NUREG/IA-0227

 International 

Agreement Report

IJS Animation Model for Krško NPP

Prepared by:

A. Prošek, B. Mavko

Jožef Stefan Institute

Jamova cesta 39

SI-1000 Ljubljana, Slovenia 

A. Calvo, NRC Project Manager 

Office of Nuclear Regulatory Research

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

May 2010 

Prepared as part of

The Agreement on Research Participation and Technical Exchange 

Under the International Code Assessment and Maintenance Program (CAMP)

 

Published by

U.S. Nuclear Regulatory Commission
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NUREG/IA-0227

IJS animation model for Krško NPP 

Manuscript Completed: October 2009 

Date Published: May 2010 

Prepared by: Andrej Prošek, Borut Mavko 

Jožef Stefan Institute 

Jamova cesta 39 

SI-1000 Ljubljana, Slovenia 

Antony Calvo, NRC Project Manager 

Prepared for:

Division of Systems Analysis 

Office of Nuclear Regulatory Research 

U.S. Nuclear Regulatory Commission 

Washington, DC 20555-0001

iii 

ABSTRACT

This report presents the developed animation model for Krško nuclear power plant (NPP). For 

animations the Symbolic Nuclear Analysis Package (SNAP) was used. Krško NPP, which is a 

two-loop pressurized water reactor, Westinghouse type, before modernization in 2000 obtained 

plant specific full scope simulator. In the present study reference design basis calculations for 

Krško full scope simulator validation were analyzed with the latest RELAP5/MOD3.3 Patch 03 

code to get the source data needed for development of animation model. In total six scenarios 

were analyzed: two scenarios of the Small Break Loss-of-Coolant Accident (LOCA), two 

scenarios of the Loss of Main Feedwater (LOFW), scenario of the Anticipated Transient Without 

Scram (ATWS), and scenario of the Steam Generator Tube Rupture (SGTR). Animation masks 

were created for the primary and the secondary system, important plant systems, the plant 

signals and the control systems. The use of SNAP for animation of Krško nuclear power plant 

analyses showed several benefits, especially better understanding of the calculated physical 

phenomena and processes. It can also be concluded that the use of such support tools to 

system codes significantly contributes to better quality of safety analysis. 

v 

CONTENTS

Page

Abstract ...................................................................................................................................... iii

Acknowledgment ........................................................................................................................ x

Abbreviations ............................................................................................................................. xi

1. Introduction ........................................................................................................................... 1

2. Input Model Description ....................................................................................................... 3

3. Scenarios Description .......................................................................................................... 5

3.1 Anticipated Transient Without Scram Scenario ................................................................. 5

3.2 Loss of Feedwater Scenarios ............................................................................................ 5

3.3 Small Break Loss-of-Coolant Accident Scenarios ............................................................. 6

3.4 Steam Generator Tube Rupture Scenario ......................................................................... 6

4. Description of Developed Animation Masks ...................................................................... 9

4.1 Animation Masks of Plant Systems and Components ....................................................... 9

4.1.1 General Plant Mask ............................................................................................... 9

4.1.2 Reactor Vessel Mask .......................................................................................... 11

4.1.3 Pressurizer Mask ................................................................................................. 11

4.1.4 Steam Generator Masks...................................................................................... 12

4.1.5 Main Steam System Mask ................................................................................... 14

4.1.6 Main Feedwater System Mask ............................................................................ 14

4.1.7 Auxiliary Feedwater System Mask ...................................................................... 15

4.2 Animation Masks of Plant Signals ................................................................................... 16

4.2.1 Reactor Trip and Safety Injection Signal Mask ................................................... 17

4.2.2 Turbine Trip and Feedwater Isolation Signal Mask ............................................. 18

4.2.3 AFW Start Signal Mask ....................................................................................... 19

4.2.4 MSIV Isolation and RCP Trip Signal Mask .......................................................... 20

4.2.5 Main Signals and Sequence of Events Mask ...................................................... 21

4.3 Animation Masks of Control Systems .............................................................................. 22

4.3.1 Rod Control System Mask ................................................................................... 23

4.3.2 Pressurizer Pressure Control System Mask ........................................................ 24

4.3.3 Pressurizer Level Control System Mask.............................................................. 25

4.3.4 Steam Generator Level Control System Masks .................................................. 26

4.3.5 Turbine Power Control Mask ............................................................................... 27

4.3.6 Steam Dump Control Mask ................................................................................. 29

5. Results of RELAP5 Calculations ....................................................................................... 31

5.1 Anticipated Transient Without Scram Results ................................................................. 31

5.2 Loss of Feedwater Results .............................................................................................. 38
vi 

5.2.1 Loss of Feedwater with Auxiliary Feedwater Available Results .......................... 38

5.2.2 Loss of Feedwater without Auxiliary Feedwater Available Results ..................... 42

5.3 Steam Generator Tube Rupture Results ......................................................................... 47

5.4 Small Break Loss-of-Coolant Accident Results ............................................................... 53

5.4.1 5.08 cm Break Size Small Break Loss-of-Coolant Accident Results ................... 53

5.4.2 20.32 cm Break Size Small Break Loss-of-Coolant Accident Results ................. 57

6. Examples of Animations .................................................................................................... 63

6.1 Steam Generator Tube Rupture Accident Animation ...................................................... 63

6.2 Small Break Loss-of-Coolant Accident Phenomena Animation ...................................... 67

7. Conclusions......................................................................................................................... 71

8. References ........................................................................................................................... 73
vii 

Figures

Page

1. General plant mask after 1000 seconds of steady state – void color map ............................. 10

2. General plant mask after 1000 seconds of steady state – fluid condition color map .......... 10

3. Reactor vessel mask after 1000 seconds of steady state ...................................................... 11

4. Pressurizer mask after 1000 seconds of steady state............................................................ 12

5. Steam generator no. 1 mask after 1000 seconds of steady state .......................................... 13

6. Steam generator no. 2 mask after 1000 seconds of steady state .......................................... 13

7. Main steam system mask after 1000 seconds of steady state ............................................... 14

8. Main feedwater system mask after 1000 seconds of steady state ......................................... 15

9. Auxiliary feedwater system mask after 1000 seconds of steady state ................................... 16

10. Reactor trip and safety injection signal mask after 1000 seconds of steady state ................ 17

11. Turbine trip and feedwater isolation signal mask after 1000 seconds of steady state .......... 18

12. AFW start signal mask after 1000 seconds of steady state .................................................. 19

13. MSIV isolation and RCP trip signal mask after 1000 seconds of steady state...................... 20

14. Main signals and sequence of events mask after 1000 seconds of steady state ................. 21

15. Rod control system mask after 1000 seconds of steady state .............................................. 23

16. Pressurizer pressure control system mask after 1 second for 5.08 cm break size SBLOCA 24

17. Pressurizer level control system mask after 15 seconds for 5.08 cm break size SBLOCA .. 25

18. Steam generator no. 1 level control system mask after 1000 seconds of steady state ........ 26

19. Steam generator no. 2 level control system mask after 8 seconds of LOFW scenario 1 ...... 27

20. Turbine power control system mask after 2 seconds of LOFW scenario 1 ........................... 28

21. Steam dump control system mask after 30 seconds of LOFW scenario 1 ........................... 30

22. Steam generator no. 1 pressure – ATWS ............................................................................. 33

23. Steam generator no. 1 narrow range level – ATWS ............................................................. 34

24. Main steamline no. 1 flow – ATWS ....................................................................................... 34

25. Primary pressure – ATWS .................................................................................................... 35

26. Reactivity – ATWS ................................................................................................................ 35

27. Primary coolant average temperature – ATWS .................................................................... 36

28. Core power – ATWS ............................................................................................................. 36

29. Pressurizer PORV no. 1 mass flow – ATWS ........................................................................ 37

30. Pressurizer PORV no. 2 mass flow – ATWS ........................................................................ 37

31. Steam generator no. 1 narrow range level – LOFW with AFW ............................................. 39

32. Primary pressure – LOFW with AFW .................................................................................... 40

33. Steam generator no. 1 pressure – LOFW with AFW ............................................................. 40

34. Steam dump flow – LOFW with AFW .................................................................................... 41

35. Pressurizer level – LOFW with AFW ..................................................................................... 41

36. Core collapsed liquid level – LOFW with AFW...................................................................... 42

37. Steam generator no. 1 narrow range level – LOFW without AFW ........................................ 44

38. Primary pressure – LOFW without AFW ............................................................................... 44

39. Steam generator no. 1 pressure – LOFW without AFW ........................................................ 45

40. Steam dump flow – LOFW without AFW ............................................................................... 45

41. Pressurizer level – LOFW without AFW ................................................................................ 46

42. Core collapsed liquid level – LOFW without AFW................................................................. 46

43. Core cladding outer surface temperature (11 of 12) – LOFW without AFW ......................... 47

44. Primary pressure – SGTR ..................................................................................................... 49

45. Pressurizer level – SGTR...................................................................................................... 50

46. Rupture flow – SGTR ............................................................................................................ 50
viii 

47. Steam generator no. 1 pressure – SGTR ............................................................................. 51

48. Steam generator no. 2 pressure – SGTR ............................................................................. 51

49. Steam generator no. 1 level – SGTR .................................................................................... 52

50. Steam generator no. 2 level – SGTR .................................................................................... 52

51. Primary pressure – 5.08 cm break size SBLOCA ................................................................. 54

52. Cold leg no. 1 temperature – 5.08 cm break size SBLOCA .................................................. 54

53. Reactor coolant system mass – 5.08 cm break size SBLOCA ............................................. 55

54. Reactor vessel collapsed liquid level – 5.08 cm break size SBLOCA................................... 55

55. Integrated break flow – 5.08 cm break size SBLOCA ........................................................... 56

56. Steam generator no. 1 pressure – 5.08 cm break size SBLOCA .......................................... 56

57. Steam generator no. 1 level – 5.08 cm break size SBLOCA ................................................ 57

58. Primary pressure – 20.32 cm break size SBLOCA ............................................................... 59

59. Reactor coolant system mass – 20.32 cm break size SBLOCA ........................................... 59

60. Reactor vessel collapsed liquid level – 20.32 cm break size SBLOCA................................. 60

61. Core cladding outer surface temperature (8/12) – 20.32 cm break size SBLOCA ............... 60

62. Integrated break flow – 20.32 cm break size SBLOCA ......................................................... 61

63. Steam generator no. 1 pressure – 20.32 cm break size SBLOCA ........................................ 61

64. Steam generator no. 1 level – 20.32 cm break size SBLOCA .............................................. 62

65. SNAP animation mask for reactor trip and SI signal – SGTR ............................................... 63

66. SNAP animation mask of Krško NPP plant at 365 second – SGTR ..................................... 64

67. SNAP animation mask for SG1 at 365 second showing void fractions (left) and flow regimes 

(right) – SGTR ............................................................................................................................. 65

