3 526,000 lbm 6C-13c Amendment No. 26 ( 11 /13)
TABLE 6C-2a PLANT DESIGN DATA USED IN THE EPU BORIC ACID PRECIPITATION ANALYSIS Parameter Analyzed reactor core thermal power level (includes uncertainty)
Maximum RCS boric acid concentration Decay heat multiplier BAMT parameters Maximum number of tanks Maximum liquid volume per tank Maximum boric acid concentration Minimum liquid temperature RWT parameters Maximum volume Maximum boric acid concentration Minimum liquid temperature SIT parameters Maximum number of tanks Maximum liquid volume per tank Minimum boric acid concentration Maximum liquid temperature Maximum pressure Pump parameters Maximum number of charging pumps Minimum number of HPSI pumps Minimum number of LPSI pumps Minimum number of containment spray pumps Maximum charging pump flow rate per pump Flow rates for emptying the RWT Minimum flow HPSI delivery Minimum flow LPSI delivery Minimum containment spray pump flow rate RCS parameters Hot leg diameter Pump discharge leg diameter Pump suction leg diameter Distance from bottom of loop seal to centerline of reactor vessel inlet nozzle Distance from bottom of discharge leg to bottom of active core Distance from the top of the active core to the bottom of the reactor vessel Distance from the top of the loop seals to the bottom of the reactor vessel Core flow area Guide tube flow area Core barrel/shroud bypass flow area Lower plenum volume Maximum RCS water mass Mixing volume RCP locked rotor K-factor for forward flow 3030 MWt 2200 ppm 1.2 2 9975 gal 6240 ppm 51°F 580,000 gal 2300 ppm 51°F 4 1202 ft 3 2300 ppm 85.5°F 295 psig 3 1 1 1 49 gpm Ogpm 1962 gpm 2550 gpm 42 inches 30inches 30inches 7.25 ft 15. 7 ft 21.58ft 22.41 ft 54 ft 2 6.34 ft 2 11.25 ft 2 871.5 ft 3 469,000 lbm 7800 gal 13.39 6C-13ca Amendment No. 26 ( 11 /13)
TABLE 6C-3
SUMMARY
OF RESULTS PRE-EPU Parameter Boric acid solubility limit Time boric acid concentration reaches solubility limit with no hot side injection Minimum simultaneous hot side and cold side injection flow rates Hot Side Cold Side Initiation time for simultaneous hot and cold side injection Maximum core boric acid concentration with 190 gpm of simultaneous hot and cold side injection started at 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> Maximum core boric acid concentration with 20 gpm flushing flow Initiated at 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> 6C-13d 27.6wt% 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 190 gpm 235 gpm 4 to 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> post-LOCA 25.1 wt% at 10. 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> post-LOCA 25 wt% at 10.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> post-LOCA Amendment No. 26 (11 /13)
TABLE 6C-3a
SUMMARY
OF RESULTS FOR THE EPU BORIC ACID PRECIPITATION ANALYSIS EPU Analysis CENPD-254-P-A Methodology Modified by the Waterford Approach Parameter Boric acid solubility limit Time boric acid concentration reaches solubility limit with no hot side injection Minimum simultaneous hot and cold side injection flow rates Hot Side Cold Side Initiation time for simultaneous hot and cold side injection Maximum core boric acid concentration with 229 gpm of hot side injection and 275 gpm of cold side injection started at 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Maximum core boric acid concentration with 20 gpm flushing flow initiated at 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Current AOR CENPD-254-P-A Methodology Parameter Boric acid solubility limit Time boric acid concentration reaches solubility limit with no hot side injection Minimum simultaneous hot and cold side injection flow rates Hot Side Cold Side Initiation time for simultaneous hot and cold side injection Maximum core boric acid concentration with 190 gpm of simultaneous hot and cold side injection started at 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> Maximum core boric acid concentration with 20 gpm flushing flow initiated at 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> 6C-13e EPU Result 29.27 wt% 9.