NUREG/IA-0458 

International 

 Agreement Report

RELAP5/MOD3.3 Analysis of Event with 

Actuation of Safety Injection System at the 

Loss of External Power

 

 

Prepared by: 

A. Prošek, M. Matkovič

Jožef Stefan Institute 

Jamova cesta 39 

Sl-1000 Ljubljana, Slovenia 

K. Tien, NRC Project Manager 

 

Division of Systems Analysis

Office of Nuclear Regulatory Research

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

Manuscript Completed: November 2014

Date Published: December 2015

Prepared as part of 

The Agreement on Research Participation and Technical Exchange

Under the Thermal-Hydraulic Code Applications and Maintenance Program (CAMP) 

Published by

U.S. Nuclear Regulatory Commission
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NUREG/IA-0458 

International 

 Agreement Report

RELAP5/MOD3.3 Analysis of Event with 

Actuation of Safety Injection System at the 

Loss of External Power

 

 

Prepared by: 

A. Prošek, M. Matkovič

Jožef Stefan Institute 

Jamova cesta 39 

Sl-1000 Ljubljana, Slovenia 

K. Tien, NRC Project Manager 

 

Division of Systems Analysis

Office of Nuclear Regulatory Research

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

Manuscript Completed: November 2014

Date Published: December 2015

Prepared as part of 

The Agreement on Research Participation and Technical Exchange

Under the Thermal-Hydraulic Code Applications and Maintenance Program (CAMP) 

Published by

U.S. Nuclear Regulatory Commission

iii

ABSTRACT

Measured plant data are of great importance for the assessment of thermal-hydraulic system 

codes. Namely, the integral effects facilities contain atypicalities and scaling distortions relative 

to full scale plants. On the other hand, the accidents in the plants are very rare and the plant 

specific data are generally available only for startup tests and operational events. However, the 

measured plant data may be limited for the full understanding of event. The purpose of this 

study was therefore both code assessment and better understanding of the plant response to 

abnormal event, which occurred on 23 March 2011 in Krško nuclear power plant (NPP). The 

abnormal event was called “Reactor trip and actuation of safety injection system at the loss of 

external power“. For the analysis the latest RELAP5/MOD3.3 Patch 04 best-estimate 

thermalhydraulic computer code and standard Krško NPP input deck for RELAP5 have been 

used. The results show good agreement between measured and simulated data, when all plant 

system responses and operator actions were considered. This suggests that the RELAP5 code 

using standard plant input deck is good representative of the plant and could be used for better 

understanding of the plant response when information on all physical phenomena and 

processes is not available by plant measured data.

v

CONTENTS --

Page

ABSTRACT...............................................................................................................................iii

FIGURES..................................................................................................................................vii

TABLES ....................................................................................................................................ix

EXECUTIVE SUMMARY ...........................................................................................................xi

ACKNOWLEDGMENTS.......................................................................................................... xiii

ABBREVIATIONS ....................................................................................................................xv

1. INTRODUCTION.................................................................................................................. 1

2. ABNORMAL EVENT DESCRIPTION .................................................................................. 3

3. RELAP5 INPUT MODEL AND SCENARIOS DESCRIPTION.............................................. 5

 3.1 RELAP5 Input Model ............................................................................................... 5

 3.2 RELAP5 Initial and Boundary Conditions ................................................................. 7

 3.3 Scenarios Description.............................................................................................. 9

4. RESULTS ...........................................................................................................................13

 4.1 Information Obtained from Measured Data .............................................................13

 4.2 First Part of Transient .............................................................................................16

 4.3 Second Part of Transient ........................................................................................22

 4.4 Results Discussion..................................................................................................26

5. CONCLUSIONS..................................................................................................................27

6. REFERENCES....................................................................................................................29

vii

FIGURES

Page

Figure 1 RELAP5 Krško NPP Hydraulic Components View............................................... 5

Figure 2 RELAP5 Animation Mask of Steam Dump System For Krško NPP ..................... 7

Figure 3 Measured Turbine First Stage (impulse) Pressure............................................... 7

Figure 4 Measured Feedwater Flow to Steam Generator No. 1 And 2 .............................. 8

Figure 5 Measured Steamline No. 1 and Steamline No. 2 Steam Flow and Total Flow 

(Summed Steamline Flows) ................................................................................ 8

Figure 6 Measured Turbine-Generator Rotor Speed ......................................................... 9

Figure 7 TRACE Model of the Input Part of Steam Dump Load Rejection Controller........11

Figure 8 TRACE Model for Low Steamline Pressure Signal Compensation .....................11

Figure 9 Measured RCS Average and Reference Temperature Signal and the 

Corresponding Compensated Signals ................................................................13

Figure 10 Measured Error Temperature Signal for Steam Dump Demand and the 

Corresponding Difference Signal between RCS Average and Reference 

Temperature.......................................................................................................14

Figure 11 Turbine Governor Valve Position Indications......................................................14

Figure 12 Steam Generators Pressures and Compensated Low Steamline Pressures ......15

Figure 13 Calculated Compensated Low Steamline Pressures as a Function of Lead 

Constant.............................................................................................................16

Figure 14 Reactor Power – First Part .................................................................................17

Figure 15 Pressurizer Pressure – First Part........................................................................17

