Overview of Korean-Type PWR Simulator Prepared for IAEA TM (Vienna, Austria, May 19-22, 2014) KIM, Kyung Doo ([email protected])
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Transcript 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