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> 229 gpm 275 gpm 4 to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> post-LOCA 29.1 wt% at 9.9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> post-LOCA 29.1 wt% at 6.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> post-LOCA Pre-EPU Result 27.6 wt% 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 190 gpm 235 gpm 4 to 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> post-LOCA 25.1 wt% at 10.7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> post-LO CA 25 wt% at 10.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> post-LOCA Amendment No. 26 (11 /13)
HOT LEG COLD LEG A £ LOWER PLENUM TO BOTTOM OF CORE (EXCLUDING ANNULUS) B
- CORE REGION C
- TOP OF CORE TO SOTTQM OF HOT LEG Amendment No. 26 (11 /13) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 REACTOR VESSEL REGIONS Figure 6C-3 (Historical)
HOT LEG / , ( / / ,, / 7/ ,, U// (/* 0 r/J c /o/ o c// COLD LEG A= '12 LOWER PLENUM TO BOTIOM OF CORE (EXCLUDING ANNULUS) B =CORE REGION (INCLUDING VOIDS) C =TOP OF CORE TO TOP OF CSB NOZZLES (INCLUDING VOIDS) Amendment No. 26 (11/13) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 REACTOR VESSEL REGIONS Figure 6C-3a
- ! a... CJ ui 500 400 300 a: 3: 0 _J u. 200 100 0 0 .... .* i Simul!anaous HoVCold Side Injection Started at 10 Hours Core Flushing Flow :::: Hot Side Injection Rate -Boilott Rate . , .. r. 2 . I ... 4 6 Hot Sfde Injection Aale BoiloH Rate 8 10 .I .. .. *. I . 12 14 16 TIME AFTER LOCA, HOURS Amendment No. 26 (11/13) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 COMPARISON OF CORE BOILOFF RATE AND HOT SIDE INJECTION FLOW RATE OF 190 GPM FIGURE 6C-7 (Historical) 600 -_l __ 500 400 Cl.. QJ 300 .+.J l1J 0 u:: 200 100 0 0 5 Comparison of Core Boiloff Rate and Hot Side Injection Flow Rate of 229 GPM I I _, I I I I l I
' --Boiloff Curve ------HSL=229 GPM at 6 hrs 10 15 20 25 nme After LOCA (hrs) Amendment No. 26 (11 /13) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 COMPARISON OF CORE BOILOFF RATE AND HOT SIDE INJECTION FLOW RATE OF 229 GPM FIGURE 6C-7a z 0 t= <( a: 1-z L1.J u z 0 u g u ..;::: 48 40 32 24 S2 16 a:: 0 co 8 0 0 ,. '*j Simultaneous Hot/Cold Side Injection Started at 1 O Hours Hot Side Injection Rate:: 190 GPM ------------------
, I. 2 4 No Core Flushing Core Flush = Hot Side
- Boiloff Coro;1 F=iu.,h 20 GPM Solubility Limit .. 27.6 WT% '** . ' 1 ' .I ... 6 8 10 12 14 TIME AFTER LOCA, HOURS Amendment No. 26 (11 /13) 16 FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 CORE BORIC ACID CONCENTRATION VERSUS TIME FIGURE 6C-8 (Historical) 40 30 ----,...__ ! c: 0 .. I'll .... .... c: 20 8 c: 0 u I '"C *c < u *;:: I 0 CD 10 I I I I 0 0 4 Core Boric Acid Concentration VS lime / / v ,J -----
,._ __ .._ __ --.. '* v ... .. I .... v .... .. I ' . ' .. ... .. I' ........ *--...... -. ....... _ ... ..,.. ----NOHSI v ----I', ' .. .. .. .. .. .. .. ......._ ...... _ ..
' .. ... .. ----Solubility Limit (29.27 wt%) -----------
229 gpm HSI at 6 hrs --.... _____ ' .. ... , ..... .. --------20 gpm Flushing Flow at 6 hrs 8 12 16 20 lime After LOCA (hrs) Amendment No. 26 (11 /13) FLORIDA POWER & LIGHT COMPANY ST. LUCIE PLANT UNIT 1 CORE BORIC ACID CONCENTRATION VS TIME FIGURE 6C-8a