Overview of Korean-Type PWR Simulator Prepared for IAEA TM (Vienna, Austria, May 19-22, 2014) KIM, Kyung Doo ([email protected])
Download ReportTranscript Overview of Korean-Type PWR Simulator Prepared for IAEA TM (Vienna, Austria, May 19-22, 2014) KIM, Kyung Doo ([email protected])
Overview of Korean-Type PWR Simulator Prepared for IAEA TM (Vienna, Austria, May 19-22, 2014) KIM, Kyung Doo ([email protected]) 1 Table of Contents Nuclear Power Plants in Korea Introduction of the Korean-Type Simulator Overview of a Korean-Type PWR Systems Simulation Examples 2 Korea at a Glance Difficult Environment Small Land, High Population, Rare Natural Resource, Divided Country Land size 99,000 km2 (108th) 50Mth Baby Girl born on June 23, 2012 Energy Consumption 9th, Oil Consumption 7th, Oil Import 4th Fastest Developed Country Good Quality of Human Resource, High Level of Technology, Diversified Industry Trade > 1,000B$ (7Th) (0.1B$ in 1965) Per Capita Income: 22,750$ (2012) Enter 20-50 Club (US, Japan, German, France, UK, Italy, Korea) Nuclear Energy played important Role 3 Korean Economy and Nuclear Nuclear Energy Locomotive to Korean Economy Nuclear is always revitalize the Korean Economy! 22,424$ (2011) 21,590$ (2007) Per Capita Income (US$) Enter OECD (1996) 12,250$ HANARO operation (1995) 5,000 KORI#1 Operation (1978) 1,383$ 7,463$ (1998) First OPR1000 67$ 1945 1953 Liberation Korean War from Japan (1950-53) (1945) 1959 (2009) Export to UAE and Jordan 10,000 TRIGA II Start (1959) 89$ 17,000$ 1970 1978 1980 1990 1995 1998 2007 Korea US Subprime Financial Crisis Mortgage Crisis (1977.12) (2007) Source : Bank of Korea 4 Nuclear Power in Korea In Operation As of December 2011 – 21 Units Installed Capacity Total Nuclear • 17 PWRs (7 OPR1000) • 4 PHWRs at Wolsong : 79.3 GWe : 18.7 GWe (23.6%) Under Construction Electricity Generation Total Nuclear – 3 OPR1000 – 4 APR1400 : 496.9 TWh : 154.0 TWh (31.0%) Planned by 2022 – 4 APR1400 Seoul Yonggwang Ulchin Wolsong Kori Long-term Energy Policy – 59% share of nuclear in electricity generation In operation Under construction Preparation for Construction OPR1000 APR1400 5 KAERI Overview KAERI Overview The sole national nuclear R&D research institution in Korea Nuclear basic research New reactor development Fuel cycle technology development (front-end & back-end) Nuclear safety research Research reactor utilization Radiations/radioisotopes applications Manpower training, policy study, etc. Founded in 1959 (the 1st government-support R&D institution) Founder of many nuclear power related organizations, including KOPEC, KNF, and KINS ~1,300 regular staff 6 Introduction of the Korean-Type Simulator 7 Special Features Calculation engine based on a best-estimate system analysis code Realistic system TH simulation with very high fidelity Simulators which use overly simplified models and assumptions for a real-time simulation may entail inaccurate results. may result in “negative training”, especially for complicated two-phase flows conditions. Wide range of simulation capability Normal operation to DEC. Simplified reactor neutronics calculation : Point Kinectis Better for accident simulation. It can easily adapted for other plants (not provided) Plant Independent input feature It can run by itself without any additional graphics software No commercial graphic software such as LabView, DataView, etc. 8 OECD PKL-3 (SBO) SG 4 SG 1 SG 2 SG 3 psec = 21 bar psec = 1 bar psec = 1 bar psec = 20 bar Main steam header not available pprim CET PCore PRZ: = 45 bar = 295 °C = 347 KW HPRZ~ 9.1 m 256 Quasi-constant PRZ-level during 1Φ-discharge 257 °C 257 257 257 257 256 257 257 257 257 295 °C 0 kg/s 0 kg/s 0 kg/s 0 kg/s Relation PCT - CET 256 °C 9 Main Functions of This Simulator Online X-Y Trend Graphic Pre-determined trend graph in trend graph window Any parameter can be selected for trend graph by a user. Visualization of entire system behavior System mimic with several gauges Nodalization map for overall plant properties (boron, void, liquid/gas temperature,..) Interactive control Simplifying control input for complex manual operation, e.g., EOP. Miscellaneous functions Engineering unit conversion 10 Project Tab Active Project Setting 1. Open Project 2. File selection – Drag and drop – Type the file names Unit selection 1.SI/British/IAEA definition Initialization 11 Calculation Tab Stop Trend Graph Run Selected Minor edit variable information Minor edit variable selection Selected Volume information Volume selection User defined Engineering unit Junction selection Selected Junction information 12 System Mimic Tab Can design a mimic from provided indicators User can add indicators, remove, set indicator and map with output variable Provided Indicators Object Inspector Variable Mapping 13 Nodalization Tab Volume properties can be shown in color spectrum User can change the range for color spectrum Click trend menu for the specific volume Spectrum bar for Void/Temperature/Boron Color spectrum range change 14 Interactive Control Tab Interactive Control Simulate the operator’s action during transients On/Off switch, flow rate, valve opening area, heater power, reactivity control Auto/manual selection On/Off Switch Flow rate control Target value Rate Trip Message Window Display trip occurring time and its description Help the understanding for transient behavior Valve area control 15 Trend Graph Tab Trend Graph Important variables in trend tab (shown in trend graph tab) Click “Trend button” during the transient execution (in separate window) Click trend menu for the specific volume in nodalization window (in separate window) Can save the data in text format 16 Formation of the Manual (I) The manual consists of ; Overview 2. TWO-LOOP LARGE PRESSURIZED WATER REACTOR SIMULATOR 1. 2.1 2.2 2.3 2.4 2.5 3. Simulator startup Simulator initialization Event and/or malfunction initiation List of Two-Loop Large PWR simulator display screens Overview of the Target Plant OPERATIONAL TRANSIENT EVENTS 3.1 3.2 3.3 3.4 Reactor power reduction Reactor power increase Reactor trip Turbine trip 17 Formation of the Manual (II) 4. MALFUNCTION TRANSIENT EVENTS 4.1 4.2 4.3 4.4 4.5 4.6 5. Loss of Main Feedwater Flow Single RCP trip Steam generator tube rupture Cold Leg #1 SBLOCA Cold Leg #1 LBLOCA Station Blackout MODEL DESCRIPTION 5.1 5.2 5.3 5.4 Reactor kinetic model Hydrodynamic model Reactor control system Protection system 18 OPR 1000 Simulator’s NSSS Model 966 ADV ADV 967 926 924 964 Safety Valve Safety Valve 923 963 927 MSIV 960 01 02 920 03 MSIV MSIV 940 02 01 02 01 03 02 01 900 MSIV 03 965 03 925 980 945 Safety Valve 01 ADV 947 905 ADV 943 Safety Valve 907 903 02 790 690 946 MFW MD AFW 778 704 716 780 944 MFW 03 906 904 778 678 680 678 670 660 670 650 05 610 04 760 770 723 770 715 MD AFW 604 616 623 615 05 712 710 713 04 720 Steam line bypass 710 05 750 610 987 985 994 720 718 01 07 01 06 Atmospheric volume Legend 03 292 05 08 02 01 06 02 290 Time dependent volume 05 08 Junction 04 10 01 03 03 740 02 11 724 260 02 222 03 230 270 030 420 410 01 400 02 460 01 02 02 02 01 03 01 200 110 112 110 470 455 454 462 02 03 Chargin g 04 466 477 LPSI 476 120 190 120 122 606 132 180 03 02 02 488 03 01 487 04 160 482 472 024 491 492 14 13 12 11 10 09 08 07 06 05 04 03 02 01 170 Letdown RCP - 2B 330 453 130 300 01 310 02 320 380 014 SIT 392 03 04 391 372 03 388 04 387 LOOP 2 486 LPSI RCP -1A 375HPSI 374 377 376 LPSI 382 04 03 366 362 02 01 RCP -1B 385 01 05 05 384 HPSI SIT 140 SIT 150 396 484 HPSI 496 485 02 364 378 013 012 370 05 452 350 360 390 01 02 607 280 019 011 022 01 SIT 12 10 021 023 474 01 01 MFW 020 394 05 478 HPSI 475 494 RCP -2A 490 480 11 381 481 464 02 02 08 240 220 03 03 630 624 07 09 029 01 242 250 10 03 640 06 430 01 03 05 Cross flow junction 707 450 01 04 01 01 12 09 04 03 Valve 730 706 02 Time dependent junction 01 02 02 02 09 MFW TD AFW 01 02 03 618 01 07 03 Safety valve 293 291 SDS Valve Volume 02 620 340 294 990 613 04 620 440 TD AFW 612 04 386 LPSI 03 02 LOOP 1 19 Overview of Korean-Type PWR Plant 20 Pressurized Water Reactor Characteristics of Pressurized Water Reactor The nuclear reactor core is cooled by pressurized water PWR keeps water under pressure (~15.5 MPa) so that the reactor coolant water does not boil during normal operation. It consists of the primary and the secondary cooling system. Most of the radioactivity stays in the primary cooling system. 