Figure 16 Cold Leg No. 1 Temperature – First Part............................................................17

Figure 17 Cold Leg No. 2 Temperature – First Part............................................................18

Figure 18 Hot Leg No. 1 Temperature – First Part..............................................................18

Figure 19 Hot Leg No. 2 Temperature – First Part..............................................................18

Figure 20 RCS Loop No. 1 Average Temperature – First Part............................................19

Figure 21 RCS Loop No. 2 Average Temperature – First Part............................................19

Figure 22 Delta Temperature No. 1 – First Part..................................................................19

Figure 23 Delta Temperature No. 2 – First Part..................................................................20

Figure 24 Steam Generator No. 1 Pressure – First Part.....................................................20

Figure 25 Steam Generator No. 2 Pressure – First Part.....................................................20

Figure 26 Steam Generator No. 1 Narrow Range Level – First Part...................................21

Figure 27 Steam Generator No. 2 Narrow Range Level – First Part...................................21

Figure 28 LO-2 Steam Line No. 1 Pressure Signal – First Part...........................................21

Figure 29 LO-2 Steam Line No. 2 Pressure Signal – First Part...........................................22

Figure 30 Reactor Power – Second Part ............................................................................22

Figure 31 Pressurizer Pressure – Second Part ..................................................................23

Figure 32 Cold Leg No. 1 Temperature – Second Part.......................................................23

Figure 33 Cold Leg No. 2 Temperature – Second Part.......................................................23

Figure 34 Hot Leg No. 1 Temperature – Second Part ........................................................24

Figure 35 Hot Leg No. 2 Temperature – Second Part ........................................................24

Figure 36 RCS Loop No. 1 Average Temperature – Second Part ......................................24

Figure 37 RCS Loop No. 2 Average Temperature – Second Part ......................................25

Figure 38 Steam Generator No. 1 Pressure – Second Part................................................25

Figure 39 Steam Generator No. 2 Pressure – Second Part................................................25

Figure 40 Steam Generator No. 1 Narrow Range Level – Second Part..............................26

Figure 41 Steam Generator No. 2 Narrow Range Level – Second Part..............................26

ix

TABLES

Page

Table 1 Reported Sequence of Events............................................................................. 3

Table 2 Initial Conditions.................................................................................................. 9

Table 3 Scenarios Simulated by RELAP5 Till SI Injection Signal ....................................10

Table 4 TRACE Calculated Minimum Values of Low Pressure Compensated Signals for 

Both Steamlines .................................................................................................15

xi

EXECUTIVE SUMMARY

Measured plant data are of great importance for the assessment of thermal-hydraulic system 

codes. Namely, the integral effects facilities contain atypicalities and scaling distortions relative 

to full scale plants. On the other hand, the accidents in the plants are very rare and only the 

plant specific data are generally available for startup tests and operational events. However, the 

measured plant data may be limited for the full understanding of event. 

The purpose of this study was to analyze the abnormal event, which occurred on 23 March 

2011 in Krško nuclear power plant (NPP). The abnormal event was called “Reactor trip and 

actuation of safety injection system at the loss of external power“. The objective was to validate 

the computer code and also to provide additional information on the time dependence of the 

values of parameters that are not directly available using the plant instrumentation.

For the analysis the latest RELAP5/MOD3.3 Patch 04 best-estimate thermalhydraulic computer 

code and standard Krško NPP input deck for RELAP5 have been used. The abnormal event 

started with spurious activation of 400 kV bus differential protection in the NPP’s 400 kV 

switchyard, followed by the disconnection of circuit breakers in the bays, resulting in loss of offsite load. Automatic stabilization at house load operation using the turbine control system and 

steam dump system was not successful to stabilize main steam line pressure. Safety injection 

actuation and reactor trip occurred on low pressure signal in steam generator no. 1 due to 

divergent oscillation of pressure in steam generators. The measured data were available for the 

first four minutes.

The results show good agreement between measured and simulated data, when all plant 

system responses and operator actions were considered (for example, emergency boration 

initiated by plant operator was not mentioned in international incident reporting system (IRS) 

report no. 8300). 

It was shown that both before and after SI signal generation it is important to have available 

plant information about systems behavior. In the opposite the response may deviate. The 

analysis showed that in such transient when part of information is, the measured data may be 

used to reproduce some missing information. In the present study the steam dump demand 

signal was reproduced and the compensated low steam line pressure signals, which caused 

safety injection signal. When having this information available in addition to plant 

measurements, the transient could be better understood. The hypothesis done in internal plant 

analysis that operator manual main feedwater control did not help in secondary pressure 

stabilization was also confirmed. It seems that almost simultaneous request for opening and 

closing by turbine control and steam dump load rejection controller was the reason for two fast 

pressure decrease and consequential safety injection signal (SI) generation. Please note that 

automatic turbine control is in mode to control the speed of the turbine-generator.

This obtained calculated results suggests that the RELAP5 code using standard plant input 

deck is good representative of the plant and could be used for better understanding of the plant 

response when not all information on physical phenomena and processes is available from plant 

measured data.

xiii

ACKNOWLEDGMENTS

The authors acknowledge the financial support from Krško Nuclear Power Plant and Slovenian 

Nuclear Safety Administration within CAMP program (project no. POG-U3-KE-R4/104/12 – also 

NEK no.: 3120118) and from the state budget by the Slovenian Research Agency (program no. 