68. SNAP animation mask for main steam system at 4750 second showing SG2 PORV 

discharging – SGTR.................................................................................................................... 65

69. SNAP animation mask for auxiliary feedwater at 4750 second showing AFW system not 

injecting – SGTR ......................................................................................................................... 66

70. SNAP animation mask for emergency core cooling system at the end of calculation showing 

HPSI pumps injecting – SGTR .................................................................................................... 66

71. SNAP animation mask for plant, showing void conditions – 20.32 cm break size SBLOCA 67

72. SNAP animation mask for plant, showing fluid conditions – 20.32 cm break size SBLOCA 68

73. SNAP animation mask for plant, showing fluid conditions – 20.32 cm break size SBLOCA 69

74. SNAP animation mask for plant, showing fluid conditions – 20.32 cm break size SBLOCA 70
ix 

Tables

Page

1. Main plant signals and sequence of events - ATWS .............................................................. 32

2. Main plant signals and sequence of events – LOFW with AFW available ............................. 38

3. Main plant signals and sequence of events – LOFW without AFW available ........................ 43

4. Main plant signals and sequence of events – SGTR ............................................................. 48

5. Main plant signals and sequence of events – 5.08 cm break size SBLOCA .......................... 53

6. Main plant signals and sequence of events – 20.32 cm break size SBLOCA ........................ 58
x 

ACKNOWLEDGMENT 

The authors acknowledge the financial support from Krško NPP and Slovenian Nuclear Safety 

Administration within CAMP program (project no. POG-3473) and from the state budget by the 

Slovenian Research Agency (program no. P2-0026). The RELAP5/MOD3.3 Krško NPP base 

input model is courtesy of Krško NPP. Special thanks also to undergraduate student (and 

scholar of NPP Krško) Martin Blazinšek for his help in drawing animation masks with SNAP. 
xi 

ABBREVIATIONS 

AFW Auxiliary Feedwater 

AMSAC ATWS Mitigation System Actuation Circuitry 

ATWS Anticipated Transient Without Scram 

CST Condensate Storage Tank 

CVCS Chemical and Volume Control System 

DEH Digital Electro Hydraulic 

ECCS Emergency Core Cooling System 

HPSI High Pressure Safety Injection 

IJS Institut “Jožef Stefan” 

LOFW Loss of Feedwater 

LPSI Low Pressure Safety Injection 

MD Motor Driven 

MFW Main Feedwater 

MPa megapascal 

MSIV Main Steam Isolation Valve 

NPA Nuclear Plant Analyzer 

NPP Nuclear Power Plant 

NR Narrow Range 

PORV Power Operated Relief Valve 

PRT Pressurizer Relief Tank 

PRZ Pressurizer 

PWR Pressurized Water Reactor 

RCP Reactor Coolant Pump 

RCS Reactor Coolant System 

s second 

SBLOCA Small Break Loss-Of-Coolant Accident 

SG Steam Generator 

SGTR Steam Generator Tube Rupture 

SI Safety Injection 

SNSA Slovenian Nuclear Safety Administration 

SV Safety Valve 

TD Turbine Driven 

1 

1. INTRODUCTION

The Krško nuclear power plant (NPP), which is a two-loop pressurized water reactor, 

Westinghouse type, before modernization in 2000 obtained plant specific full scope simulator. 

With the RELAP5/MOD2 computer code reference calculations of some design basis accidents 

were performed for the verification of Krško Full Scope Simulator in 2000. In 2004 annual 

ANSI/ANS validation was performed using RELAP5/MOD3.3 computer code. In spring 2007 

Slovenian Nuclear Safety Administration (SNSA) expressed interest to upgrade the Nuclear 

Plant Analyzer (NPA) of Krško nuclear power plant (NPP), developed for SNSA in 1997. The 

advantage of using NPA were developed masks, however the animation tool was rather 

obsolete. In addition, the RELAP5 input model including nodalization was changed after plant 

modernization in 2000 requiring modification of old masks. On the other hand, Symbolic Nuclear 

Analysis Package (SNAP) (Ref. 1) was modern tool still developing, but it use requires to start 

from scratch (no masks available). Therefore capabilities of SNAP version 0.27.3 were 

investigated first. SNAP besides animation offered also plotting through AptPlot. Due to these 

facts it was decided to make support to the analytical tools based on SNAP. 

Motivation for developing the support tool based on SNAP was to prepare for the transition from 

RELAP5 to TRACE (RELAP5 to TRACE conversion, running codes, pre- and post-processing, 

generating input deck database etc.), better understanding of the calculated physical 

phenomena and processes, user friendly tool for understanding the nodalization and the detail 

of plant modeling, better presentation of the results, a tool to train new users of thermalhydraulic code, and with modern tool to attract people to work with system codes. For 

verification of the animation models the source data were needed. SNAP tool is such that only 

calculated data support all animation features. Therefore it was decided to calculate the 

reference calculations (Refs. 3, 4, 5, 6) with the latest RELAP5/MOD3.3 Patch03 code (Ref. 2). 

The RELAP5 input model of Krško NPP is very briefly described in Section 2. The scenarios for 

reference calculations of design basis accidents are described in Section 3. The developed 

animation masks are described in Section 4. Section 5 shows the results of RELAP5/MOD3.3 

Patch 03 calculations, used as source data in SNAP. In addition, the RELAP5/MOD3.3 Patch 03 

calculations are compared to RELAP5/MOD2 and RELAP5/MOD3.3 verified calculations. In 

Section 6 are given examples of the Krško NPP animation model use, while conclusions are 

given in Section 7. 

3 

2. INPUT MODEL DESCRIPTION

To perform these analyses, Krško NPP has provided the base RELAP5 input model, so called 

“Master input deck”, which have been used for several analyses, including reference 

calculations for Krško full scope simulator verification (Refs. 7, 8, 9). The latest analyses were 

performed for uprated power conditions (2000 MWt) with new steam generators (SG) and core 

cycle 21 settings, corresponding to the plant state after outage and refueling in September 

2004. 

The model consists of 469 control volumes, 497 junctions and 378 heat structures with 2107 

radial mesh points. Besides, 574 control variables and 405 logical conditions (trips) represent 

the instrumentation, regulation isolation, safety injection (SI) and auxiliary feedwater (AFW) 

triggering logic, steam line isolation, etc. 

Modeling of the primary side without the reactor vessel and both loops includes the pressurizer 

vessel, pressurizer surge line, pressurizer spray lines and valves, two pressurizer poweroperated relief valves (PORVs) and two pressurizer safety valves, chemical and volume control 

system (CVCS) charging and letdown flow, and RCP seal flow. The reactor vessel consists of 

the lower downcomer, lower head, lower plenum, core inlet, reactor core, core baffle bypass, 

core outlet, upper plenum, upper head, upper downcomer, and guide tubes. The primary loop is 

represented by the hot leg, primary side of the SG, intermediate leg with cold leg loop seal, and 

cold leg, separately for loop 1 and loop 2. Loops are symmetrical except for the pressurizer 

surge line and the chemical and volume control system connections layout. The primary side of 

the SG consists of the inlet and outlet plenum, tubesheet, and the U-tube bundle represented by 

a single pipe. 

ECCS piping includes high-pressure safety injection (HPSI) pumps, accumulators, and 

low-pressure safety injection (LPSI) pumps. The hydrodynamic components representing HPSI 

and LPSI pumps are time-dependent junctions, while for accumulators the ‘accum’ 

hydrodynamic component was used. The ECCS connects to both cold legs and directly to the 

reactor vessel. 

The secondary side consists of the SG secondary side (riser, separator and separator pool, 

downcomer, steam dome), main steamline, main steam isolation valves, SG relief and safety 

valves, MFW piping, and AFW piping from the header to the SG. The AFW injects above the SG 

riser. The main steam no. 1 has same volumes as main steam no. 2, but the geometry data 

differ depending on pipeline. Turbine valve is modeled by the corresponding logic, while turbine 

is represented by time dependent volume. MFW and AFW pumps are modeled as time 

dependent junctions, pumping water from time dependent volumes, representing the 

condensate storage tank. For AFW pumps, recirculation flow is modeled too. 

The refueling water storage tank (RWST) is modeled as time dependent volume, similarly as the 

containment and the atmosphere. The break in the cold leg is modeled with two valves, giving 

possibility to model double ended guillotine break too. 

In order to accurately represent the Krško NPP behavior, a considerable number of control 

variables and general tables are part of the model. They represent protection, monitoring and 
4 

simplified control systems used only during steady state initialization, as well as the following 

main plant control systems: (a) rod control system, (b) PRZ pressure control system, (c) PRZ 

level control system, (d) SG level control system, and (e) steam dump. It must be noted that rod 

control system has been modeled for point kinetics. Present model can be used for transient 

analysis with two options: (a) with constant or predefined core power transient as function of 

time (including decay power calculation) or (b) with rod control system in auto or manual mode. 

The reactor protection system was based on trip logic and it generates various signals. It 

includes reactor trip signal, SI signal, turbine trip signal, steam line isolation signal, MFW 

isolation signal, and AFW start signal. 

For the nodalization details of the above mentioned plant systems and components, plant 

signals and control systems schemes the reader can refer to Section 4. 
5 

3. SCENARIOS DESCRIPTION 

In total six scenarios were analyzed: scenario of the Anticipated Transient Without Scram 

(ATWS), two scenarios of the Loss of Main Feedwater (LOFW), two scenarios of the Small 

Break Loss-of-Coolant Accident (SBLOCA), and scenario of the Steam Generator Tube Rupture 

(SGTR). Since the purpose of the analyses was to provide basis for Krško full scope simulator 

validation, NPP Krško has required a simplified, but phenomenologically clear scenarios to be 

simulated. In all cases the reactor power at transient start was at 100%. 