21 Ulchin NPP Unit 4 22 OPR-1000 Main Parameters Thermal/Electric Power : 2,825MWth/1,050MWe Plant Design Life : 40 years RCS : 2 Loop Design Refueling cycle : 12 – 18 months OPR1000 : 10 + 2 Units Ulchin Unit 3,4,5&6 Yonggwang Unit 3,4,5&6 Shin-kori 1,2 Shin-wolsong 1,2(Const.) 23 OPR-1000 Systems NSSS, Nuclear Steam Supply System Main Steam System Containment atmospheric dump valve main steam safety valve Containment spray header main steam isolation valve pressurizer safety valve Chemical and Volume Control System downcomer feedwater control valve RDT filter steam generator 1 safety depressurization system pressurizer volume control tank safety injection tank reactor vessel letdown heat exchanger reheater drain tank economizer feedwater control valve charging pump charging control valve regenerative heat exchanger boric acid make-up pump reactor drain tank containment recirculation sump refueling water tank deaerator storage tank HP heater 7 HP heater 6 separator drain tank intercept valve HP heater 5 intermediate valve LP turbine (3EA) HP extraction steam turbine bypass to condenser sea water from intake hot well train A high pressure safety injection pump train B containment spray pump sea water to discharge duct LP extraction steam LP heater 1 Shutdown Cooling System shutdown cooling heat exchanger Generator condenser LP heater 2 HP extraction steam low pressure safety injection pump deaerator storage tank level control valve LP extraction steam reactor coolant pump in-core instrument deaerator 1st stage reheater reheater drain tank condensate pump letdown orifice auxiliary charging pump 2nd stage reheater HP turbine control rod ion exchanger moisture separator reheater stop valve control valve steam generator 2 LP extraction steam HP heater 7 cold leg HP heater 6 HP heater 5 LP heater 3 feedwater feedwater pump booster pump Feedwater System BOP, Balance of Plant hot leg containment spray Safety Injection System 24 Major Components of Reactor Coolant System 25 Reactor Coolant System RCS provides a circulating water through the reactor and steam generator(SG) to Transfer heat from reactor to the SG Provides a moderator for neutrons Provides a solvent for boric acid A boundary to contain radioactive fluid fission products PZR RCP 1B SG 1 RCP 1A RCP 2A Reactor Vessel SG 2 RCP 2B 26 Reactor Coolant Temperature Reactor Coolant Temperature Thot Tavg 296℃ No Load(0%) Steam Generator Power (%) Tcold 327℃ 311℃ ΔT=31℃ 296℃ 100% F.P 27 OPR-1000 Systems –Reactor Vessel/Cor e core Nuclear fissions occur at the reactor Reactor vessel Reactor internals Inlet Nozzles Outlet Nozzles Incore instrumentation penetrations Control element drive mechanism nozzles Reactor Core Fuel assemblies (177) Control element assemblies (CEAs) (73) Fixed incore instruments (45) Core Thermal Hydraulics Minimum Departure from Nucleate Boiling Ratio (MDNBR) Maximum fuel centerline temperature 28 OPR-1000 Systems – Nuclear Fuel Fuel Uranium used to obtain the chain reaction in oxide form (UO2) Melting point of UO2 is approximately 2,800℃ Small pellets stacked in a leak-tight metal tube (Fuel Rod). It is essential to prevent fission products from leaking into the primary system Fuel rods are arranged in a Fuel Assembly Fuel Assembly is composed of 236 fuel rods (16 X 16) Reactor Core consists of 177 Fuel Assemblies 29 Initial Fuel Loading and Reactor Cavity 30 Establishment of Reactor Head Assembly 31 OPR-1000 Systems –NSSS Components Steam Generators: Heat sink of the primary side Barrier between primary and secondary system Inverted U-tube type vertical SG Integral economizer Steam separators Steam dryers Two outlet nozzles 32 A Schematic of the Steam Generator Steam Outlet(2) Dryer(8) Moisture Separator(144) Recirculation Nozzle(1) Tube Bundle(8,214) Coolant Inlet Nozzle(1) Feedwater Ring Economizer Nozzle(2) Coolant Outlet Nozzle(2) 33 Installing a Steam Generator 34 OPR-1000 Systems:Reactor Coolant Pumps RCP provides forced recirculation flow in the RCS. Vertical pump with bottom suction and horizontal discharge Single stage centrifugal type driven by motor with anti-reverse rotation device Flywheel on the shaft under the motor provides additional inertia to extend pump coastdown. Leakoff is controlled by three shaft seal. Normal pump speed : 1,190rpm 35 OPR-1000 Systems –Pressurizer Pressurizer is connected to the hot leg via the surge line RCS Pressure Control: Spray, Heaters, Valves PZR Volume: 1,800ft3 (Liquid/Vapor : 50/50) filled with saturated water and steam Heater Capacity: 1,800kW (36 Elements) Heater Type: Immersion • Overall length : 12.9 m • Shell diameter : 2.4 m • Weight(dry) : 108 ton Pressurizer 36 RCS Pipings Flow per Cold Leg: 30.4×106 lb/hr Flow per Hot Leg: 60.8×106 lb/hr Pipe Size(Inside Diameter) Hot Leg: 42 inch Cold Leg: 30 inch Pipe Design Press.: 175kg/㎠ Pipe Design Temp.: 345℃ 37 MALFUNCTION TRANSIENT Simulation 4.1 Loss of Main Feedwater Flow 4.2 Single RCP trip 4.3 Steam generator tube rupture 4.4 Cold Leg #1 SBLOCA 4.5 Cold Leg #1 LBLOCA 4.6 Station Blackout 38 Loss of Primary Flow 39 Categorization of Initiating Event According to their frequency of occurrence AOO ( Anticipated Operating Occurrence) Expected during the plant life time (> 10-2 event/r-yr) DBA (Design Basis Accident) Unexpected but should be considered in design ( > 10-4 ~ -6 event/yr) BDBA (Beyond BDA) SA (Severe Accident) According to the types of accident (PWR) Reactivity Induced Accident (i.e. RIA) Decrease of reactor coolant flow Increase of reactor coolant inventory Increase of heat removal by the secondary side Decrease of heat removal by the secondary side Decrease of reactor coolant inventory 40 Loss of Flow Accident Typical DBTs for Loss of Flow Accident (LOFA) Single or Multiple Main Coolant Pump (MCP) Trip Inadvertent Closure of Main Isolation Valve in a Primary Loop Seizure of One MCP or Shaft Break of One MCP Coolant Flow Blockage in a Fuel Assembly Comparison with LOCA (Loss of Coolant Accident) LOCA: Loss of primary coolant inventory LOFA: Loss of primary forced cooling but inventory preserved Major concerns LOCA : Peak Cladding Temperature (PCT) LOFA : minimum DNBR or Critical heat flux ratio (CHFR) 41 Major Phenomena of LOFA Primary flow rate decrease Core outlet temp. ↑ due to flow reduction ( Q mCpTcore,out in) Heat transfer to S/G ↓ due to flow reduction Core inlet (S/G outlet) & fuel temperature ↑ RCS TAVG↑ RCS coolant volume ↑ PRZ level ↑ PRZ pressure ↑ Critical heat flux (CHF) is reduced by flow reduction and fuel temperature increases CHF could occur!! If CHF condition is reached, some fuel rod cladding should be damaged 42 Pool Boiling Curve DNB point CHF Mass flux ↓ : plant condition during LOFA Surface temperature , Ts ↑ 43 IAEA Classification (1/4) Single or Multiple Main Coolant Pump (MCP) Trip Cause Interruption of power supply or failure of control system Results Slow reduction of primary flow rate due to inertia of pump rotor (a few hundred seconds) Imbalance between power generation and heat removal Pressurization of primary system and possibility of DNBR occurrence Classification Anticipated Operational Occurrence (AOO) Transient Acceptance criteria – Min. DNB < Design value (~1.3) (fuel integrity) – RCS & S/G pressure < 110% of design value (structural integrity) – No fuel melting 44 IAEA Classification (2/4) Inadvertent Closure of Main Isolation Valve in a Primary Loop Applicable only when main isolation valves exist in primary loop There is no main isolation valve in Korean-type PWR No need to consider this accident! 