P2-0026).

xv

ABBREVIATIONS

ASCII American Standard Code for Information Interchange

AC alternate current

AFW auxiliary feedwater

CVCS chemical and volume control system

ECCS emergency core cooling system

HPSI high pressure safety injection

IAEA International Atomic Energy Agency

JSI Jožef Stefan Institute

LPSI low pressure safety injection

MFW main feedwater

MSIV main steam isolation valve

NPP Nuclear Power Plant

NRC Nuclear Regulatory Commission

PORV power operated relief valve

PRZ pressurizer

RELAP Reactor Excursion and Leak Analysis Program

RCP reactor coolant pump

RCS reactor coolant system

RPV reactor pressure vessel

SG steam generator

SL surge line

SNAP Symbolic Nuclear Analysis Package

SSG Specific Safety Guide

TB turbine

TRACE TRAC/RELAP Advanced Computational Engine

1 

1. INTRODUCTION

Measured plant data are of great importance for thermal-hydraulic system code validation, 

because the integral effects facilities contain atypicalities and scaling distortions relative to full 

scale plants. Typically, real plant data are limited mostly to operational events. However, 

especially at unexpected event some plant data may be missing for full understanding besides 

the fact that the plant measured data are limited both in the number of parameters and number 

of measured data points (not all history available). Such missing information could be 

reconstructed provided that transient progression is well simulated, i.e. simulated and measured 

main plant parameters agree well. The purpose of this study was both validation and better 

understanding of the plant response to abnormal event. This is in agreement with IAEA SSG-2 

(Ref. 1) that accident analyses may be used as a tool for obtaining a full understanding of 

events that occur during the operation of nuclear power plants and should form an integral part 

of the feedback from operating experience. According to IAEA SSG-2 (Ref. 1) the objective to 

analyze operational events may be also to provide additional information on the time 

dependence of the values of parameters that are not directly available using the plant 

instrumentation, to check whether the plant operators and plant systems performed as intended 

and to validate and adjust the models in the computer codes that are used for analyses. In the 

present work the RELAP5/MOD3.3 analysis of the abnormal event, which occurred on 23 March 

2011 in Krško nuclear power plant (NPP) is presented. First the abnormal event is described, 

followed by standard RELAP5 input model of Krško and scenarios description. The simulated 

results are then presented and compared to measured data which were available. At the end 

discussion is given and conclusions.

3 

2. ABNORMAL EVENT DESCRIPTION

The abnormal event, which occurred on 23 March 2011 in Krško NPP, started with spurious 

activation of 400 kV bus differential protection in the NPP’s 400 kV switchyard, followed by the 

disconnection of circuit breakers in the bays, resulting in loss of off-site load (Ref. 2). To protect 

the turbine generator, the turbine runback started to adjust to the house load power level. 

Automatic stabilization at house load operation using the turbine control system and steam 

dump system was not successful to stabilize main steam line pressure. Safety injection (SI) on 

low steamline pressure was actuated approximately after 2 minutes, which led to reactor trip 

and turbine trip. The reported sequence of events is shown in Table 1. The timing is based on 

measured data. At 10:55, an “unusual event” was declared according to the emergency 

response procedure classification criteria (loss of power 6.3 kV bus). At that time the power 

supply to safety buses has been established through the auxiliary transformer and after diesel 

generators were manually shut down and placed in standby mode. At 12:15, the plant 

transferred to a “hot standby” mode and the termination of “unusual event” was declared.

The measured data received were available only until time 10:31 what means only first four 

minutes (or less in case of some parameters). The measured parameters available were 

reference temperature, turbine first stage impulse pressure, pressurizer pressure, nuclear 

power, rod position, delta temperatures, overpower and overtemperature delta temperature, hot 

leg temperatures, cold leg temperatures, average RCS temperatures, turbine-generator rotor 

speed, turbine governor valves position, steam pressures, steam flows, feedwater flows and 

steam generator levels. However, there is no information on steam demand, steam dump open 

logic signals and steam dump flow. Also it was reported that operators in main control room 

switched feedwater flow control to manual mode with the intention of steam generator level 

stabilization, but the timing is not available. On the SI signal both diesel generators started and 

the safety systems loading sequence was performed normally.

Table 1 Reported Sequence of Events

Event Time (hh:mm:ss)

loss of off-site load 10:27

turbine overspeed protection started (closure of turbine governor 

valves with steam dump valve opening)

10:27:01*

alarm ROD BANK LO-LO LIMIT 10:28:18

safety injection signal 10:29:02

“unusal event” was declared 10:55

diesel generator no. 1 (2) stopped 11:20 (11:34)

reactor coolant pump no. 1 restarted 11:55

plant transited to a “hot standby” mode, the termination of “unusual 

event” was declared

12:15

* - estimated from measured data

5 

3. RELAP5 INPUT MODEL AND SCENARIOS DESCRIPTION

3.1 RELAP5 Input Model

To perform the analyses, the base RELAP5 input model of Krško NPP has been used. This 

input model has been validated by plant transients (e.g. Ref. 3). It has been used for several 

safety analyses including reference calculations for Krško full scope simulator verification (Refs. 