3.1 Anticipated Transient Without Scram Scenario

In ATWS transient with ATWS Mitigation System Actuation Circuitry (AMSAC) available it is 

assumed that both trains of ECCS and both motor driven (MD) AFW pumps were available. The 

transient is initiated by a malfunction in main feedwater system, causing total loss of normal 

feedwater, which is followed by the steam generator liquid inventory boil-off. The reactor trip 

signal is renounced and control rods are not inserted into the core to shut down the reactor. The 

liquid level in both steam generators lowers rapidly below AMSAC trip setpoint causing turbine 

trip. Consequently, as the heat transfer to the secondary side is degraded and finally 

interrupted, the rise in reactor coolant system temperature and pressure follows. This causes 

the pressurizer to get fully filled with the liquid (solid pressurizer). Soon after that the pressurizer 

relief and safety valves open and the liquid-vapor mixture is discharged into the pressurizer 

relief tank (PRT). Eventually, the PRT rupture disk breaks due to PRT over-pressurization and 

the reactor coolant is released into the containment. The moderator density and Doppler 

temperature feedback effects suppress the reactor positive reactivity and reduce the core power 

in the absence of reactor scram. Primary pressure and temperature soon stabilize near or below 

the normal operating values. Meanwhile, on the secondary side, the AFW pumps start and both 

steam generators are gradually refilled with cold water. With reduced and stabilized core power 

the secondary system is able to transfer and release the energy through the steam dump or the 

SG PORVs, depending on whether steam line is isolated or not. 

The most important parameter in this transient is the primary pressure, which should not exceed 

the ASME stress level C limit of 22.7 megapascals (MPa) (Ref. 10). For the purpose of pressure 

peak reduction AMSAC is incorporated into the safety logic (Refs. 11 and 8), in parallel to the 

reactor protection logic. The safety goal of the AMSAC system is to reduce the core power and 

maximize secondary inventory available for later plant cooldown. This is achieved by reduction 

of the steam extraction from the secondary side, which accelerates the primary temperature rise 

and the core inventory density reduction. The two above mentioned most important inherent 

feedback effects reduce the core power earlier what results in lower primary pressure peak. 

3.2 Loss of Feedwater Scenarios

For LOFW two different scenarios were analyzed. The difference between the scenarios was, 

that in the first scenario both MD AFW pumps were available and operator was maintaining 

steam generator level at no-load conditions between 68 and 72 % narrow range (NR), while in 

the second scenario all AFW pumps were unavailable. It is assumed that both trains of ECCS 

are available, rod control system was in MANUAL mode (temperature feedback blocked) and 
6 

operator action to trip the RCP is modeled. It is assumed that the loss of main feedwater flow is 

caused by malfunction in MWF system, therefore AFW system will not start on the MFW 

isolation signal, but will be delayed till one of the SG narrow range levels drops below low-low 

setpoint at 13 %. Main characteristic of LOFW transient is gradual emptying of steam 

generators, while heat transfer to secondary side is still possible. Heat transfer is soon 

degraded during partial uncovering of the U-tubes and finally interrupted with complete 

emptying of steam generators. The consequences of the loss of heat sink to the secondary side 

reflect in increasing average coolant temperature and pressure on the primary side. Due to 

increased primary pressure the pressurizer relief and safety valves open and part of the primary 

coolant is released into the PRT. If the AFW flow is established, there is no further threat to the 

core. The AFW inflow ensures sufficient secondary coolant resource to establish stable 

secondary heat sink either through steam dump, SG relief or SG safety valves. When no heat 

sink could be established on the secondary side and if no other operator intervention is 

assumed, the pressurizer relief and safety valves open and close between their set and reset 

pressures to remove the decay heat from the primary system. This is satisfactory only until the 

amount of the primary coolant lost is such that core uncovering occurs. 

3.3 Small Break Loss-of-Coolant Accident Scenarios

For SBLOCA the 5.08 cm and 20.32 cm equivalent diameter break size scenarios were 

analyzed. For 5.08 cm cold leg break both trains of ECCS system were available and both MD 

AFW pumps. Each ECCS train consists of HPSI and LPSI pumps, and passive accumulators. 

For 20.32 cm cold leg break loss of off-site power was assumed and successful emergency 

diesel generator start. After the emergency diesel generator start one train of safety systems 

was available. No operator actions were specified in the scenarios except RCP trip per 

emergency operating procedures. In the case of 5.08 cm break rapid primary pressure drop 

after break opening causes the reactor trip on low pressurizer pressure signal at 12.99 MPa. 

The safety injection (SI) signal is generated on the low-low pressurizer pressure signal at 12.27 

MPa. The SI signal actuates the ECCS and MD AFW pumps. On SI signal coinciding with high 

steam generator level signal also both MFW pumps are tripped. The RCPs are tripped manually 

on subcooling signal according to the emergency operating procedures allowing additional 60 

seconds for operator actions. The accumulators start to inject at 4.93 MPa. In the case of 20.32 

cm break simultaneous break opening and loss of offsite power is assumed. So the reactor trip, 

SI signal, both RCPs trip, MFW trip and turbine trip occur at 0 seconds. 

3.4 Steam Generator Tube Rupture Scenario

In SGTR accident it is assumed that both trains of ECCS and both MD AF pumps were 

available and rod control system was in MANUAL mode (temperature feedback blocked). There 

were no operator actions assumed except isolation of the ruptured SG, when the NR liquid level 

difference between the intact and ruptured SG exceeds 5%, and maintaining of the SG liquid 

level at no load conditions between 68% and 72 % NR in the intact SG. After the tube rupture 

initiation similarly as in SBLOCA accident, pressure in the pressurizer starts decreasing. All 

pressurizer heaters are switched on trying to rebuild the primary pressure, while CVCS is trying 

to restore the primary coolant inventory (pressurizer level). However pressurizer pressure and 

level continue to decrease. When the pressurizer level drops below 18 %, the letdown is 

isolated and the pressurizer heaters are turned off. Following this event, more rapid pressure 

decrease causes the reactor trip and turbine trip. The reactor trip causes decreasing of the 

primary system average coolant temperature, while the primary pressure continues to decrease 
7 

due to the rupture flow. Primary and secondary pressures start to equalize, so the rupture flow 

soon starts to decrease and turns from critical to pressure difference driven flow. The SI 

actuation setpoint is reached soon due to initial depressurization of the primary system. The 

HPSI pumps start to pump with the delay according to the SI triggering sequence after the SI 

signal is generated. On the secondary side immediately after the reactor trip, turbine is tripped 

and soon MFW is isolated. AFW pumps start shortly after MFW isolation. Due to the rupture 

flow from primary side, the mixture levels and pressure in both steam generators start to 

increase. The SG relief valves are expected to open when the secondary pressure reaches 7.5 

MPa. 

9 

4. DESCRIPTION OF DEVELOPED ANIMATION MASKS

Animation masks were developed at Institut “Jožef Stefan (IJS) with the aim to present the 

RELAP5 input model, which is described in Section 2, in a user friendly way. Animation masks 

were developed for the plant systems and components, the plant signals and the control 

systems. The animation masks are shown with color maps for Display Bean animation mostly at 

time 0 second after which transients were simulated. The data shown at 0 second are steady 

state results of RELAP5 input model for Krško NPP at 100% power. Therefore, each Data Value 

on animation mask represents initial condition for the reference calculations performed for Krško 

full scope simulator validation. 

4.1 Animation Masks of Plant Systems and Components

Animation masks of systems and components were created for the primary and secondary 

system representing a plant, the reactor vessel, the pressurizer with pressurizer relief tank, the 

steam generator (primary and secondary side), the emergency core cooling system, the main 

steam system, the main feedwater and the auxiliary feedwater system. 

4.1.1 General Plant Mask 

The general plant mask showing primary and secondary system is shown in Figure 1. Shown is 

the detail of the primary and secondary system modeling. Shown are volumes, pumps and 

valves. Information on volume number can be very easily obtained when mask is displayed in 

SNAP Model Editor or from more detailed masks for reactor vessel, pressurizer, ECCS, main 

steam system and auxiliary feedwater system. Junctions and heat structure are not shown, with 

exception of valves and a few arrows created by Line Annotation. The arrows indicate the 

normal direction of flow. From Figure 1 it can be very easily seen the number of safety and relief 

valves on pressurizer and steam generators and their status. Status is given also for the pumps. 

Green color means open valve and running pump, and red the opposite. It can be seen that 

secondary side is modeled up to the turbine and steam dump system. Main feedwater, auxiliary 

feedwater and emergency core cooling system are shown in more detail in separate masks. 

There are several pumps shown, but reactor coolant pumps are the only pumps modeled by 

RELAP5 ‘pump’ card. The other pumps are modeled by ‘tmdpjun’ cards as it is schematically 

shown in Figures 8 and 9 by volume and junction inside the SNAP Simple Pump component. 

SNAP component can be animated by different Color Maps. The selected color map for 

volumes in Figure 1 is Void Fraction Color Map. For core the Temperature Color Map was 

selected. SNAP offers a variety of color maps. However, the color map can be changed in one 

step for the same Plant Components and Indicators only. In our case the Single Volume, 

Plenum, Pipe Elbow and Polygon were used for hydrodynamic volumes. 

In Figure 2 is shown plat mask for the fluid condition. One can very easily see that primary side 

is subcooled liquid, while on the secondary side there is saturated liquid and steam. Please note 

that due to simplification the steam generator downcomers are not shown. They are shown in 

more detailed SG masks (see Figures 5 and 6). 
Figure 1 General plant mask after 1000 seconds of steady state – void color map 

10 

Figure 2 General plant mask after 1000 seconds of steady state – fluid condition color 

map 
4.1.2 Reactor Vessel Mask 

The reactor vessel mask gives details about the phenomena in the reactor vessel, especially 

during uncovery. First of all, the geometry of the reactor vessel is shown detailed comparing to 

the plant mask from which separate volumes are not seen. Besides, the directions of flows are 

also shown. When the flow direction changes, the color changes (in our case green color 

means normal flow and red the opposite direction). Core uncovery can be seen from Void 

Fraction Color Map and also from Fluid Level indicator. On the left side the reactor vessel like in 

the plant is drawn and described. The main parameters given are core power and heat transfer, 

pressure and temperature in the reactor head, and hot and cold leg flows. Finally, rod position is 

shown by Fluid Level indicator, where 609 steps mean fully withdrawn control rods and 0 steps 

reactor scram. 