45 IAEA Classification (3/4) Seizure of One MCP or Shaft Break of One MCP Cause Mechanical damage of MCP instant pump stop (within 1 s) Results Similar to one MCP pump trip Classification Accident (DBA) Acceptance criteria – Peak cladding temp. (PCT) < 1480℃ (typical) – RCS & S/G pressure < 110% of design value (structural integrity) – Partial fuel melting allowed (maximum 10% of fuel volume at hot spot) 46 IAEA Classification (4/4) Coolant Flow Blockage in a Fuel Assembly Cause Presence of debris in primary loop Results Total or partial coolant flow reduction in fuel assembly Sudden imbalance between power generation and heat removal (possibility of DNBR) Negligible impact on overall core flow because debris is very small in most cases. However, its impact on DNBR should be considered when flow blockage occurs in hot channel. Classification Accident (DBA) Acceptance criteria is the same as seizure of 1 MCP accident 47 LOFA Event Sequences (1/4) Single Main Coolant Pump (MCP) Trip Anticipated Sequences One primary loop flow slowly decreases Low primary loop flow signal occurs (typically 80~90% of nominal flow) Reactor scram and Turbine trip Reverse flow occurs in failed loop after pump coastdown ends while intact loop flow slightly increases Plant will be stabilized at hot stand-by due to heat removal via remaining intact loop 48 LOFA Event Sequences (2/4) Multiple Main Coolant Pump (MCP) Trip Anticipated Sequences All primary loop flows slowly decrease simultaneously Low primary loop flow signal occurs (typically 80~90 % of nominal flow) Reactor scram and Turbine trip Natural circulation is established after pump coastdown ends Primary pressure would increase but pressurizer safety valve or spray could control overpressurization Plant will be stabilized nearby hot stand-by due to natural circulation in primary loop 49 LOFA Event Sequences (3/4) Seizure of One MCP or Shaft Break of One MCP Anticipated Sequences (similar to one MCP trip) One primary loop flow sharply decreases Low primary loop flow signal occurs (typically 80~90% of nominal flow) Reactor scram and Turbine trip Reverse flow could occur in failed loop while intact loop flow slightly increases Primary pressure would increase but pressurizer safety valve or spray could control overpressurization Plant will be stabilized at hot stand-by due to heat removal via remaining intact loop 50 LOFA Event Sequences (4/4) Coolant Flow Blockage in a Fuel Assembly Anticipated Sequences Single fuel assembly is blocked partially by small debris No major symptom or warning sign from plant detection system No reactor scram and no turbine trip Coolant Finally, and fuel cladding temperature in blocked channel will increase DNBR could occur in blocked fuel assembly In case of open channel, temperature rise could be restricted by crossflow from adjacent channel 51 LOFA Simulation 52 Single RCP Trip Initiated by setting the single RCP trip during the nominal operating condition. This event is an accident but the transient behavior is very similar to operational transient after reactor trip by reactor protection system. 1. Click the execution file ‘APWRSimulator_visa.exe’ to start a simulation. It will automatically load the input file (100ic_NLOCA_r3.i) and the corresponding restart file of 100ic.r for 100% nominal operating condition. 2. Press “OK” button in project tab for initialization. 3. Press “Run” speed button to simulate the 100% nominal power condition. 4. Enter the data saving frequency in the dialog box a number of time advancement a time interval 5. Pause in the simulation at 10 s Speed button in upper part Set the time to pause. 53 Single RCP Trip 6. Move to “interactive tab” to initiate the transient. 7. Change the selection box from automatic to manual in “RCP 1A trip” line. 8. Press the toggle switch for trip status in target column to be true. Then the toggle switch will change the color from green to red. 9. Then, resume the execution by speed button in top left corner. Interactive Control Tab before and after single RCP trip 54 Single RCP Trip Before initiating single RCP trip, Reactor Power PRZ and SG Pressure you can confirm if the calculation is reached the steady state condition by examining the trend graphs for reactor power, pressurizer and steam generator pressures, etc. 55 Single RCP Trip At 30 s RCP 1A speed is slowly coast-down due to large flywheel with large inertia. The speed for remaining RCPs is maintained with same speed. Loop 1A flow is decreasing and negative flow is established due to the pump head developed in loop 2A and 2B pumps. Loop 1B flow is increasing since the pump head in loop 1A is decreased. Loop 2A and 2B flow are maintained almost same as before. Pump speed Cold leg flow 56 Single RCP Trip At 30 s Reactor is scrammed with 2 seconds delay due to low loop 1A flow signal at ~7 s. Turbine is tripped due to reactor trip signal. As soon as turbine trip occurs, pressurizer pressure and steam line pressure increase due to turbine isolation valve closure. Reactor Power PRZ/SG Pressure 57 Single RCP Trip At 30 s Economizer FW is decreased by SG water level control but downcomer FW flow is maintained without change. SG water level is started to decrease slowly due to less FW flow. Turbine is tripped by reactor trip signal and MFW is isolated after reactor scram. After main feedwater isolation, steam generator water level is decreasing more rapidly. AFW system is started due to low SG narrow range levels. To control the steam header pressure, turbine bypass valves are opened at ~10 s after RCP trip. SG water levels and auxiliary feedwater flows between SG A and B are different from each other. This is due to the flow difference between loops. FW/Turbine/Steam bypass flow PRZ/SG level AFW flow 58 Single RCP Trip At 300 s Reactor power is slowly decreasing due to decrease of decay heat. Pressurizer pressure and steam line pressure are maintained and stabilized by steam header pressure control. Steam line pressure is periodically oscillating due to steam flow through turbine bypass valve. RCP 1A speed is slowly coast-down to zero. The speed for remaining RCPs is maintained with same speed. Reactor Power PRZ/SG pressure RCP speed 59 Single RCP Trip At 300 s Loop 1A flow becomes negative and maintained at constant negative flow while loop 2A and 2B flow are increased a little. Loop 1B flow is increasing about 20%. Auxiliary feedwater flow is increasing and stabilized at ~300 s. Turbine bypass valves are open and closed before ~50 s to remove the decay heat. Cold leg flow Steam bypass flow AFW flow 60 Single RCP Trip At 300 s, Examine the difference of the steam flow rates from steam generators, reactor power, hot/cold-leg flow, and steam generator water levels compare to nominal operating condition. 