4 and 5). The base model consists of 469 control volumes, 497 junctions and 378 heat 

structures with 2107 radial mesh points. When imported ASCI file into SNAP, the following 

hydraulic components view has been generated semi automatically (hydraulic components with 

connections generated automatically, annotations and layout manually). In terms of SNAP this 

gives 304 hydraulic components and 108 heat structures. Hydraulic components in SNAP 

consist of both volumes and junctions, where pipe with more volumes is counted as one 

component. Each heat structure in SNAP connected to pipe is counted as one component in 

SNAP and not as many heat structures as pipe volumes like counted in RELAP5 output file. 

This explains the difference in numbers of heat structures in Figure.1 and that reported in 

RELAP5 output file.

Figure 1 RELAP5 Krško NPP Hydraulic Components View
6 

Modeling of the primary side includes the reactor pressure vessel (RPV), both loops (LOOP 1 

and 2), the pressurizer (PRZ) vessel, pressurizer surge line (SL), pressurizer spray lines and 

valves, two pressurizer power operated relief valves (PORVs) and two pressurizer safety 

valves, chemical and volume control system (CVCS) charging and letdown flow, and reactor 

coolant pump (RCP) seal flow. The primary loop is represented by the hot leg, primary side of 

the steam generator (SG), intermediate leg with cold leg loop seal, and cold leg, separately for 

loop no. 1 and loop no. 2. Emergency core cooling system (ECCS) piping includes high 

pressure safety injection (HPSI) pumps, accumulators (ACCs), and low pressure safety injection 

(LPSI) pumps.

The secondary side consists of the SG secondary side, main steam line, main steam isolation 

valves (MSIVs), SG relief and safety valves, and main feedwater (MFW) piping. The turbine 

valve is modeled by the corresponding logic. The turbine is represented by time dependent 

volume. The MFW and AFW (auxiliary feedwater) pumps are modeled as time dependent 

junctions.

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 

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. The reactor protection system was based 

on trip logic. It includes reactor trip signal, safety injection signal, turbine trip signal, steam line 

isolation signal, MFW isolation signal, and AFW start signal. For the simulation of this transient 

is important steam dump system. During loss of load RCS average temperature control is used, 

and loss of load controller. There are 10 valves in four groups a, b, c and d and they open 

according to the temperature error. When fast opening is needed bistables open group a on HI1 demand (20% capacity), group b on HI-2 demand (30% capacity), group c on HI-3 demand 

(20% capacity) and group d on HI-4 demand (30% capacity). The steam dump control system is 

schematically shown in Figure 2, where Krško NPP animation mask is animated with calculated 

data at time 0 s. 
7 

Figure 2 RELAP5 Animation Mask of Steam Dump System For Krško NPP

3.2 RELAP5 Initial and Boundary Conditions

Loss of external load has been modeled with artificial turbine control as external perturbation, 

which is provided in the standard input deck. The turbine external power function was 

determined from measured turbine first stage pressure (impulse pressure), shown in Figure 3. 

The turbine external power was needed as input into rod control and steam dump control 

system. 

Figure 3 Measured turbine first stage (impulse) pressure

0

1

2

3

4

5

0 60 120 180 240

Pressure (MPa)

Time (s)

p-impulse
8 

Due to manual operation of main feedwater the measured feedwater flow was used as 

boundary condition and it is shown in Figure 4. However, as was reported in plant event 

analysis report, this operator action did not help in secondary pressure stabilization and anyway 

the triggering of SI signal would be expected.

Figure 4 Measured Feedwater Flow to Steam Generator No. 1 And 2

Total steam flow was initially used as boundary condition because in the standard Krško NPP 

input deck the secondary side is modelled up to the turbine (see Figure 1) only what means that 

the RELAP5 model does not have the representative turbine model with turbine overspeed 

controller. The total flow shown in Figure 5 was obtained by summing the measured steamline 

no. 1 and steamline no. 2 steam flows. 

Figure 5 Measured Steamline No. 1 and Steamline No. 2 Steam Flow and Total Flow 

(Summed Steamline Flows)

Finally, turbine-generator frequency was also considered for reactor coolant pump operation

which is dependent on rotor speed shown in Figure 6. Also, it was the main target of automatic 

turbine control to maintain the frequency at 50 Hz (speed 1500 rpm).

0

100

200

300

400

500

600

0 60 120 180 240

Mass flow (kg/s)

Time (s)

FW 1 flow

FW 2 flow

0

200

400

600

800

1000

1200

0 60 120 180 240

Mass flow (kg/s)

Time (s)

total (sum)

SL 1 flow

SL 2 flow
9 

Figure 6 Measured Turbine-Generator Rotor Speed

The initial conditions for the simulations are shown in Table 2 and due to good match no 

additional steady-state calculation was performed.