Figure 3 Reactor vessel mask after 1000 seconds of steady state 

4.1.3 Pressurizer Mask 

Pressurizer mask shows the reactor coolant system from surge line to pressurizer relief tank. 

Shown is pressurizer with electrical heaters and sprays, power operated relief valves and safety 

valves, and the associated piping. The pressurizer mask is important for pressurizer pressure 

and level control, and for transient with emptying and filling the pressurizer. One can clearly see 

the loop seal filled with the water before safety valves. From the main plant parameters are 

shown pressures, temperatures and flows. From flows are shown flow through surge line, 

11 
sprays and PORVs and SVs. Shown is also pressurizer level as measured in the plant. The 

mask is useful especially for heatup events with overpressurization (e.g. ATWS). 

Figure 4 Pressurizer mask after 1000 seconds of steady state 

4.1.4 Steam Generator Masks 

There are two loops and each steam generator is on its own mask. Shown are the primary and 

the secondary side of the steam generator. On the primary side one can see the inlet and outlet 

plenum and U-tubes represented by a single pipe. On the secondary side there are downcomer 

and riser, the separators and the dryer. Shown are inlets for main feedwater and auxiliary 

feedwater flow and the piping inside the steam generator including J pipes and AFW injection 

above the separators. From the parameters are shown flows (cold and hot leg, SG downcomer 

and riser, main feedwater and auxiliary feedwater system, main steam system) and their 

temperatures. Shown are also SG parameters like pressure, wide and narrow range level, 

recirculation ratio, power and mass. Besides the mass in the steam generator is shown also the 

mass discharged through SG PORV and SG safety valves. The mask is very useful for 

transients with core cooling by the secondary side. 

12 
Figure 5 Steam generator no. 1 mask after 1000 seconds of steady state 

13 

Figure 6 Steam generator no. 2 mask after 1000 seconds of steady state 
4.1.5 Main Steam System Mask 

The steam generator masks end on the secondary side, the main steam system mask starts. 

Shown are the main steamlines from the steam generator up to the turbine and steam dump 

system. Included are main steam isolation valves and SG PORVs and safety valves. For each 

relief valve the flow and mass discharged are shown. Other parameters shown are steam flows, 

turbine flow, feedwater flow, auxiliary feedwater flow and steam dump flow. For each steam 

generator are shown total mass discharged, pressure and level. Finally, turbine power is given. 

Figure 7 Main steam system mask after 1000 seconds of steady state 

4.1.6 Main Feedwater System Mask 

The main feedwater systems shows piping from the MFW pump modeled as time dependent 

junction to the J-ring tubes in the steam generator. Shown are the control and isolation valve 

with their status, green indicating open valve and red indicating closed valve. From parameters 

are shown MFW control valve area, flow and temperature. For each SG are shown main 

parameters like SG pressure and level, and steam flow. The mask is useful when we are 

interested on status of the feedwater system (pump running, control valve opening, status of 

feedwater isolations valves and the value and temperature of the flow). 

14 
Figure 8 Main feedwater system mask after 1000 seconds of steady state 

4.1.7 Auxiliary Feedwater System Mask 

Similar information like for main feedwater is given also for auxiliary feedwater. From the mask 

shown in Figure 9 it can be seen that there are three AFW pumps. Two are motor driven AFW 

pumps each injecting into one steam generator and one is turbine driven (TD) AFW pump, 

injecting to both steam generators through header. Each pump is modeled by time dependent 

junction. Besides injecting flow path is modeled also recirculation flow path to condensate 

storage tank (CST). For each steam generators are given parameters on SG pressure and 

level, main feedwater flow and steam flow. For each AFW pump is given flow, temperature of 

the flow and integrated mass flow to each SG, recirculation flow and discharge pressure of the 

pumps. 

15 
Figure 9 Auxiliary feedwater system mask after 1000 seconds of steady state 

4.2 Animation Masks of Plant Signals

Various signals based on trip cards logic are included in the RELAP5 input model of Krško NPP. 

The following signals were presented on the animation masks: 

• reactor trip signal, 

• SI signal, 

• turbine trip signal, 

• steam line isolation signal, 

• MFW isolation signal, and 

• AFW start signal. 

In addition, mask with main signals and sequence of events was created. SNAP RELAP5 plugin offers all RELAP5 TRIP cards. However, the time when trip occurs is not available from 

restart-plot file. For the time being, no TRIP “time-of” plot variables were introduced in the 

RELAP5 input model. This information is available from the printed output file (trip time for trip 

number), but SNAP cannot use such data source. The only solution was therefore to use the 

Python data source. The trip times were determined from trip data time trends at times 

determined by plot frequency. The problem is when there is large number of time advances of 

plot data, since the trip times are not exact times, but rounded values. 

16 
4.2.1 Reactor Trip and Safety Injection Signal Mask 

The reactor trip and safety injection signal presenting reactor protection system are shown in 

the same mask, each in its own table. For each reactor trip and safety injection signal is given 

trip setpoint (some are calculated, e.g. overtemperature delta T), status of the trip (0 indicating 

false and 1 indicating true), the time of the trip and the assumed delay of the signal. It should be 

noted that only the first reactor trip cause the reactor scram, while subsequent trips just reflect 

the conditions at which the trip would occur, but this is not physical because of the reactor 

scram after which the course of transient is completely changed. Nevertheless, this reflect the 

RELAP5 as in each time step each trip number is recalculated. 

Figure 10 Reactor trip and safety injection signal mask after 1000 seconds of steady 

state 

17 
4.2.2 Turbine Trip and Feedwater Isolation Signal Mask 

Second mask dealing with signals is for turbine trip and feedwater isolation. The turbine is 

tripped automatically on reactor protection signals, on any high SG level signal and AMSAC 

signal. In addition, it can be tripped manually. 

Feedwater isolation occurs on similar signals as turbine trip with the exception that there must 

be coincidence between the reactor trip and low average RCS temperature signals and there is 

no AMSAC signal. 

Figure 11 Turbine trip and feedwater isolation signal mask after 1000 seconds of steady 

state 

18 
4.2.3 AFW Start Signal Mask 

Auxiliary feedwater is also started automatically besides manual start. Both MD AFW pumps 

start on any low SG level, in case of both MFW pumps trip, on SI and AMSAC signal. The 

pumps can be started manually, too. Manual start is used also to simulate blackout sequence. 

TD AFW pump is started when both SG levels are low and on AMSAC signal. It can also be 

started manually. Manual AFW pump start is used also to simulate blackout sequence. 

Figure 12 AFW start signal mask after 1000 seconds of steady state 

19 
4.2.4 MSIV Isolation and RCP Trip Signal Mask 

The last signals simulated are MSIV no. 1 and MSIV no. 2 isolation signals, and RCP no. 1 and 

RCP no. 2 signals. Main steamline is isolated on high steam flow in any steamline when 

coincident with low-low average temperature and SI signal, high-high steamline flow in any 

steamline in coincident with SI signal, low steamline pressure in any steamline (permissible 

bypass if RCS pressure less than 13.89 MPa), high-high containment pressure and manual 

(operation either will operate both). 

Figure 13 MSIV isolation and RCP trip signal mask after 1000 seconds of steady state 

20 
4.2.5 Main Signals and Sequence of Events Mask 

This mask shows the transient timing and status of the trip, 0 indicating false and 1 indicating 

true value. The signals shown are reactor trip, safety injection (SI) signal, turbine trip, steam line 

isolation, and main feedwater isolation. More detailed masks for these signals are given above. 

Sequence of events mainly consists of systems and components start times such as ECCS 

system, AFW system, CVCS system (charging and letdown) and steam dump system. For each 

ECCS subsystem it is shown when it is initialized (setpoint reached) and time at which started to 

inject. For additional information, injected flow or mass is shown. The reason for distinguishing 

the initialization time and injection time is, that pumps may be started; however the pressure 

might be higher than the pump head. Similarly it is done for AFW system. For reactor coolant 

pumps the trip times are shown, for charging and letdown the isolations times are given and 

finally, the start time of steam dump in case of plant trip. 

Figure 14 Main signals and sequence of events mask after 1000 seconds of steady state 

21 
22 

4.3 Animation Masks of Control Systems

The animation masks for the following control systems were developed: 

• rod control system, 

• pressurizer pressure control system, 

• pressurizer level control system, 

• steam generator level control system (both loops), 

• turbine power control (artificial), and 

• steam dump. 

The animation models are not represented by control blocks available in SNAP animation plugin. Rather, new blocks (just graphically) were created similar to Simulink and following the 

standard drawings of Westinghouse PWR control systems. The values are shown using Data 

Value indicator. This integrated view improves the understanding, how controls work and are 

much more suitable for the analyst and training purposes. It is not purpose to explain in detail 

how control systems works, but to present the layout of animated masks, and the data shown. 
4.3.1 Rod Control System Mask 

The animation mask for rod control system is shown in Figure 15. After 1000 seconds of steady 

state the reactor point kinetics model was introduced into the input model, what can be seen 

from the text annotation colored orange and labeled “Automatic rod control system active”. This 

also means that rod control is not in manual. The steady state values of reactor and turbine 

power slightly deviates like the temperature. Nevertheless, the control rods are not moving. The 

rod control systems model includes power and temperature mismatch units giving the 

temperature error, which is input to rod speed program. The reactor control unit to generate rod 

speed program is in the RELAP5 modeled with a number of control blocks and trip logic. It 

converts the temperature error to rod speed. The rod speed program simulated the deadband, 

the lock-up, the minimum (8 steps/min.), proportional and maximum speed (72 steps/min.). The 

rod speed determines the rod position (609 steps mean fully withdrawn rods) and depending on 

the position the control rod reactivity is determined through table. Total reactivity is determined 

based on control rods and shutdown rods reactivity. By automatic positioning the control rods 

the control system maintains the programmed average temperature during power operations. 