61 Single RCP Trip At 300 s, To examine the secondary side parameter more precisely, you have to select sub-menu “Open Standalone Mimic” from the file menu. Then, it will show the directory which includes the mimic file. Select “panel_SG” to open the mimic. Then, the standalone mimic for secondary side of SGs appears in a different window. Before the transient start, steam flow and main feedwater flows for the steam generators are maintained in nominal level. But main feedwater flow and steam flow through turbine stop valve are terminated after a RCP trip. Before loss of FW After loss of FW 62 LOSS OF COOLANT ACCIDENT 63 LOCA Licensing History Final acceptance criteria (10CFR50.46) issued by USNRC in 1974. Required and acceptance features of final evaluation model (EM) issued (Appendix K) Vendors and fuel suppliers required to submit detailed documentation of their EMs showing adherence to appendix K. After 1974, the USNRC has continue to fund much analytical development (e.g., RELAP, TRAC) and experimental work (e.g., LOFT) SECY-83-472 New EM: retain appendix K, modify non-required features Confirm conservatism of EM by 95% probability PCT calculation 64 Major Licensing Analysis Assumptions Core decay heat increased 20% Reactor trip on low pressurizer pressure SIAS (Safety Injection Actuation Signal) on low pressurizer pressure Loss of all offsite power Main coolant pump coastdown Main feedwater pumps stop Steam bypass system not available Worst single active failure in ECCS 65 10 CFR50, 46 Acceptance Criteria for ECCS for LWR Peak cladding temperature shall not exceed 2200oF (1200oC) Max. cladding oxidation shall nowhere exceed 0.17 times the total cladding thickness Max. hydrogen generation for chemical reaction of the cladding with water or steam shall not exceed 0.01 times hypothetical amount from all cladding excluding plenum volume (at tops of fuel rods) Coolable geometry: calculated changes in core geometry shall be such that the core remains amenable to cooling Long term cooling: the calculated core temperature shall be maintained at an acceptable low value for the extended period 66 Peak Cladding Temperature (LB-LOCA) Evaluation model Best-estimate Calculation Modified decay heat Modified reflood HT 67 Small- and Large Break LOCA LB-LOCA : Full or partial rupture of the main circulation line, typically with break areas larger than 25% (USNRC: 0.005ft2)of the cross-section of the main circulation line. Ruptures of the major pipes connected to the primary circuit, such as pressurizer surge line or accumulator discharge line. SB-LOCA: Breaks smaller than in size in comparison with LB-LOCA. Breaks cannot be compensated for by the make-up system and require activation of the ECCS. 68 LB-LOCA 69 Major Periods of Time During a LBLOCA Blowdown Primary coolant is expelled from the RCS Core heat removal capability is degraded. Nuclear chain reaction is terminated Emergency code coolant is injected into RCS Refill Core heat removal by radiation Safety injection tanks add water to RCS Water fills reactor vessel lower plenum Reflood SITs, LPSIs, and HPSIs and water to RCS Water level increases in reactor core Core heat removal capability increases Long term cooling Core is totally covered with water HPSIs are realigned for long term cooling 70 Systems which cool the RCS during a LOCA Emergency Core Cooling System (ECCS) High Pressure Safety Injection System (HPSI) Low pressure safety injection system (LPSI) Safety Injection Tank (SIT) Auxiliary Feedwater System SG Power Operated Relief Valves (PORV) (if avalable) Atmospheric Dump and Bypass Valves 71 Sources and Sinks for mass and energy Sources Initial primary fluid Initial core stored heat RCS components stored heat Charging system Safety injection system Reactor decay heat Zirconium/water reaction Steam generator (steam binding) Mass X X X H2 Energy X X X X X (low Temp) X X X (if Tsec>Tprim) Sinks Flow through break X(water & steam) X Letdown line X X Steam generator (NC or reflux cooling) X (if Tsec<Tprim) 72 Break Locations in Primary System All piping in the reactor coolant pressure boundary Do not require consideration of breaks in the pressure vessel. Exception : for plants with bottom mounted instrument the failure of an instrument nozzle must be investigated A break in the steam generator tubing is considered as a separate accident The control rod ejection is considered for overpower induced core damage. The associated LOCA effects are approximated by the small break spectrum. 73 Characteristics of LBLOCA Blowdown Rapid loss of primary fluid (Critical flow) Rapid decrease in primary pressure Reversal of heat transfer across SGs ( Tprim <Tsec) Reversal of core flow for the large cold leg breaks Fuel rod surface experiences multiple HT regimes (nucleate boiling, CHF, transition boiling, film boiling, steam convection, radiation) Hot rods cladding swells, ruptures, some zirconium-steam reaction Containment pressure increase 74 Characteristics of LBLOCA refill/reflood ECCS acts to restore core coolant: Safety injection tanks (SITs) Low pressure safety injection pumps (LPSIs) High pressure safety injection pumps (HPSIs) Also charging pumps Core reactivity held down with boric acid Fuel rod surface experiences multiple HT regimes (radiation, film boiling, quench to nucleate boiling) Hot rods experience zirconium-steam reaction and become embrittled. For cold leg break, steam with droplet evolved in core travels through SG to reach break. This raises pressure in vessel and retards increase in core liquid level (steam binding). It worsens for lower containment pressure as steam specific volume increases) 75 Transport of RCS Energy to the SG (SBLOCA) With the RCPs off, the RCS flow is driven by hydrostatic head differences between the colder and hotter portions of loop (natural circulation) As long as a continuous liquid path exists, the nautral circulation flow will be single of two-phase. With continuous flow path is broken ( steam accumulation at tops of SG tube or vessel upper plenum) natural circulation flow will be by reflux cooling. Steam evolved in the core travels to SG tubes where it condenses to liquid The condensate formed on the hot side of SG tubes refluxes back to the core. 76 Reflux cooling (SB-LOCA) 77 LOCA Analysis (I) Break size and location have to be selected to maximize core heat up. All source of generated and stored energy in the RCS and secondary side have to be adequately modeled. Conservative power distribution in the core LB-LOCA: not so important SB-LOCA: top skewed power distribution (assumed as EOC) Conservatively low characteristics (low efficiency, low capacity and a long delay before action is taken) for reactor scram, HPSIs, LPSIs. Loss of off-site power and failure of a diesel generator is a typical assumption for single failure to minimize safety injection Loop seal effect (blocking of steam outflow by water plugs in pump suction leg) 78 SGTR 79 SGTR Initiated by setting SGTR during the nominal operating condition. This event is an accident but the transient behavior is very similar to operational transient after reactor trip by reactor protection system. 1. Click the execution file ‘APWRSimulator_visa.exe’ to start a simulation. It will automatically load the input file (100ic_NLOCA_r3.i) and the corresponding restart file of 100ic.r for 100% nominal operating condition. Select ‘open project’ from File menu and then choose ‘loca.mpj’ from directory window to load input files for LOCA simulation. 2. Press “OK” button in project tab for initialization. 3. Press “Run” speed button to simulate the 100% nominal power condition. 4. Enter the data saving frequency in the dialog box 5. Pause in the simulation at 20 s Speed button in upper part Set the time to pause. 80 SGTR 6. Move to “interactive tab” to initiate the transient. 