Table 2 Initial Conditions

Variable Plant measured RELAP5

Reactor power (%) 100.3 100

RCS average temperature (K) 577.96 578.15

Hot leg temperature no. 1 / 2 (K) 596.87 / 596.92 596.79 / 596.79

Cold leg temperature no. 1 / 2 (K) 559.22 / 559.19 559.51 / 559.32

Pressurizer pressure (MPa) 15.509 15.513

Steam generator pressure no. 1 / 2 (MPa) 6.327/6.321 6.438/6.415

Feedwater flow no. 1 / 2 (kg/s) 550.4 / 549.6 541.34 / 544.47

Steam flow no. 1 / 2 (kg/s) 551.8 / 549.3 541.3 / 544.5

Feedwater temperature (K) N.A. 565.55

Steam generator narrow range level (%) 69.29 / 69.22 69.3 / 69.3

RCS boron concentration 1687 ppm 1704 ppm

3.3 Scenarios Description

The simulations were performed in two steps. In the first step the focus was given on transient 

progression till SI injection signal actuation and in the second step the focus was given on whole 

transient simulation lasting 4 minutes.

In the first step there were performed some sensitivity runs as shown in Table 3 for operator 

action and plant responses not mentioned in IRS report (Ref. 2).For example, the IRS 8300 

report (Ref. 2) did not reported that operator performed emergency boration. This information 

was found in the internal plant report on analysis of the event. On the other hand, plant 

response has been suggested from measured data plots. For example, in the IRS report it was 

not reported pressurizer PORV opening. Also plant measured data suggested that pressurizer 

rate sensitive PORV did not open. Namely, in the plant some setpoints may drift, while this was 

not the case calculation with not disabling pressurizer rate sensitive PORV. Also turbine 

frequency change influences the reactor coolant pump operation, therefor case was run, when 

1400

1450

1500

1550

1600

0 20 40 60 80 100 120

Speed (rpm)

Time (s)

TG rotor
10

this is not considered. Finally, in the base case simulation the reactor power was fine tuned (by 

boron). Case was also run, if no boration is considered (case with emergency boration has not 

been performed as start time and the flowrate of injection was not known). It was already 

mentioned that operator manual main feedwater control did not help in secondary pressure 

stabilization. Therefore also one simulation case with main feedwater system in automatic was 

performed to verify this hypothesis.

Table 3 Scenarios Simulated by RELAP5 Till SI Injection Signal

Scenario Name

Base case (assuming above initial and boundary conditions) base

Base case without assuming influence of turbine-generator frequency 

on RCP flow

w/o frequency

Base case with not disabled rate sensitive pressurizer PORV opening with PRZ PORV

Base case without assuming any boration w/o boration

Base case (assuming main feedwater system in automatic mode) w/o operator FW

For the whole transient simulation the base case scenario was used. In addition, scenario with 

assuming some assuming steam release after SI signal was performed as suggested by 

measured data. Namely, when there is low steam line pressure signal there is also steam line 

isolation, but measured steam slow at the exit of steam generators was non-zero (the validity 

sign for measured values was true), indicating that steam was released either through steam 

dump or the SG PORVs if main steam line isolation occurred (not reported) like suggested by 

simulation.

In the above calculations the total steam flow was used as boundary condition because both 

turbine and steam dump flow were not known. The purpose was first to show that if both primary 

(reactor power) and secondary power (i.e. total steam flow) are matched that the RELAP5 plant 

model is good representative of the plant response.

Finally, the simulation was performed in which total steam dump flow was predicted from 

measured signals and in this way the turbine flow was determined and used as input value. 

Namely, the plant measured average RCS temperature and reference temperature signals were 

sent through the steam dump load rejection controller to determine the temperature error of the 

lead-lag compensated signals. This part of load rejection steam dump controller model was built 

with TRACE as the RELAP5 code is limited by the number of data points for input signals. The 

TRACE model is shown in Figure 7. The inputs are shown in Figure 8, the highest RCS 

temperature (auctioneered) being Function 1 and the reference temperature (Tref) being 

Function 2.
11

Figure 7 TRACE Model of the Input Part of Steam Dump Load Rejection Controller

Similarly, signal for safety injection (SI) on low steamline pressure was also calculated from 

plant measured data. Again, due to the number of input data points, the TRACE model shown in 

Figure 8 has been used to calculate the lead-lag compensated signal. There are three channels 

per steamline and 2 out of 3 on either steamline generate the SI signal. Knowing the value of 

compensated signal helps in understanding the transient.

Figure 8 TRACE Model for Low Steamline Pressure Signal Compensation

13

4. RESULTS

4.1 Information Obtained from Measured Data

First the information available from the measured data was extracted. As has been already 

mentioned above, the information on steam dump demand is missing in the measured data. 

Figure 9 shows the input temperature signals into steam dump controller shown in Figure 7 and 

the corresponding output lead-lag compensated signals, which are used for load rejection 

temperature error signal, shown in Figure 10. For comparison, difference signal between RCS 

average and reference temperature is shown, as this is information normally available to 

operators. One may see that after first 40 seconds, the temperature error signal is very similar 

to temperature difference signal. At around 41 second the steam dump group d valves are fully 

closedclosed. The group c valves started to close at around 65 second. The information on the 

turbine governor valve position indication is also available, see Figure 11. One may see that 

before transient start the governor valve (GV) no. 4 was opened 12%, what is accordance with 

the plant (before modernization with plant uprate three out of four valves were sufficient for 

100% turbine flow). After transient start the turbine control closes all four governor valves to 

prevent overspeed of turbine-generator. Once the speed of turbine-generator started to drop, 

the first two governor valves (controlled in pair) partially reopen, but after full steam dump 

operation the first two turbine governor valves started to close again after 17 seconds. However, 

once steam dump group d valves fully close, the governor valves open again after 41 second. 