Figure 15 Rod control system mask after 1000 seconds of steady state 

23 
4.3.2 Pressurizer Pressure Control System Mask 

The pressurizer pressure control system mask is shown in Figure 16. The control system 

controls the pressure of reactor control system at reference pressure, during both steady state 

and design transient conditions. In the selected 5.08 cm break size SBLOCA the pressure 

started to drop and after 1 second the pressure error is about 2 bars. This pressurizer pressure 

signal feeds proportional-plus integral (PI) controller before being used to control proportional 

and back-up heaters, spray valves and one of the two pressurizer PORVs. This compensated 

error signal is around 11 bars, what is more than sufficient to turn on the backup heaters. This 

can be also seen from information on the right side of Figure 16, as text box “Backup heaters 

ON (pressure deviation” is colored orange. The backup heaters could be switched on also in the 

case of 5% pressurizer level deviation. As pressurizer level is greater than 18%, the backup 

heaters are active. This mean they can operate when demanded. One can also see that in the 

case of low reactor coolant pump flow the backup heater control is disabled. This is operator 

correction in pressurizer control systems automatic operation due to low RCS flow causing 

dubious average temperature measurement with resistance temperature detectors. 

Figure 16 Pressurizer pressure control system mask after 1 second for 5.08 cm break 

size SBLOCA 

24 
4.3.3 Pressurizer Level Control System Mask 

The pressurizer level control system mask is shown in Figure 17. The control system controls 

the charging flow to maintain the programmed level in the pressurizer. As can be seen the 

charging flow is modeled by time dependent junction. The level signal is a simulation of the 

differential pressure measurement, taking into account calibration (based upon pressurizer 

temperature). The simulated measured level signal is compared to the programmed level, 

depending on the average temperature (maximum from the two loops). The resulting level error 

signal feeds PI controller, which controls the CVCS charging flow. This is done through 

comparing flow signal based on compensated level error with the charging flow signal. Also 

level error signal feeds the PI controller. The “fixed letdown flow” is zero when pressurizer level 

control is ON; otherwise it is equal to letdown flow. The resulting charging flow in % then 

determines the actual charging flow, modeled by time dependent junctions. In addition, it is 

used to calculate the charging flow signal. In Figure 17, showing conditions 15 seconds after 

5.08 cm break size SBLOCA occurence, it can be seen that pressurizer level control is on, 

therefore fixed letdown flow is zero. The letdown system is also on. The charging flow is larger 

than letdown flow, because the level is below the programmed level. Additional information is 

also given on the status of charging and letdown flow (ON/OFF) to be promptly alarmed. 

Finally, as can be seen in Figure 17, the uncompensated level error is input to the pressurizer 

control system in order to switch on backup heaters when pressurizer level is 5% higher than 

the programmed level. 

Figure 17 Pressurizer level control system mask after 15 seconds for 5.08 cm break size 

SBLOCA 

25 
4.3.4 Steam Generator Level Control System Masks 

The steam generator level control system masks for loop 1 and 2 are shown in Figure 18 and 

Figure 19, respectively. The main purpose of the steam generator water level is to control the 

feedwater flow to maintain a programmed level in the steam generators. Each steam generator 

has its own controller. First the actual level signal, sent through a lag unit to dampen out any 

oscillations in the signal, is compared to the programmed level. The level error is then sent to PI 

controller where it is converted into an equivalent flow error. This flow error signal is then 

combined with steam flow and feedwater flow to produce a total error in the PI controller. This 

signal is then used to position the main feedwater control valve. 

Figure 18 shows the condition at the end of steady state for SG 1 level control. It can be seen 

that artificial control to achieve steady state is on and that desired level is achieved. Besides 

level also steam and feedwater flow are balanced, therefore there is no valve area change 

needed. 

Figure 18 Steam generator no. 1 level control system mask after 1000 seconds of steady 

state 

Figure 19 shows the conditions after 8 seconds of LOFW accident for SG 2 level control. It can 

be seen that at 8 second MFW valve is closed (closure time is 7 seconds). In order to simulated 

LOFW accident by assumption the MFW control valve started to close at 0 second. 

26 
Figure 19 Steam generator no. 2 level control system mask after 8 seconds of LOFW 

scenario 1 

4.3.5 Turbine Power Control Mask 

To control the operation of the turbine the digital electro hydraulic (DEH) control system was 

designed in Krško NPP (in 2009 was replaced by programmable DEH). In the RELAP5 model 

the secondary side was modeled up to the turbine control valves. To simulate the turbine and 

power control the artificial turbine power control was introduced into the RELAP5 input model. 

The animation mask of artificial turbine power control is shown in Figure 20. 

To understand how this control works, it must be explained that the turbine flow is modeled by 

control valve discharging to time dependent volume. In addition, in the case of turbine runback 

or external perturbation (load function defined by RELAP5 user), the turbine flow (see upper 

part of Figure 20) is established through the time dependent junction. In the case of turbine trip 

or demanded constant flow the flow is regulated by the turbine valve. Demand on the turbine 

valve area change is by assumption such that control of turbine governor valve preserves 

constant mass flow through the turbine (mass flow through the turbine after the end of steady 

state). Scaling factor for error in mass flow and lag constant were based on the engineering 

judgment. The part with temperature error is just to compensate average temperature error 

during steady state calculation. Calculation of this error is enabled only during steady state 

calculation (artificial control ON – value 1). During steady state calculation turbine governor 

valve area regulates SG pressure to achieve desired RCS Thot temperature. Following the end 

27 
of steady state calculation, control system regulates turbine valve area to preserve constant 

mass flow to turbine as already mentioned. 

Figure 20 shows conditions 2 seconds after transient start. In this case artificial control is OFF 

and turbine valves are opened. The flow error between turbine flow and turbine flow at the end 

of steady state is very small; therefore the turbine valve area not changes much. In the bottom 

part of artificial turbine power control system the power is determined based on turbine mass 

flow. There are four contributors to power: power at turbine trip, power at turbine runback, power 

at external perturbation, and power when all these trips are off. From them the final turbine 

power is determined. The feedback is turbine mass flow. In the case of turbine runback and 

external perturbation it is simulated by time dependent junction. When neither turbine runback 

nor external perturbation is present, turbine valve area is changed. In the case of turbine trip the 

turbine valve closure is simulated. When none of the three trips is present, the constant mass 

flow is maintained. 

The status of turbine stop valves and the above mentioned trips is shown at top on the right in 

Figure 20. Orange color means that value is true. White value means the value is false (as font 

color is white the text is not visible). At present the turbine stop valves are closed. This also 

means that there is no turbine trip (second box from top). Third box indicates there is no 

external perturbation. Fourth box indicates there is no turbine runback. 

Figure 20 Turbine power control system mask after 2 seconds of LOFW scenario 1 

28 
29 

4.3.6 Steam Dump Control Mask 

Steam dump model is represented by simplified time dependent junction and its flow is 

calculated by steam dump control system shown in Figure 21. Steam dump control system 

consists of steam dump Tavg control for load follow and turbine trip, as well as steam header 

pressure control. The corresponding controllers are load rejection controller, turbine trip 

controller and steam pressure controller. One mode of operation can be selected at a time: 

Tavg mode and pressure mode. During normal power operations generally greater than 15% 

thermal power, the steam dump is placed in the Tavg mode. Until turbine trip, loss of load 

controller is automatically selected. When turbine trip occurs, loss of load controller is 

disconnected and turbine trip controller is enabled. The two controllers differ according to their 

functions. The function of loss of load controller is to provide alternate heat sink until rod control 

system reduces reactor power to match turbine power. Therefore the load reduction controller 

has a deadband to allow for control rod motion before the steam dump valves begin to open. 

The function of the turbine trip controller is to remove decay heat and stored energy to return 

Tavg to its no load value. There are ten valves which are divided into four groups. Each valve 

has 10% capacity. In group a are two valves, in group b three valves, in group c two valves and 

in group d three valves. To arm the loss of load, there are two interlocks, one set to 10% 

sudden load loss and the other 50% sudden load loss. In the case of 10% sudden loss load, 

only first half of valves will be armed (groups a, b). When sudden loss load is greater than 50% 

step, second group is also armed (groups c, d). In the case of turbine trip only the first half of 

valves are armed (groups a, b). The temperature difference modulates open steam dump 

valves. When this difference originally is higher than the controller can handle, first group of 

valves is fully opened. If the temperature error continues increasing, second group is fully 

opened. The bistable trip setpoints for turbine trip controller are higher than those for loss of 

load controller. 

Figure 21 shows steam dump system operated in Tavg mode during LOFW scenario no. 1. 

Load rejection controller is enabled and first two groups are armed. As temperature difference is 

below trip bistables setpoints, the steam dumps valves are modulated open. Total steam dump 

(SD) flow is calculated from the contributions from the three above mentioned controllers, with 

only loss of load controller contributing. There is no main steam isolation valve closure or RCP 

trip. In such cases the steam dump flow is not calculated. When steamlines are isolated the 

steam flow is not feasible. In the case of RCP trip the reason for not calculating steam dump 

flow is dubious Tavg measurement, and steam dump can be put to manual. 
Figure 21 Steam dump control system mask after 30 seconds of LOFW scenario 1 

30 
31 

5. RESULTS OF RELAP5 CALCULATIONS 

The calculated results of scenarios for ATWS, LOFW, SBLOCA and SGTR, described in 

Section 3, are presented. Compared are RELAP5/MOD2 (input model for cycle 17), 

RELAP5/MOD3.3 (input model for cycle 19), RELAP5/MOD3.3 (input model for cycle 21) and 

RELAP5/MOD3.3 Patch 03 (input model for cycle 21). The RELAP5/MOD2 is the last, frozen 

computer code version 36.05 from 1989. The RELAP5/MOD3.3 is computer code version 3.3bf 

from February 2002 and RELAP5/MOD3.3 Patch 03 is computer code version 3.3gl from March 

2006. The calculations with RELAP5/MOD3.3 and RELAP5/MOD3.3 Patch 03 computer codes 

were performed using same initial conditions and models. In general, the differences for the 

indicated variables are small. Besides different initial conditions (reactor kinetics feedbacks, 

initial pressurizer level, initial SG level, different SG level regulation, consideration of pump seal 

flow) important difference between RELAP5/MOD2 and RELAP5/MOD3.3 calculations was the 

break flow model used (Ransom-Trapp versus Henry-Fauske). As can be seen, the cycle 21 

calculation with RELAP5/MOD3.3 Patch 03 is just reanalysis and results in principle should be 

the same except for code improvements influence. The main aim of reanalysis was to prepare 

the source data for SNAP animation model with the latest RELAP5 and not to compare RELAP5 

calculations with different versions. Nevertheless, the comparison was done with previous 

versions in order to be sure that the calculated data are comparable to the previously verified 

reference calculations. The reasons for discrepancies are also explained. 