7. Change the selection box from automatic to manual in “SGTR1” line. 8. Press the toggle switch for trip status in target column to be ON. Then the toggle switch will change the color from green to red. This will initiate a 5 steam generator U-tube rupture (SGTR) of steam generator 1. 9. Then, resume the execution by speed button in top left corner. 81 SGTR Before initiating SGTR, Reactor Power PRZ and SG Pressure you can confirm if the calculation is reached the steady state condition by examining the trend graphs for reactor power, pressurizer and steam generator pressures, etc. 82 SGTR At 100 s PRZ pressure starts to decrease. PRZ water level is decreasing and affected SG water level is increasing because the primary water flows into affected SG through the break. PRZ/SG pressure PRZ/SG level 83 SGTR At 100 s Break flow from primary side to secondary side of SG starts to increase and then, slowly decrease because the pressure difference between primary and secondary pressure is decreasing. MFW flow for affected SG is decreased by feedwater flow control system due to SG water level increase. Break flow AFW flow 84 SGTR At 100 s PRZ water level is started to decrease as shown since water in primary side of RCS is discharged through the break. Void distribution before SGTR Void distribution after SGTR 85 SGTR At 300 s Reactor is shut down due to low pressurizer pressure signal at ~255 s. Before reactor scram, reactor power is slowly increased due to reactor regulating control and reactivity feedback. After reactor shutdown, primary pressure decreases more rapidly and secondary pressure is increasing due to turbine stop. Reactor power PRZ/SG pressure 86 SGTR At 300 s Turbine flow and MFW flow is ceased and turbine bypass valves are opened by turbine bypass valve control system to control the SG pressure. AFW flows are also initiated at the almost same time. Turbine/steam bypass/MWF flow AFW flow 87 SGTR 10. It is normal to trip the reactor by operator based on high radiation signal. But it is ignored in this example. 11. According to the EOP, operator should isolate the affected SG by closing the MSIV and FW valves for SG 1 (In this example, SG is isolated at 350 s). 88 SGTR At 350 s HPSI system is started with some delay after low PRZ pressure signal. PRZ water level keeps decreasing after the break and decreasing speed is increased after reactor scram. SG water level is decreasing rapidly after turbine trip. At 350 s, the affected SG is isolated in this example. SG isolation includes MSIV close and auxiliary feedwater stop for the affected SG. HPSI flow PRZ/SG level 89 SGTR At 350 s just before the affected SG is isolated Water in SG is almost stagnant due to low heat transfer from the primary sides. And SG pressure is controlled by SG pressure control system. The upper part of vessel becomes vacant. Void distribution at 100 s Void distribution at 350 s 90 SGTR At 500 s Upper part of pressure vessel is filled with vapor and is almost identical with void distribution before SG isolation. This is due to primary and secondary SG pressure becomes equalized at ~ 350 s. Void distribution at 350 s Void distribution at 500 s 91 SGTR At 1000 s As soon as affected SG is isolated, auxiliary feedwater into SG 1 is ceased. Primary and Secondary side pressures of the affected SG becomes almost identical. Break flow is stopped due to no pressure difference. AFW flow PRZ/SG level 92 Cold Leg #1 SBLOCA 93 Cold Leg #1 SBLOCA Initiated by setting SBLOCA during the nominal operating condition. 1. Click the execution file ‘APWRSimulator_visa.exe’ to start a simulation. It will automatically load the input file (100ic_NLOCA_r3.i) and the corresponding restart file of 100ic.r for 100% nominal operating condition. Select ‘open project’ from File menu and then choose ‘loca.mpj’ from directory window to load input files for LOCA simulation. 2. Press “OK” button in project tab for initialization. 3. Press “Run” speed button to simulate the 100% nominal power condition. 4. Enter the data saving frequency in the dialog box 5. Pause in the simulation at 10 s Speed button in upper part Set the time to pause. 94 Cold Leg #1 SBLOCA 6. Move to “interactive tab” to initiate the transient. 7. Change the selection box from automatic to manual in “3% SBLOCA1” line. 8. Press the toggle switch for trip status in target column to be ON. Then the toggle switch will change the color from green to red. This will initiate a 3% LOCA in cold leg 1. 9. Then, resume the execution by speed button in top left corner. 95 Cold Leg #1 SBLOCA Before initiating SBLOCA, Reactor Power PRZ and SG Pressure you can confirm if the calculation is reached the steady state condition by examining the trend graphs for reactor power, pressurizer and steam generator pressures, etc. 96 Cold Leg #1 SBLOCA At 30 s PRZ pressure starts to decrease as soon as break occurs. At ~ 13 s, core is started to fill with void. At ~17 s, reactor power is scrammed due to low pressurizer pressure signal. PRZ/SG pressure Core void fraction Reactor power 97 Cold Leg #1 SBLOCA At 30 s Break flow is started as soon as break occurs. Due to discharge flow through the break, pressurizer water level is decreasing as soon as break occurs. Break flow PRZ/SG level 98 Cold Leg #1 SBLOCA 10. For the conservative simulation, all 4 RCPs are stopped to protect RCPs as an operator’s action at ~30 s. 99 Cold Leg #1 SBLOCA At 30 s PRZ water level is started to decrease. Hot leg and upper plenum are started to boil. At 60 s, Water in upper parts of reactor vessel is discharged through the break and upper head of pressure vessel and pressurizer is filled with void. Void distribution before SBLOCA Void distribution at 30 s Void distribution at 60 s 10 Cold Leg #1 SBLOCA At 100 s Reactor is tripped due to low pressurizer pressure. RCP speeds are started to coast down slowly due to RCP trip at 30 s. Cladding temperature decreases because saturated water temperature decrease and core is covered by two-phase water. With delay after low pressurizer pressure signal, safety injection is started. Reactor power RCP speed Cladding temperature HPSI flow 10 Cold Leg #1 SBLOCA At 100 s Upper part of vessel becomes vacant. At 300 s, Upper part of pressure vessel is filled with vapor and cold/hot legs become partially filled with vapor. At 1000 s, water in pump suction legs is cleared due to pressure buildup in upper head and flows to downcomer of pressure vessel. Void distribution at 100 s Void distribution at 300 s Void distribution at 1000 s 10 Cold Leg #1 SBLOCA At 500 s Cladding temperatures keep decreasing due to pressure decrease. As long as core is covered by two-phase water, core heat-up does not occur. At ~400 s, core and downcomer collapsed level starts to recover. Cladding temperature Downcomer level 10 Cold Leg #1 SBLOCA At 500 s Break location/Break flow. PRZ/Core/downcomer level. Cladding temperature. 10 LBLOCA Simulation 10 Guillotine Break at Cold Leg #1 This is the most limiting hypothetical accident in a PWR plant. Other simulators based on overly simplified models could not simulate a complex two-phase phenomena in this kind of transient conditions. High fidelity of this simulator makes it possible to show close to real situation. 1. Pause on the execution at 50 s by setting the time to pause. 2. Move to “interactive tab”. − Change the selection box from automatic to manual. − Press “CL1 LBLOCA” toggle switch for trip. − Then press OK button at the bottom right. − Then, resume the execution by speed button in top left corner. 