As may be seen, the position of governor valves is then rather constant until 90 s (the first two 

governor valves are slightly closing and the last two governing valves are slightly opening). 

When looking steam flow in Figure 5, and steam demand in Figure 10, between 51 and 65 

second the steam dump groups a, b and c were fully opened. Then group c started to gradually 

close. Finally, at around 95 second the governor valves no. 1 and 2 started to close and also 

slightly steam dump group c. After 100 seconds steam dump group a valves also started to 

close. These cause overheating and pressure increase. The first reacted turbine control and 

reopens the valves. Same happened due to steam demand with group b valves and there was 

pressure drop, and lead-lag compensated signal caused SI signal generation. 

Figure 9 Measured RCS Average and Reference Temperature Signal and the 

Corresponding Compensated Signals

560

565

570

575

580

585

0 20 40 60 80 100 120

Temperature (K)

Time (s)

Tref Tref comp

Tavg Tavg comp
14

Figure 10 Measured Error Temperature Signal for Steam Dump Demand and the 

Corresponding Difference Signal between RCS Average and Reference 

Temperature

Figure 11 Turbine Governor Valve Position Indications

Signal which triggers SI signal generation, is shown in Figure 12. It can be seen that steam 

generator pressures in both steam generators are very similar. Also, for each steam generator 

pressure the channel measurements are practically the same, therefore only channel one 

measurements are presented. The low pressure setpoint is 4.928 MPa. For actuating the SI 

signal, 2 out of 3 signals are needed. Therefore in Table 4 are shown the minimum values of 

low pressure steamline pressure compensated signal calculated with TRACE from measured 

input steam generator pressure signals. In the plant report it was stated that Si signal was 

triggered because of low pressure in steam generator no. 1. According to calculation, the 

absolute values of minimum low steamline pressures were higher for steamline no. 1 than 

steamline no. 2. The reason may be that the setpoint drifted or the real controllers perform 

slightly different. When comparing dropping rates at 5 seconds and at 112 seconds, it may be 

seen that drop was more step at 5 seconds, but the reason to not generate SI signal

immediately was that initially due to the closure of all turbine governor valves the rate of 

0

5

10

15

20

0 20 40 60 80 100 120

Temperature (K)

Time (s)

Tavg comp - Tref comp Tavg-Tref

Terr HI-1 Terr HI-2

Terr HI-3 Terr HI-4

0

2

4

6

8

10

12

14

0 20 40 60 80 100 120

Position (%)

Time (s)

GV1

GV2

GV3

GV4
15

pressure increase was high and therefore the compensated low steamline pressure signal has 

more margin in dropping to setpoint value than at 112 s. Also, in the case of first pressure drop 

only governor valvew close, while steam dump valves remain open. This was not the case for 

last pressure increase and decrease. Namely, at 96 s the governor valves no. 1 and 2 started to 

close (see Figure 11). At 102 seconds also the steam dump group b valves started to close. 

Both closures are in agreement with steam flow shown in Figure 5 and pressure started to 

increase. First again reacted turbine control at approximately 112 second, followed by steam 

dump demand at 116 second and this then resulted in SI signal generation on low steamline 

pressure. In this last case turbine control and steam dump control both reacts in the same 

direction, therefore the pressure change was faster than in the time interval between 20 and 100 

seconds.

Figure 12 Steam Generators Pressures and Compensated Low Steamline Pressures

Table 4 TRACE Calculated Minimum Values of Low Pressure Compensated Signals 

for Both Steamlines

Steamline no. 1 Steamline no. 2

Channel 

number

Value (MPa) Channel 

number

Value (MPa)

1 5.119 1 5.051

2 5.070 2 5.034

3 5.118 3 5.052

Finally, lead constant in low steamline pressure compensation was varied as shown in Figure 

13. It may be seen that faster controller with lead constant 65 s would cause SI signal actuation

at the beginning of transient and that slower controllers might prevent SI signal actuation at last 

pressure decrease before SI signal generation. It should be noted that this signal present 

protection against steamline break and caution should be made when considering constant 

change.

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

0 20 40 60 80 100 120

Pressure (MPa)

Time (s)

SG no. 1 - ch. 1

SG no. 2 - ch. 1

SG no. 1 - ch. 1

SG no. 2 - ch. 1

4.928 MPa
16

Figure 13 Calculated Compensated Low Steamline Pressures as a Function of Lead 

Constant

4.2 First Part of Transient

The results of first part simulation are shown in Figures 14 through 29. The comparison between 

measured and simulated data for scenarios in Table 3 is done. Figure 14 shows that in the 

simulated case without considering any boration (labelled w/o boration) the core power 

significantly deviates from the measured data, resulting in deviation of other parameters. 

Different simulated power influences also all other parameters, shown in Figures 15 through 29. 