For each scenario the sequence of events for RELA5/MOD3.3 Patch 03 is given, created by 

SNAP animation model. In addition, a few important variables are shown and described to 

understand the transient. This will help the user of the Krško NPP animation model to 

understand the transients when animating the SNAP masks with the source data of reference 

calculations. 

5.1 Anticipated Transient Without Scram Results

The results for ATWS are shown in Table 1 and Figures 22 through 30. ATWS transient started 

at simulation time 0 s, when both main feed water lines to the steam generators were closed 

due to malfunction in the main feed system. Initially, absence of the subcooled main feedwater 

flow into the steam generators slowed down the recirculation and caused increased steam 

production in the saturated secondary liquid-vapor mixture. The low-low SG level alarm (NR 

level < 13 %) started the AFW pumps around 56 second. Due to degraded SG ability to remove 

the heat produced in the core (fission + decay) the secondary pressure started to increase as 

shown in Figure 22. At the same time the AFW flow was insufficient to refill the SG. This 

resulted in secondary pressure initial rise. Before the turbine trip the steam from the steam 

generators was released through the condenser via turbine at 100 % mass flow rate. Since the 

SG inventory was discharged (Figure 23), the steam line pressure soon started to decrease, 

which produced SI signal at time 97 seconds. That caused the turbine trip, steam line isolation 

(Figure 24) and also disabled steam dump operation. Meanwhile, due to SG PORV and safety 

valves opening, SG water level is further decreasing till the steam generators dry out at time 

around 91 seconds (SG NR level below 1 %). After the turbine trip the steam produced in steam 

generators is released through SG PORVs. Shortly after that (within the next 100 seconds) 

steady state was reached on the secondary side and the SG PORVs steam release was 

balanced by the cold water delivered from the AFW system. 
Table 1 Main plant signals and sequence of events - ATWS 

According to the NPP Krško Technical Specification the reactor trip signal is not produced 

therefore the reactor remains at full power 2000 MWt after the closure of the feedwater lines. 

Since low SGs water level disabled the heat extraction from the primary side, the primary 

pressure and coolant temperature started to increase. This caused primary coolant expansion. 

The pressurizer, which is compensating transient consequences, started to fill with liquid and 

the liquid level reached the top (solid pressurizer). At increased primary pressure above 17.2 

MPa (Figure 25), PRZ PORVs and safety valves opened. The primary coolant average 

temperature increase has negative feedback effect on core reactivity. During the initial steady 

state operation reactivity was kept around 0 (Figure 26). It started to decrease in the beginning 

of the primary coolant average temperature increase (Figure 27) and reached its minimum value 

around 150 seconds. The reactor core power was decreased to minimum around 300 seconds 

(Figure 30) what resulted from negative feedback effects caused by primary coolant average 

temperature increase. Before AMSAC intervention steam extraction from both steam generators 

increased, causing primary coolant average temperature decrease and consequently positive 

32 
feedback effects. A short return to power was observed after that, at around 400 second. Later 

in the transient (after 2000 seconds), steady state was reached. 

The root cause for slight differences between RELAP5/MOD3.3 and RELAP5/MOD3.3 Patch 03 

was the mass flow through PRZ PORVs. In the case of RELAP5/MOD3.3 Patch 03 more mass 

was discharged through PRZ PORVs comparing to RELAP5/MOD3.3 as can be seen in Figures 

29 and 30 (flow is shown in the period from 0 to 500 seconds). The PRZ PORVs were modeled 

by motor valve. PRZ PORVs were initially opened approximately in the period between 70 and 

200 second. Therefore in the RELAP5/MOD3.3 Patch 03 calculation pressure drops 14 seconds 

faster below the HPSI pump shutoff head than in the RELAP5/MOD3.3 calculation. Earlier 

injection caused further pressure decrease causing higher injection flow and the time difference 

in HPSI flow termination at around 700 seconds was already 50 seconds. As the pressures at 

that time were very close to the shutoff head, and due to the fact that injection initially also helps 

to further reduce the pressure, in RELAP5/MOD3.3 Patch 03 calculation the injection after 800 

seconds lasted approximately 300 seconds longer than in the RELAP5/MOD3.3 calculation, and 

that causes differences in the primary pressure, in spite of the fact that flow was only a few kg/s. 

The primary pressure further influences the primary coolant average temperature. In the case 

with more injected water the temperature drops more. The other parameters agree rather well. 

6

6.5

7

7.5

8

0 2000 4000 6000 8000 10000

Time (s)

Pressure (MPa)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 22 Steam generator no. 1 pressure – ATWS 

33 
0

10

20

30

40

50

60

70

0 2000 4000 6000 8000 10000

Time (s)

Level (%)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 23 Steam generator no. 1 narrow range level – ATWS 

34 

0

100

200

300

400

500

600

700

0 2000 4000 6000 8000 10000

Time (s)

Flow (kg/s)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 24 Main steamline no. 1 flow – ATWS 
12

13

14

15

16

17

18

0 2000 4000 6000 8000 10000

Time (s)

Pressure (MPa)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 25 Primary pressure – ATWS 

-1.4

-1.2

-1

-0.8

-0.6

-0.4

-0.2

0

0.2

0 2000 4000 6000 8000 10000

Time (s)

Reactivity ($)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

35 

Figure 26 Reactivity – ATWS 
570

580

590

600

610

0 2000 4000 6000 8000 10000

Time (s)

Temperature (K)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 27 Primary coolant average temperature – ATWS 

0

500

1000

1500

2000

0 2000 4000 6000 8000 10000

Time (s)

Power (MW)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

36 

Figure 28 Core power – ATWS 
0

10

20

30

40

50

60

70

80

90

0 100 200 300 400 500

Time (s)

Flow (kg/s)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 29 Pressurizer PORV no. 1 mass flow – ATWS 

0

10

20

30

40

50

60

70

80

90

0 100 200 300 400 500

Time (s)

Flow (kg/s)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

37 

Figure 30 Pressurizer PORV no. 2 mass flow – ATWS 
5.2 Loss of Feedwater Results

5.2.1 Loss of Feedwater with Auxiliary Feedwater Available Results 

The results for LOFW with AFW available are shown in Table 2 and Figures 31 through 36. Due 

to unavailability of all data for RELAP5/MOD3.3 calculation of cycle 21 only three calculations 

were compared. Table 2 shows main sequence of events for the LOFW scenario, as calculated 

by RELAP5/MOD3.3 Patch 03 code. The triggering time for each event is given. The loss of 

feedwater leads to reactor trip after reaching low-low level setpoint in the steam generator 

(Figure 31), set to 13 % NR span. This consequently caused turbine trip. The primary pressure 

decreased (Figure 32) due to the reactor trip, while the secondary pressure increased due to 

the turbine trip (Figure 33). 

Table 2 Main plant signals and sequence of events – LOFW with AFW available 

When the auxiliary feedwater was activated, it started to fill steam generators. Pressurizer 

pressure rate sensitive PORV no.1 discharged briefly (see pressure spike in Figure 33) around 

55 second, while no secondary coolant was discharged through SG PORVs into the 

38 
atmosphere. During the initial transient stage and later the steam dump provided the continuous 

heat sink (Figure 34). The second PRZ PORV has never opened. As it can be seen from Figure 

31, the auxiliary feedwater refilled the steam generator no. 1, so the accident consequences 

were successfully mitigated. CVCS pumps have successfully recovered primary inventory 

(Figure 35), so the core was never uncovered (Figure 36) and thus fuel rods never over-heated. 

The results showed that practically there are no differences between RELAP5/MOD3.3 (cycle 

19) and RELAP5/MOD3.3 Patch 03 (cycle 21). This means that LOFW transient with AFW 

available is not very much sensitive to fuel cycle. 

0

10

20

30

40

50

60

70

80

0 2000 4000 6000 8000 10000

Time (s)

Level (%)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 P03 - cycle 21

Figure 31 Steam generator no. 1 narrow range level – LOFW with AFW 

39 
12

13

14

15

16

17

18

0 2000 4000 6000 8000 10000

Time (s)

Pressure (MPa)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 P03 - cycle 21

Figure 32 Primary pressure – LOFW with AFW 

6

6.5

7

7.5

8

0 2000 4000 6000 8000 10000

Time (s)

Pressure (MPa)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 P03 - cycle 21

40 

Figure 33 Steam generator no. 1 pressure – LOFW with AFW 
0

100

200

300

400

0 2000 4000 6000 8000 10000

Time (s)

Flow (kg/s)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 P03 - cycle 21

Figure 34 Steam dump flow – LOFW with AFW 

0

10

20

30

40

50

60

70

80

90

0 2000 4000 6000 8000 10000

Time (s)

Level (%)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 P03 - cycle 21

41 

Figure 35 Pressurizer level – LOFW with AFW 
0

1

2

3

4

0 2000 4000 6000 8000 10000

Time (s)

Level (m)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 P03 - cycle 21

Figure 36 Core collapsed liquid level – LOFW with AFW 

5.2.2 Loss of Feedwater without Auxiliary Feedwater Available Results 

The results for LOFW with AFW available are shown in Table 3 and Figures 37 through 43. 

Table 3 shows main sequence of events for the LOFW scenarios, as calculated by 

RELAP5/MOD3.3 Patch 03 code. The triggering time for each event is given. The loss of 

feedwater leads to reactor trip after reaching low-low level setpoint in the steam generator 

(Figure 37), set to 13 % NR span. This consequently caused turbine trip. The primary pressure 

decreased (Figure 38) due to the reactor trip, while the secondary pressure increased due to 

the turbine trip (Figure 39). 

Almost exactly as in the LOFW scenario with AFW available, negligible amounts of primary 

coolant was lost in the initial time period. At 618 seconds the SI signal was generated due to 

low-low steam line pressure (Figure 39), which caused the steam line isolation and disabled the 

steam dump operation (Figure 40). After the emptying of steam generators the primary 

temperature and pressure (Figure 38) started to increase. After 1200 seconds the pressurizer is 

full of liquid (Figure 41). The core uncovering could not be prevented, because the primary 

pressure became higher than the shutoff head of HPSI and CVCS pumps (Figure 42). 