10 Guillotine Break at Cold Leg #1 Before initiating LBLOCA, Primary side is filled with water except PRZ. SG secondary side: − − − Solid water in downcomer The steam and water mixture in riser part Two-phase mixture is separated in steam separator. Steam flows to steam line and water is returned to downcomer. 10 Guillotine Break at Cold Leg #1 Void distribution after initiating LBLOCA, 13 s 70 s 25 s 130 s 40 s 160 s 10 Guillotine Break at Cold Leg #1 Trend graph at 3 s after initiating LBLOCA, 10 Guillotine Break at Cold Leg #1 Trend graphs at 15 s after initiating LBLOCA, Fuel cladding T RCP speeds Accumulator flow Trend graph at 55 s after initiating LBLOCA, Fuel Cladding T DC / Core level Accumulator flow SI flow 11 Guillotine Break at Cold Leg #1 Trend graphs at 120 s after initiating LBLOCA, No re-heating occurs Accumulator flow Fuel cladding T 11 SBO + DC Power Loss Simulation (similar to Fukisima Accident) 11 SBO An SBO accident :a complete loss of all AC power including the EDGs. Most of ESFs require the electrical power except for the TD-AFW system and the relief valves of a safety-related class during an SBO accident. RCP seal leak is neglected in this test simulation. System Primary Secondary *Power source type: Component Control/Scram Rod RCP PSV PZR heater / spray Charging / Letdown SIP SIT MFWP/CP MD- AFW TD- AFW SBCS MSSV ADV Function Reactor power control RCS Forced cooling Pressure control Pressure control PRZ Level control Coolant inventory Coolant inventory SG coolant inventory SG Coolant inventory SG Coolant inventory SG Pressure control SG Pressure control SG Pressure control Power Source* G/E E S/E E E E A E/T E T A S M/E Availability O X O X X X O X X O X O X E=Electricity, G=Gravity, S=Spring-loaded, T=Turbine, M=Man-powered, A=compressed Air 11 SBO TD-AFW system consists of the steam control valve (3), an auxiliary turbine (4), an emergency feedwater pump (5), condensate storage tank (6) which is the water source of the auxiliary feedwater, and the control panel (7) equipped with the SG level measurements and valve controller to control the SG (1) water level remotely in the main control room (MCR). The pump speed is controlled according to the steam flow rate which is determined by the steam control valve at normal state. 7 Offsite/ Emergency Power S/G Level Gauge & V/V controller 8 CST 6 V/V Control MSSV 3 M S L 2 AFW P/P 4 5 Steam Control V/V AFW TBN Exhausted steam Atmosphere S/G Level Signal S/G 1 Flow path of AFW Flow path of Steam 11 SBO Press “Manual rector trip”, “Manual turbine trip”, all RCPs, main feedwater flow trip toggle switch for trip. Set charging / letdown flow rate to zero. Set HPSIs, LPSIs to zero. Set MD-AFW to zero. DC battery power is assumed to be available. Then press OK button at the bottom right. Reactor power MFW / Turbine flow RCP speed PRZ/SG narrow level 11 SBO Due to a low SG level (23.5 %) signal, TD-AFW is actuated. SG P is maintained at ~80 bars by the actuation of the MSSV. TD-AFW flow MSSV flow 11 SBO At ~1000 s, the system is stabilized by controlled TD-AFW flow. TD-AFW flow PRZ/SG P MSSV flow Reactor power PRZ/SG narrow level RCP speed 11 SBO Let us assume DC battery failure at ~1000 s after SBO. If the control panel is unavailable due to loss of DC power such as Fukusima accident, the stem position of the steam control valve (3) remains as it is. At ~2200 s, top of separator is filled with water and steam separation function is no more available. Then, the moisture goes to the turbine of TD-AFW system and TD-AFW could be fail. TD-AFW flow PRZ/SG narrow level 11 SBO You can simulate TD-AFW failure by setting TD-AFW flow to be zero. 9,000 s 13,000 s 11,000 s 14,000 s 12,000 s 15,000 s 11 SBO SG water is dried out at ~16000 s. Loss of SG heat removal capability makes primary P increases. Primary P finally reaches to PSV open setpoint. PSV is repeatedly opened and closed to remove the decay heat by mass/energy release. Void distribution PRZ/SG P PSV flow 12 SBO Due to primary water discharge through PSV, primary inventory is decreasing. 19,500 s 20,800 s 20,000 s Core liquid fraction (20,800 s) Core liquid fraction Fuel cladding T (20,800 s) 12 SBO After 21,200 s, primary inventory remains only in lower part of vessel, loop seal, and PRZ. 12 Appendix 12 Nuclear Steam Supply System (NSSS) Chemical and Volume Control System Safety Injection System Supporting Systems 12 OPR-1000 Systems - CVCS Chemical and Volume Control System Maintain reactor coolant inventory Control boron concentration and chemistry of reactor coolant Provide seal injection flow to reactor coolant pumps Provide auxiliary pressurizer spray 12 Schematic of the CVCS Containment Atmospheric Dump Valve Containment Spray Header Main Steam Isolation Valve RDT Downcomer Feedwater Control Valve Safety Depressurization System Filter Pressurizer Steam Generator 2 Chemical and Volume Control System Volume Control Tank HP Heater 7 Reheater Drain Tank HP Heater 5 Reactor Vessel Deaerator Storage Tank Separator Drain Tank HP Heater 5 Safety Injection Tank Economizer Feedwater Control Valve Letdown Orifice Intercept Valve Intermediate Valve LP Extraction Steam LP Turbine (3EA) HP Turbine Control Rod Letdown Heat Exchanger 1st Stage Reheater Reheater Drain Tank Deaerator Storage Tank Level Control Valve Deaerator 2nd Stage Reheater Stop Valve Control Valve Steam Generator 1 Ion Exchanger Moisture Separator Reheater Main Steam Safety Valve Pressurizer Safety Valve LP Extraction Steam Generator HP Extraction Steam Condenser Turbine Bypass to Condenser Condensate Pump Auxiliary Charging Pump Hot Well Sea Water From Intake Core Reactor Coolant Pump Charging Pump LP Extraction Steam LP Heater 1 In-Core Instrument Charging Control Valve Regenerative Heat Exchanger Containment Recirculation Sump Refueling Water Tank LP Heater 2 HP Extraction Steam Reactor Drain Tank Boric Acid Make-up Pump HP Heater 7 Shutdown Cooling Heat Exchanger Low Pressure Safety Injection Pump Train A High Pressure Safety Injection Pump Train B Containment Spray Pump Sea Water to Discharge Duct HP Heater 6 HP Heater 5 LP Heater 3 Feedwater Feedwater Pump Booster Pump C C Cold Leg Hot Leg Containment Spray 12 OPR-1000 Systems – Safety Injection Safety Injection System Supply borated water into four cold legs during a loss-of-coolant accident (LOCA) Remove decay heat and long term cooling after LOCA Supply borated water during RCS overcooling event such as main steam line break accident Feed and bleed operation with safety depressurization system System components Two high pressure (HPSI) and two low pressure (LPSI) pumps – Two train (100%) redundancy Four safety injection tanks Refueling water tank (RWT) - external to containment 12 Schematic of the SIS SI-331 LOOP2 HOTLEG SI-604 SI-616 HIGH PRESS. SI PUMP 2 SI-614 REFUELING WATER TANK SI-698 SI-617 SI-626 LOOP2 COLDLEG SI-615 SI-306 SI-624 SI-669 LOW PRESS. SI PUMP 2 SI-666 SI-627 SI-660 SI-625 SI-659 SI-636 SI-634 SI-667 SI-668 SI-637 SI-307 SI-646 LOOP1 COLDLEG LOW PRESS. SI PUMP 1 SI-635 SI-644 SI-699 SI-647 LOOP1 HOTLEG HIGH PRESS. SI PUMP 1 SI-645 SI-321 SI-675 SI-603 SI-676 CONTAINMENT RECIRCULATION SUMP SAFETY INJECTION SYSTEM - INJECTION MODE 12 OPR-1000 Systems – Aux. Feedwater Syste Auxiliary feedwater system m Dedicated for emergency feedwater functions Two motor-driven and two turbine-driven pumps Diverse and redundant 12 OPR-1000 Systems : COLSS & CPC Core Operating Limit Supervisory System(COLSS) Monitoring the limiting conditions for operator Linear heat rate margin Departure from Nucleate Boiling Ratio (DNBR) margin Total core power Azimuthal tilt and axial shape index Core Protection Calculator(CPC) DNBR Trip Linear Power Density Trip Auxiliary Trips 13 I&C systems Operator have to know all the existing conditions occurring in NPP over 10,000 I&C components provide necessary data to operators. It is difficult for operators to control various systems and equipment I&C systems provide automatic controls to maintain the plant safety and reliable conditions. When an emergency condition is occurred, the I&C systems provide needed protective actions regardless operators do not realize what happens at the plant. 