The pressurizer pressure is higher, steam generator pressures are higher and therefore low 

steam line pressure signals are higher, not resulting in actuating SI signal. The alternate current 

(AC) frequency change due to changing frequency of the turbo-generator has major influence 

on power which increases in first few seconds (case w/o frequency). This increases also 

pressurizer pressure and steam generator pressures, but these increases are less significant 

than power increase. Base case calculation (labelled base) is performed considering both 

boration, changing AC frequency and disabling rate sensitive PRZ PORV no. 2. Opening of the 

PRZ PORV no. 1 and 2 was not reported in first few seconds and this can be seen also from 

measured pressurizer pressure signal shown in Figure 15. The modification rate sensitive PRZ 

PORV mainly influences the pressurizer pressure in the initial 13 seconds. It has no influence 

on the further transient progression. Nevertheless, it is important for deeper understanding of 

the transient. The simulated results indicate that the plant setpoint for PRZ PORV no. 1 was not 

challenged. One possible reason may be valve setpoint drift. When not disabling the PRZ 

PORV no. 2 in calculation (case with PRZ PORV), the pressure initially did not increase much 

(like in w/o frequency case). The hot leg, cold leg and average temperatures shown in Figures 

16 through 21 agree well with measured data for all cases except in the case without boration 

and in the case when main feedwater pump was in automatic (expected because of different 

control than in the case of manual operator control). The secondary side plant parameters 

shown in Figures 24 through 29 are also in good agreement. This resulted that SI signal (see 

Figures 28 and 29) was generated in the base case calculation as was the case in the plant 

event.

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

12.5

13.5

0 20 40 60 80 100 120

Pressure (MPa)

Time (s)

lead constant 65 s

lead constant 50 s

lead constant 45 s

lead constant 40 s

4.928 MPa
17

Figure 14 Reactor Power – First Part

Figure 15 Pressurizer Pressure – First Part

Figure 16 Cold Leg No. 1 Temperature – First Part

50

60

70

80

90

100

110

0 20 40 60 80 100 120

Power (%)

Time (s)

measured

base

w/o frequency

with PRZ PORV

w/o boration

w/o operator FW

14.5

15.0

15.5

16.0

16.5

0 20 40 60 80 100 120

Pressure (MPa)

Time (s)

measured

base

w/o frequency

with PRZ PORV

w/o boration

w/o operator FW

556

558

560

562

564

566

568

0 20 40 60 80 100 120

Temperature (K)

Time (s)

measured

base

w/o frequency

with PRZ PORV

w/o boration

w/o operator FW
18

Figure 17 Cold Leg No. 2 Temperature – First Part

Figure 18 Hot Leg No. 1 Temperature – First Part

Figure 19 Hot Leg No. 2 Temperature – First Part

556

558

560

562

564

566

568

0 20 40 60 80 100 120

Temperature (K)

Time (s)

measured

base

w/o frequency

with PRZ PORV

w/o boration

w/o operator FW

585

588

591

594

597

600

0 20 40 60 80 100 120

Temperature (K)

Time (s)

measured

base

w/o frequency

with PRZ PORV

w/o boration

w/o operator FW

585

588

591

594

597

600

0 20 40 60 80 100 120

Temperature (K)

Time (s)

measured

base

w/o frequency

with PRZ PORV

w/o boration

w/o operator FW
19

Figure 20 RCS Loop No. 1 Average Temperature – First Part

Figure 21 RCS Loop No. 2 Average Temperature – First Part

Figure 22 Delta Temperature No. 1 – First Part

570

573

576

579

582

585

0 20 40 60 80 100 120

Temperature (K)

Time (s)

measured

base

w/o frequency

with PRZ PORV

w/o boration

w/o operator FW

570

573

576

579

582

585

0 20 40 60 80 100 120

Temperature (K)

Time (s)

measured

base

w/o frequency

with PRZ PORV

w/o boration

w/o operator FW

24

28

32

36

40

0 20 40 60 80 100 120

Temperature (K)

Time (s)

measured

base

w/o frequency

with PRZ PORV

w/o boration

w/o operator FW
20

Figure 23 Delta Temperature No. 2 – First Part

Figure 24 Steam Generator No. 1 Pressure – First Part

Figure 25 Steam Generator No. 2 Pressure – First Part

24

28

32

36

40

0 20 40 60 80 100 120

Temperature (K)

Time (s)

measured

base

w/o frequency

with PRZ PORV

w/o boration

w/o operator FW

6.0

6.5

7.0

7.5

8.0

0 20 40 60 80 100 120

Pressure (MPa)

Time (s)

measured

base

w/o frequency

with PRZ PORV

w/o boration

w/o operator FW

6.0

6.5

7.0

7.5

8.0

0 20 40 60 80 100 120

Pressure (MPa)

Time (s)

measured

base

w/o frequency

with PRZ PORV

w/o boration

w/o operator FW
21

Figure 26 Steam Generator No. 1 Narrow Range Level – First Part

Figure 27 Steam Generator No. 2 Narrow Range Level – First Part

Figure 28 LO-2 Steam Line No. 1 Pressure Signal – First Part

55

60

65

70

75

80

0 20 40 60 80 100 120

Level (%)

Time (s)

measured

base

w/o frequency

with PRZ PORV

w/o boration

w/o operator FW

55

60

65

70

75

80

0 20 40 60 80 100 120

Level (%)