Considerably more coolant has been lost to through PRZ PORVs. In fact this loss of primary 

coolant caused core dryout and overheating. As can be seen from Figure 43 core heat-up 

started after approximately 3000 seconds. Transient was terminated at 5095 second due to heat 

structures overheating, which caused a code failure. The results showed that there are 

negligible differences between RELAP5/MOD3.3 (cycle 19) and RELAP5/MOD3.3 Patch 03 

(cycle 21). 

42 
Table 3 Main plant signals and sequence of events – LOFW without AFW available 

43 
0

10

20

30

40

50

60

70

80

0 2000 4000 6000 8000 10000

Time (s)

Level (%)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 P03 - cycle 21

Figure 37 Steam generator no. 1 narrow range level – LOFW without AFW 

12

13

14

15

16

17

18

0 2000 4000 6000 8000 10000

Time (s)

Pressure (MPa)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 P03 - cycle 21

44 

Figure 38 Primary pressure – LOFW without AFW 
4

5

6

7

8

9

0 2000 4000 6000 8000 10000

Time (s)

Pressure (MPa)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 P03 - cycle 21

Figure 39 Steam generator no. 1 pressure – LOFW without AFW 

0

100

200

300

400

0 2000 4000 6000 8000 10000

Time (s)

Flow (kg/s)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 P03 - cycle 21

45 

Figure 40 Steam dump flow – LOFW without AFW 
0

20

40

60

80

100

120

0 2000 4000 6000 8000 10000

Time (s)

Level (%)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 P03 - cycle 21

Figure 41 Pressurizer level – LOFW without AFW 

46 

0

1

2

3

4

0 2000 4000 6000 8000 10000

Time (s)

Level (m)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 P03 - cycle 21

Figure 42 Core collapsed liquid level – LOFW without AFW 
0

500

1000

1500

2000

2500

0 2000 4000 6000 8000 10000

Time (s)

Temperature (K)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 P03 - cycle 21

Figure 43 Core cladding outer surface temperature (11 of 12) – LOFW without AFW 

5.3 Steam Generator Tube Rupture Results

The results for SGTR are shown in Table 4 and Figures 44 through 50. Table 4 shows main 

sequence of events for the SGTR accident, as calculated by RELAP5/MOD3.3 Patch 03 code. 

The triggering time for each event is given. After the initiation of tube rupture, the primary 

pressure started to decrease (Figure 44). Pressurizer heaters were turned on trying to rebuild 

the primary pressure. Pressurizer pressure and level (Figure 45) continued to decrease. Rapid 

pressure decrease was followed by reactor trip (at 334 second in RELAP5/MOD3.3 Patch 03 

calculation) and SG isolation according to emergency operating procedures (on 5% difference 

in SG liquid levels). The reactor trip caused decreasing of the primary temperature, while the 

primary pressure continued to decrease because of the rupture. The safety injection signal 

setpoint was actuated (at 342 second in RELAP5/MOD3.3 Patch 03 calculation) on low 

pressure setpoint 12.27 MPa. The HPSI pumps started to pump with 5 seconds delay after the 

SI signal generation. After the actuation of HPSI pumps the pressurizer level started increasing. 

Since the operator did not turn off the safety injection, the pressurizer level continued to 

increase till the end of the transient (Figure 45). The primary liquid remained subcooled 

throughout the entire transient. Since enough subcooling was maintained, there was no need 

for the operator to trip RCPs as per emergency operating procedures. 

The core stayed totally submerged throughout the entire transient. This kind of transient cannot 

cause core depletion whenever at least one HPSI pump is available. Due to rupture flow from 

the primary side (Figure 46) the secondary pressures in both steam generators (intact and 

ruptured) initially started to increase. The steam generator no. 1 pressure stabilized below 

47 
7.8 MPa (Figure 47), while the steam generator no. 2 pressure oscillated below 8 MPa (Figure 

48) and was regulated by opening and closing of SG no. 2 PORV valve. Instantaneous 

decrease of the steam generator no. 1 and 2 mixture level (Figure 49 and Figure 50) at the 

beginning of the transient was caused by collapsing of vapor bubbles due to loss of heat source 

just after the reactor trip. After that the operator maintained the narrow range liquid level 

between 68 and 72% in the intact steam generator no. 1. Steam generator no. 2 level increased 

later due to rupture flow from the primary side (steam generator no. 2 is isolated) and due to 

secondary pressure increase, caused by turbine trip. Instantaneous closure of steamline flow at 

the beginning of the transient following the turbine trip caused that the steam dump drew a 

small amount of steam to the condenser. After the steam generator isolation the oscillations of 

the steamline no. 2 mass flow were caused by opening/closing of the SG no. 2 PORV. 

Table 4 Main plant signals and sequence of events – SGTR 

There were some differences between RELAP5/MOD3.3 and RELAP5/MOD3.3 Patch 03 

calculations. The reason is that MD AFW pump should be isolated after main steam isolation 

valve (MSIV) closure, which occurred at 466 s, but this does not happen in the case of 

RELAP5/MOD3.3. The isolation in RELAP5 was modeled with ‘motor valve’. In 

48 
RELAP5/MOD3.3 Patch 03 the motor valves work correctly. It should be noted that at ATWS the 

reason of differences was also motor valve. Namely, the discharge flow rates for pressurizer 

PORV between RELAP5/MOD3.3 and RELAP5/MOD3.3 Patch 03 were different. Finally, the 

RELAP5/MOD2 calculations are in a reasonable agreement with the RELAP5/MOD3.3 Patch 03 

trend in spite of the differences in initial and boundary conditions, break flow model and the core 

cycle. 

10

11

12

13

14

15

16

0 2000 4000 6000 8000 10000

Time (s)

Pressure (MPa)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 44 Primary pressure – SGTR 

49 
0

10

20

30

40

50

60

70

0 2000 4000 6000 8000 10000

Time (s)

Level (%)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 45 Pressurizer level – SGTR 

0

5

10

15

20

25

30

0 2000 4000 6000 8000 10000

Time (s)

Flow (kg/s)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

50 

Figure 46 Rupture flow – SGTR 
6

6.5

7

7.5

8

8.5

0 2000 4000 6000 8000 10000

Time (s)

Pressure (MPa)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 47 Steam generator no. 1 pressure – SGTR 

6

6.5

7

7.5

8

8.5

0 2000 4000 6000 8000 10000

Time (s)

Pressure (MPa)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

51 

Figure 48 Steam generator no. 2 pressure – SGTR 
0

20

40

60

80

100

0 2000 4000 6000 8000 10000

Time (s)

Level (%)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 49 Steam generator no. 1 level – SGTR 

0

20

40

60

80

100

0 2000 4000 6000 8000 10000

Time (s)

Level (%)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

52 

Figure 50 Steam generator no. 2 level – SGTR 
5.4 Small Break Loss-of-Coolant Accident Results

5.4.1 5.08 cm Break Size Small Break Loss-of-Coolant Accident Results 

The results for 5.08 cm break size SBLOCA are shown in Table 5 and Figures 51 through 57. 

Table 5 shows main sequence of events for the 5.08 cm break size SBLOCA, as calculated by 

RELAP5/MOD3.3 Patch 03 code. The triggering time for each event is given. The break opens 

at 0 second. The HPSI pump actuation is delayed 5 seconds on SI signal. The LPSI pumps 

started but injection setpoint has not been reached during transient. The AFW pump start is 

delayed 25 seconds on SI signal and the injection is terminated when steam generator level is 

recovered. 

Table 5 Main plant signals and sequence of events – 5.08 cm break size SBLOCA 

53 

The reactor coolant system inventory mass and heat is removed through the break during 

SBLOCA. Therefore the primary pressure (Figure 51) and cold leg temperature (Figure 52) 

dropped, primary inventory decreased (Figure 53), and the core uncovered (Figure 54). The 

integrated break flow mass is shown in Figure 55. The closure of the turbine valves and core 

heat transferred to the steam generators resulted in an initial steam pressure increase (Figure 

56), which resulted in a decrease of calculated steam generator water level (Figure 57). 
0

2

4

6

8

10

12

14

16

0 2000 4000 6000 8000 10000

Time (s)

Pressure (MPa)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 51 Primary pressure – 5.08 cm break size SBLOCA 

300

350

400

450

500

550

600

0 2000 4000 6000 8000 10000

Time (s)

Temperature (K)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

54 

Figure 52 Cold leg no. 1 temperature – 5.08 cm break size SBLOCA 
0

20

40

60

80

100

120

140

0 2000 4000 6000 8000 10000

Time (s)

Mass (tons)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 53 Reactor coolant system mass – 5.08 cm break size SBLOCA 

0

2

4

6

8

10

12

0 2000 4000 6000 8000 10000

Time (s)

Level (m)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

55 

Figure 54 Reactor vessel collapsed liquid level – 5.08 cm break size SBLOCA 
0

100

200

300

400

500

600

700

800

900

0 2000 4000 6000 8000 10000

Time (s)

Mass (tons)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 55 Integrated break flow – 5.08 cm break size SBLOCA 

5

5.5

6

6.5

7

7.5

8

0 2000 4000 6000 8000 10000

Time (s)

Pressure (MPa)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

56 

Figure 56 Steam generator no. 1 pressure – 5.08 cm break size SBLOCA 
0

10

20

30

40

50

60

70

80

0 2000 4000 6000 8000 10000

Time (s)

Level (%)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 57 Steam generator no. 1 level – 5.08 cm break size SBLOCA 

5.4.2 20.32 cm Break Size Small Break Loss-of-Coolant Accident Results 

The results for 20.32 cm break size SBLOCA are shown in Table 6 and Figures 58 through 64. 

Table 6 shows main sequence of events for the 20.32 cm break size SBLOCA, as calculated by 

RELAP5/MOD3.3 Patch 03 computer code. The triggering time for each event is given. Due to 

the assumption of simultaneous break size and station blackout all signals listed in Table 6 were 

generated after break occurrence. The break opens at 0 second. Reactor trip, SI signal, turbine 

trip, steam line isolation, main feedwater isolation and reactor coolant pump trip were generated 

after 0 second (in Table 6 is shown at 1 s, as data are plotted in one second interval and trip 

times were obtained via Python, see Section 4.2). The HPSI pump actuation is delayed 5 

seconds on SI signal and 10 seconds are additionally needed for diesel generator start. The 

LPSI pumps started with 10 seconds delay plus 10 seconds for diesel generator start but 

injection setpoint has not been reached during transient. The AFW pump start is delayed 25 

seconds on SI signal plus 10 seconds for diesel generator start and the injection is terminated 

when the steam generator level is recovered. The accumulator discharged their inventory in 

about 3 minutes. Soon after accumulator isolation the LPSI no. 1 pump started to inject. From 

Table 6 also the total mass injected after 10000 seconds for accumulators and LPSI no. 1 pump 

can be seen. 