13 Typical I&C Systems in NPP CV Pressure Monitoring Pressurizer Level Control Rx Protection Control Rod Control Pressurizer Pressure Control S/G Level & Pressure Control Main Steam flow & Pressure Monitoring Feed Water Flow Control Turbine Protection MW Control Turbine Speed Control Condenser Vacuum Control Hot Leg Temperature Monitoring RCP Speed Monitoring Cold Leg Temperature Monitoring RCS Flow Monitoring 13 Plant Monitoring Systems in NPP Functions of the Monitoring Systems Continuously monitor almost all of the plant variables Provide data to the plant operators for use in controlling the plant Transmit data to other I&C systems for control and protection of plant Also, provide visual and audible alarms in control room Major variables to be monitored Temperature, Pressure, Level, Flow, Humidity Neutron Flux, Radiation Speed, Vibration, Thrust wear Earthquake, Fire detection 13 OPR-1000 Systems : Control System Typical plant control systems Reactor regulation system (RRS) Pressurizer pressure control system Pressurizer level control system Feedwater water control system Steam bypass control system Functions of the Control Systems Continuously monitor specific systems or components variables. Compare the measured variables with reference values, and Calculate differences between measured variables and reference. Control related actuators to match the variables with reference. 13 Pressurizer Pressure Control System (PPCS) PPCS controls PRZ pressure to maintain RCS in subcooled state Pressurizer is filled with two-phase mixture in a saturated condition. Surge line is connected between liquid region of pressurizer and RCS. Pressurizer pressure is controlled to maintain at 15.5 bar. It makes RCS at 16.6 oC subcooled state in nominal operating condition. When average RCS temperature decreases, Liquid in PRZ out-surges to RCS since RCS liquid volume decreases. Saturated liquid in PRZ is evaporated due to pressure decrease while it will make PRZ pressure decrease. Consequently, it will stabilized at a little lower pressure. When average RCS temperature increases, Liquid in RCS in-surges to PRZ since RCS liquid volume is expanded. Saturated vapor in PRZ is condensed due to pressure increase. Consequently, it will stabilized at a little higher pressure. During the transient condition PPCS minimizes the pressure change by controlling heater power and spray flow. 13 Pressurizer – Pressure Control Safety Valves Open High Pressure Alarm Both spray valves fully open above 2300 Psia both spray valves fully closed below 2275 Psia proportional heaters group OFF control setpoint proportional heaters group ON All backup heaters OFF above 2225 Psia All backup heaters ON below 2200 Psia Low pressure alarm 13 Pressurizer Pressure Control System Control output: Proportional spray valve, backup heater, proportional heater Control inputs : Pressurizer pressure & level Setpoint Actual Value Pressure Controller 13 Pressurizer Level Control System (PLCS) PLCS controls PRZ level to maintain RCS water inventory. PLCS adjusts the opening area of charging and letdown control valve in CVCS to minimize the RCS inventory change. PLCS maintains PRZ steam volume to absorb the effect of in-surge flow 13 Pressurizer – Level Control PZR Level Error Action 8.9%(+38”) High Level Error Alarm 8.4%(+36”) Normal Running Charging Pump Stop 7.9%(+34”) Clear High Level Error Alarm 3.0%(+13”) Energize Backup Heater Normal Running Charging Pump Start 2.6%(+11”) Backup Heaters “OFF” -2.6%(-11”) Clear Low Level Error Alarm -3.5%(-15”) Low Level Error Alarm -14.0%(-60”) Stand-By Charging Pump Stop Lo-Lo Level Alarm -23.4%(-100”) Stand-By Charging Pump Start All Heater "OFF" (DB 2%) Note : Pressurizer Level 60% High Level Alarm (DB 3%) 52.6% 33% 25% : Level Increasing relative to setpoint : Level Decreasing relative to setpoint PZR Level Error = Program Level + Deviation 568.33(298) (15% Load) 592.85(311.6) (Full Load) RCS T AVG , o F 13 Pressurizer Level Control Control output: Letdown control valve, Charging pumps Control inputs : Pressurizer level & Tavg Pneumatic Control Valve Setpoint CVCS actual value Pneumatic Controller 14 Steam Generator Level Control (I) System Functions Maintains steam generator water level by controlling feed water flow 3 element control (steam flow, feed water flow, steam generator water level) is used when reactor power is over 15% 1 element control (steam generator water level) is used when reactor power is below 15% Adjusts downcomer, economizer feed water control valve areas and feed water pump speeds to control steam generator water level 14 Steam Generator Level Control (II) Control input : SG level, Feedwater flow , Steam flow Control output: Downcomer, Economizer Controller in MCR Feed Water Control Steam F/W Pump Speed Control Steam Generator Level Reference Compare Actual Water Level with Reference Steam Flow Monitoring S/G #1 FW Valve Control Feed Flow Monitoring Steam Flow Steam Generator Actual Level Monitoring Feed Water Control valves 14 Steam Bypass Control System (I) System Functions Automatically removes the excess energy in NSSS by controlling the steam flow through steam bypass valve with reactor power control system (RPCS) and other control systems Manually controls RCS average temperature during reactor power increase and decrease operations Produces control rod withdrawal prohibit signal not to occur control rod withdrawal when steam bypass flow demand exists Produces control rod withdrawal prohibit signal when reactor power is below 15% Removes the excess reactor power when turbine power decreases below preset valve in coincidence with control rod movement prohibit signal 14 Steam Bypass Control System (II) Control output : Steam bypass control valve Control input : Steam flow, pressurizer pressure, main steam header pressure 14 How to control the reactor power? Control Rods, made of neutron-absorbing materials such as silver, indium, cadmium, boron, or hafnium are installed in reactors to control of reactivity. A Control Element Assembly(CEA) consists of several control rods. Totally 73 CEAs are installed in a reactor. Reactor power is controlled by raising and lowering the CEAs. Raising the CEAs creates more power, lowering decrease power. When emergency, all CEAs will be dropped into reactor by gravity. 14 Control Element Assembly (CEA) The 73 CEAs are grouped into 2 Shutdown groups, 5 regulating groups, and two part strength groups. Shutdown Group provides a sufficient negative reactivity for reactor trip when it is necessary. Regulating Group controls reactor power level during normal reactor operation. Part Strength adjusts axial power distribution. Each group has one or more subgroups consisting of 4 CEAs. 14 CEA Location and Assignment SUB GROUP CONTROL GROUP CEA A 2 3 5 6, 8, 10, 12 7, 9, 11, 13 18, 19, 20, 21 B 6 7 9 10 22, 24, 26, 28 23, 25, 27, 29 34, 36, 38, 40 35, 37, 39, 41 Regulating group 1 1 14 15 2, 3, 4, 5 54, 57, 60, 63 56, 59, 62, 65 Regulating group 2 12 13 46, 48, 50, 52 47, 49, 51, 53 Regulating group 3 11 16 42, 43, 44, 45 55, 58, 61, 64 Regulating group 4 8 30, 31, 32, 33, 1 Regulating group 5 4 14, 15, 16, 17 P1 P2 17 18 66, 68, 70, 72 67, 69, 71, 73 Shutdown group Part Strength Group 14 Reactor Power Control Mechanism In general, reactor power follows turbine load. Reactor Regulating System (RRS) monitors turbine load which is a linear indication of turbine load, Tref. RRS also produces an average RCS temperature, Tavg, using reactor coolant hot leg and cold leg temperature. Determines an error signal by “Tavg – Tref”, and provides it to the Control Element Drive Mechanism Control System (CEDMCS). When “Tavg - Tref” is positive : CEAs will be inserted. When “Tavg - Tref” is negative : CEAs will be withdrawn. CEAs moving speed depends on magnitude of “Tavg – Tref”. 