The calculated plant response during SBLOCA largely depends on the break size. As larger is 

the break size, as faster is the primary system pressure drop (Figure 58), more quickly the 

reactor coolant system inventory is lost (Figure 59), the core uncovers earlier and sharper 

57 
(Figure 60) and the core is heated up earlier due to emptying refueling water storage tank 

(Figure 61). At the larger break also more coolant is discharged through the break (Figure 62). 

Steam pressure and level for steam generator no. 1 are shown in Figure 63 and Figure 64, 

respectively. The closure of the turbine valves and core heat transferred to the steam 

generators resulted in an initial steam pressure increase. Later the steam generator no. 1 

pressure dropped as a result of cooling through the primary side break. The steam generator 

no. 1 refilled due to AFW no. 1 pump operation. 

Table 6 Main plant signals and sequence of events – 20.32 cm break size SBLOCA 

58 
0

2

4

6

8

10

12

14

16

0 2000 4000 6000 8000 10000

Time (s)

Pressure (MPa)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 58 Primary pressure – 20.32 cm break size SBLOCA 

0

20

40

60

80

100

120

140

0 2000 4000 6000 8000 10000

Time (s)

Mass (tons)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

59 

Figure 59 Reactor coolant system mass – 20.32 cm break size SBLOCA 
0

2

4

6

8

10

12

0 2000 4000 6000 8000 10000

Time (s)

Level (m)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 60 Reactor vessel collapsed liquid level – 20.32 cm break size SBLOCA 

0

200

400

600

800

1000

1200

1400

1600

1800

0 2000 4000 6000 8000 10000

Time [s]

Temperature [K]

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

60 

Figure 61 Core cladding outer surface temperature (8/12) – 20.32 cm break size SBLOCA 
0

200000

400000

600000

800000

1000000

1200000

1400000

0 2000 4000 6000 8000 10000

Time (s)

Mass (tons)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 62 Integrated break flow – 20.32 cm break size SBLOCA 

0

1

2

3

4

5

6

7

8

0 2000 4000 6000 8000 10000

Time (s)

Pressure (MPa)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

61 

Figure 63 Steam generator no. 1 pressure – 20.32 cm break size SBLOCA 
0

10

20

30

40

50

60

70

80

0 2000 4000 6000 8000 10000

Time (s)

Level (%)

MOD2 - cycle 17

MOD3.3 - cycle 19

MOD3.3 - cycle 21

MOD3.3 P03 - cycle 21

Figure 64 Steam generator no. 1 level – 20.32 cm break size SBLOCA 

62 
6. EXAMPLES OF ANIMATIONS 

6.1 Steam Generator Tube Rupture Accident Animation

The first example of using Krško NPP animation model is SGTR accident animation. The 

animations are shown in Figures 65 through 70. Table 4 from Section 5.3 already shows the 

times and status of several trip signals and plant components during SGTR. It can be seen that 

the reactor was tripped in 334 second and SI signal was generated in 342 s, causing also MFW 

isolation. On SI signal HPSI, LPSI and MD AFW pumps were started in appropriate SI 

sequence. Main steamline was manually isolated in 472 second as part of procedure for the 

faulted steam generator no. 2 isolation. Figure 65 further shows on which input signals the 

reactor trip and SI signal were generated. These were low pressurizer for reactor trip and lowlow pressurizer signal for SI signal. 

Figure 65 SNAP animation mask for reactor trip and SI signal – SGTR 

The Krško NPP general animation mask is shown in Figure 66 is shown at time 365 seconds. 

The color map for void fractions shows regions with water (blue) and steam (white). The status 

of pumps and valves is shown by color, green indicating open valve and running pump, and red 

the opposite. On right side of Figure 66 is color map for core temperatures. From Figure 66 it 

can be seen that the levels in the pressurizer and the steam generator dropped. Figure 67

63 
shows the steam generator no. 1 which was intact during SGTR event. It can be seen that at 

time 365 second the U-tubes are partly uncovered. Again information about important 

parameters is given like cold leg flow and temperature, steam flow, feedwater and auxiliary 

feedwater flow and temperature, steam generator mass and power. On the left side are shown 

void fractions and on the right side the flow regimes. Steam generator level data are shown in 

Figure 68 for main steam system. Information is given also on steam flows and status of SG 

steam and relief valves including mass discharged. It can be seen that most mass was 

discharged through faulted SG PORV due to the high pressure following the steam generator 

tube rupture. Figure 69 shows the AFW system, status of pumps and valves, and the injected 

mass in each steam generator. Finally, Figure 70 shows the status of ECCS. It can be seen that 

due to broken tube the HPSI pumps are still injecting. We can also see that for LPSI the injected 

mass (integrated flow) the value is negative. The reason is that in the RELAP5 input model the 

check valve is not modeled causing some recirculation flow in the ECCS piping. This deficiency 

of the RELAP5 input model was discovered during building animation model. For each of the 

data value shown on the mask the trend can be directly plotted from the SNAP. 

Figure 66 SNAP animation mask of Krško NPP plant at 365 second – SGTR 

64 
Figure 67 SNAP animation mask for SG1 at 365 second showing void fractions (left) and 

flow regimes (right) – SGTR 

65 

Figure 68 SNAP animation mask for main steam system at 4750 second showing SG2 

PORV discharging – SGTR 
Figure 69 SNAP animation mask for auxiliary feedwater at 4750 second showing AFW 

system not injecting – SGTR 

66 

Figure 70 SNAP animation mask for emergency core cooling system at the end of 

calculation showing HPSI pumps injecting – SGTR 
6.2 Small Break Loss-of-Coolant Accident Phenomena Animation

As second example of using Krško NPP animation model, the 20.32 cm break size SBLOCA 

phenomena are shown in Figures 71 through 74. 

Figures 71 and 72 show the SBLOCA depressurization phenomenon. From Figure 71 it can be 

seen how the pressurizer empties, the boiling in the upper core, and the voids in the upper 

plenum and hot leg. In Figure 72 can be seen saturated conditions in the hottest regions of 

primary system. 

SBLOCA core uncovery process driven by inventory loss is shown in Figures 73 and 74. Figure 

73 shows that the core is boiling dry, while Figure 74 shows superheated steam in the core, the 

upper plenum, and the hot leg. 

Figure 71 SNAP animation mask for plant, showing void conditions – 20.32 cm break 

size SBLOCA 

67 
Figure 72 SNAP animation mask for plant, showing fluid conditions – 20.32 cm break 

size SBLOCA 

68 
Figure 73 SNAP animation mask for plant, showing fluid conditions – 20.32 cm break 

size SBLOCA 

69 
Figure 74 SNAP animation mask for plant, showing fluid conditions – 20.32 cm break 

size SBLOCA 

70 
71 

7. CONCLUSIONS

The calculations of design basis accidents used for Krško full scope simulator validation were 

performed with the latest RELAP5/MOD3.3 Patch03 computer code to provide source data for 

animation model of Krško NPP. The calculations were also compared to calculations performed 

with previous RELAP5 code versions. For each calculation the scenario is described and 

important results are discussed. For animations the SNAP was used. Animation masks were 

created for the plant, the reactor vessel, the pressurizer with pressurizer relief tank, the main 

steam system, the steam generators, the main feedwater system, the emergency core cooling 

system and the auxiliary feedwater system. Besides, the signals and time sequence of events 

masks were added for better understanding of the transient progression. Finally, all important 

control system masks were developed. Two examples on the use of animations masks were 

shown, for SGTR accident and for investigating SBLOCA phenomena. The developed 

animation model of Krško nuclear power plant showed several benefits like better 

understanding of the calculated physical phenomena and processes, user friendly tool for 

understanding the nodalization and the detail of plant modeling, better presentation of the 

results due to visualization and movies, a convenient tool to train new users of thermal-hydraulic 

code etc. All these contribute to higher quality of safety analysis. Besides it can also be 

concluded that such modern tool may increase the interest of people to work with system codes 

comparable to the interest for computational fluid dynamics codes. 

73 

8. REFERENCES

1. Applied Programming Technology. “Symbolic Nuclear Analysis Package (SNAP), User's 

Manual.” Applied Programming Technology, Inc.: Bloomsburg PA. April 2007. 

2. NUREG/CR-5535/Rev P3. “RELAP5/MOD3.3 code manual, Vols. 1 to 8.” Information 

Systems Laboratories, Inc., Rockville, Maryland, Idaho Falls, Idaho, prepared for USNRC. 

NRC: Washington, D.C. 2006. 

3. Prošek, A., I. Parzer, “SB LOCA thermal-hydraulic analysis for Krško full scope simulator 

validation.” Proc. of International Conference Nuclear Energy for New Europe 2005. Bled, 

Slovenia September 5-8, 2005. Nuclear Society of Slovenia: Ljubljana, Slovenia. 2005. 

4. Parzer, I., A. Prošek, “Loss of normal feedwater analysis for Krško full scope simulator 

validation.” Proc. of International Conference Nuclear Energy for New Europe 2005. Bled, 

Slovenia September 5-8, 2005. Nuclear Society of Slovenia: Ljubljana, Slovenia. 2005. 

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validation.” Proc. of International Conference Nuclear Energy for New Europe 2005. Bled, 

Slovenia September 5-8, 2005. Nuclear Society of Slovenia: Ljubljana, Slovenia. 2005. 

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International Conference Nuclear Energy for New Europe 2005. Bled, Slovenia September 

5-8, 2005. Nuclear Society of Slovenia: Ljubljana, Slovenia. 2005. 

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accident in modernized nuclear power plant.” Electrotechnical Review. Vol. 71, No. 4: 2004. 

8. Parzer, I., B. Mavko, and B. Krajnc. “Simulation of a hypothetical loss-of-feedwater accident 

in a modernized nuclear power plant.” Journal of Mechanical Engineering. Vol. 49, No. 9: 

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9. Parzer, I. “Break model comparison in different RELAP5 versions.” Proc. of International 

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