14 Reactor Regulation System (RRS) CEDMCS Power Cabinet Cold Leg Logic Cabinet Hot Leg “Tavg - Tref” is positive : CEAs will be inserted “Tavg - Tref” is negative : CEAs will be withdrawn Moving speed depends on magnitude of “Tavg - Tref” Turbine 1’st stage Pressure, Tref RCS Average Temperature Tavg Core Control #1 MSR B Stop Steam Generator #1 #1 Stop Control #2 CIV #3 CIV #2 CIV #1 #2 GEN Control #3 Stop RRS Cold Leg Temperature CIV #4 #3 Hot Leg Temperature Steam Generator #2 CIV #5 CIV #6 Control #4 Stop #4 MSR A 14 Protection Systems 15 Safety Related Protection System Design Concepts Whenever called upon to act, protection systems must perform their intended function Redundancy Independency Testability Single Failure Proof Coincidence Diversity Quality Equipment Electrical and Physical Barriers Sensor A Sensor C Sensor B B/S B/S B/S Ch B 2 out of 4 Logic Sensor D Ch C B/S Ch D 2/4 Protective Action 15 Protection System Overview Functions of the Protection Systems Continuously monitor specific system or component variables When the measured variables goes over predetermined safety limits, provide protective actions. Typical Plant Protection Systems in NPP Reactor Protection System (RPS) Core Protection Calculation System (CPCS): not modeled Engineered Safety Features Actuation System (ESFAS) Turbine Protection System - Non Safety 15 Plant Protection System (PPS) Plant Normal Operation Continuously Monitoring Plant Parameters Indicating, displaying or alarming Reactor Protection System Compares input parameters to Predetermined Setpoint Determines 2 out of 4 coincidence Opens 4 Reactor Trip Breakers Drops the Control RODs into Reactor Engineered Safety Features Actuation System Compares input parameters to Predetermined Setpoint Determines 2 out of 4 measurements exceed the setpoint Actuates each ESF Facilities via ESFAS Aux Relay Cabinet 15 PPS Cabinet Assembly 15 Reactor Protection System (RPS) Functions of the RPS Measures safety related process parameters associated with the reactor and containment system by using four redundant instrument channels. Compares measured parameters with a predetermined values. When a given process parameter exceeds the setpoint, a channel trip is occurred. If the same parameter in two or more channels reaches a limiting safety setting, a reactor trip signal will be occurred. The reactor trip will be initiated by opening the reactor trip circuit breakers resulting in interrupting the holding coils power of CEDM. De-energizing CEDM coils, all the CEAs are to drop into reactor. 15 Reactor Trip Logic Drawing 15 Reactor Protection Signals-1 1. Variable Overpower Trip Prevent Reactor Overpower Prevent Reactor Power increasing rate Reactor Neutron Detector Core Neutron Detector Ex-core Safety Channel Comparator (Bistable) + - Decide - Normal - Ch trip Safety Limit (Setpoint) 15 Reactor Protection Signals-2 2. High logarithmic power level To ensure the integrity of the fuel cladding and RCS boundary in the event of unplanned criticality from a shutdown condition, resulting from either dilution of the soluble boron or withdrawal of CEAs. The setpoint of this trip is very low, 0.018% of reactor power Reactor Neutron Detector Core Neutron Detector Ex-core Safety Channel Comparator (Bistable) + - Decide - Normal - Ch trip Safety Limit (Setpoint) 15 Reactor Protection Signals-3 3. High Local Power Density (LPD) and Low Departure from Nucleate Boiling Ratio (DNBR) To prevent the linear heat rate and the DNBR in the core from exceeding the safety limit. When LPD reaches the 21kw/ft-fuel, or calculated DNBR reaches 1.3, a reactor trip will be occurred. Core Protection Calculator (CPC), designed as a reactor protection system, generates two reactor trip signals as a function of Reactor power and power distribution. System Configuration of CPCs Execute in minicomputers in the auxiliary protective cabinet. 15 Pressurizer Pressure Low or High? 4. High Pressurizer Pressure Assure the integrity of the RCS boundary If CEAs ejects for feedwater pipe ruptures and CEA ejections that can lead to an over pressurization of the reactor coolant system. Pressurizer Steam Generator 5. Low Pressurizer Pressure To assist the ESFAS in the event of a loss RCP Reactor If LOCA occurs of coolant accident, and to provides a reactor trip in the event of reduction in pressurizer pressure Low pressure actuate a reactor trip, SIAS and CIAS (Containment Isolation Actuation Signal) are actuated simultaneously. 16 Reactor Protection Signals-4 6. Low steam generator water level This trip is to provide sufficient time for actuating Aux Feedwater pumps to remove decay heat from the reactor in the event of reduction of steam generator water inventory. 7. High steam generator water level This trip is to provide a protection to downstream components. When the steam generator water level is higher than certain value, the water among the main steam may damage turbine blade. This signal also initiate a main steam isolation signal (MSIS). 16 Reactor Protection Signals-5 8. Low Steam Generator Pressure CV Pressure Transmitter Containment Vessel Steam generator Steam S/G Pressure Transmitter Feed Water To provide protection against excess secondary heat removal in events of feedwater or steam line rupture accident. 9. High Containment Pressure To help the integrity of the containment with an event results in significant mass and energy releases into the containment from RCS or main steam lines, main feedwater lines. Also, initiate the ESFAS such as CIAS, SIAS and MSIS at the same time. 16 Reactor Protection Signals-6 10. Low reactor coolant flow To limit the consequences of a sheared reactor coolant pump shaft. The reactor coolant flow is measured by measuring the differential pressure between across the primary side of steam generator. DP Cell Orifice Factor √ K Flow 16 Reactor Protection Signals-7 11. Manual Trip When needed, operator can trip the reactor manually. Two sets of pushbuttons are provided in the MCR. A trip is accomplished by use of selective two out of four pushbuttons. 16 Fixed Setpoint (Rising Trip) ■ During Normal Operation, process value stays below setpoint. ■ When the measured value reaches high setpoint, trip occurs. Power Level Trip Setpoint Trip 발생 Pretrip Setpoint Process Value Pre Trip 발생 Time 16 Containment System 16 Containment Building Containment systems are designed to mitigate the consequences of a Design Basis Accident (DBA) Major accidents are loss-of-coolant accident (LOCA) and secondary system failure (ex. MSLB) Provides biological shielding during normal operation and following a LOCA. Functions as a leak tight barrier following an accident inside the containment. 16 Containment Building Dimensions of the containment Basemat Thickness : 3.7 m Interior Diameter : 43.9 m Interior Height : 65.8 m Cylindrical Wall Thickness : 1.2 m Liner Plate Thickness : 6 mm Free Volume(ft3) : 2.73×106 Design Pr. & Temp.: 4kg/㎠ /140℃ 16 Containment Building : Hatches [ Personnel Hatch] [ Equipment Hatch] [ Emergency Hatch] 16