Time (s)

measured

base

w/o frequency

with PRZ PORV

w/o boration

w/o operator FW

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

0 20 40 60 80 100 120

Pressure (MPa)

Time (s)

measured (reconstructed)

base

w/o frequency

with PRZ PORV

w/o boration

w/o operator FW

4.928 MPa
22

Figure 29 LO-2 Steam Line No. 2 Pressure Signal – First Part

4.3 Second Part of Transient

The results for second part are shown in Figures 30 through 41. Two new simulations were 

performed in addition to the base case. Besides base case also a case by simulating some 

steam flow after SI signal actuation (labeled with SG PORV) was performed. Namely, when 

there is low steam line pressure signal there is also steam line isolation in the calculated cases, 

but measured steam slow at the exit of steam generators was non-zero, indicating that steam 

may be released through the SG PORVs if main steam line isolation occurred like suggested by 

simulation or steam dump if main steamline isolation did not occur. The influence of simulating 

some steam flow after SI signal is on the cold leg temperatures shown in Figures 32 and 33 and 

on the steam generator pressures shown in Figures 38 and 39. However, the other primary side 

parameters were not improved. Finally, the calculation was also performed by specifying turbine 

flow only (i.e. steam flow was not boundary condition) and steam dump model in the simulation 

performed well. There is no big difference between base case and case “with TB flow”.

Figure 30 Reactor Power – Second Part

4.5

5.5

6.5

7.5

8.5

9.5

10.5

11.5

0 20 40 60 80 100 120

Pressure (MPa)

Time (s)

measured (reconstructed)

base

w/o frequency

with PRZ PORV

w/o boration

w/o operator FW

4.928 MPa

0

25

50

75

100

0 40 80 120 160 200 240

Power (%)

Time (s)

measured

base

with SG PORV

with TB flow
23

Figure 31 Pressurizer Pressure – Second Part

Figure 32 Cold Leg No. 1 Temperature – Second Part

Figure 33 Cold Leg No. 2 Temperature – Second Part

13.5

14.0

14.5

15.0

15.5

16.0

16.5

0 40 80 120 160 200 240

Pressure (MPa)

Time (s)

measured

base

with SG PORV

with TB flow

556

558

560

562

564

566

568

0 40 80 120 160 200 240

Temperature (K)

Time (s)

measured

base

with SG PORV

with PRZ PORV

556

558

560

562

564

566

568

0 40 80 120 160 200 240

Temperature (K)

Time (s)

measured

base

with SG PORV

with TB flow
24

Figure 34 Hot Leg No. 1 Temperature – Second Part

Figure 35 Hot Leg No. 2 Temperature – Second Part

Figure 36 RCS Loop No. 1 Average Temperature – Second Part

555

565

575

585

595

605

0 40 80 120 160 200 240

Temperature (K)

Time (s)

measured

base

with SG PORV

with TB flow

555

565

575

585

595

605

0 40 80 120 160 200 240

Temperature (K)

Time (s)

measured

base

with SG PORV

with PRZ PORV

555

560

565

570

575

580

585

0 40 80 120 160 200 240

Temperature (K)

Time (s)

measured

base

with SG PORV

with TB flow
25

Figure 37 RCS Loop No. 2 Average Temperature – Second Part

Figure 38 Steam Generator No. 1 Pressure – Second Part

Figure 39 Steam Generator No. 2 Pressure – Second Part

555

560

565

570

575

580

585

0 40 80 120 160 200 240

Temperature (K)

Time (s)

measured

base

with SG PORV

with TB flow

6.0

6.5

7.0

7.5

8.0

0 40 80 120 160 200 240

Pressure (MPa)

Time (s)

measured

base

with SG PORV

withTB flow

6.0

6.5

7.0

7.5

8.0

0 40 80 120 160 200 240

Pressure (MPa)

Time (s)

measured

base

with SG PORV

with TB FLOW
26

Figure 40 Steam Generator No. 1 Narrow Range Level – Second Part

Figure 41 Steam Generator No. 2 Narrow Range Level – Second Part

4.4 Results Discussion 

It was shown that both before and after SI signal generation it is important to have available 

plant information about systems behavior. In the opposite the response may deviate. The 

analysis showed that in such transient when part of information is not available, the measured 

data may be used to reproduce some missing information. In the present study the steam dump 

demand signal was reproduced and the compensated low steam line pressure signals, which 

caused safety injection signal. When having this information available in addition to plant 

measurements, the transient could be better understood. The hypothesis done in internal plant 

analysis that operator manual main feedwater control did not help in secondary pressure 

stabilization was also confirmed. It seems that almost simultaneous request for opening and 

closing by turbine control and steam dump load rejection controller was the reason for two fast 

pressure decrease and consequential SI signal generation. Please note that automatic turbine 

control is in mode to control the speed of the turbine-generator.

20

40

60

80

0 40 80 120 160 200 240

Level (%)

Time (s)

measured

base

with SG PORV

with PRZ PORV

20

40

60

80

0 40 80 120 160 200 240

Level (%)

Time (s)

measured

base

with SG PORV

with TB flow
27

5. CONCLUSIONS

The analysis the latest RELAP5/MOD3.3 Patch 04 best-estimate thermalhydraulic computer 

code has been performed for the abnormal event with loss of external load, following by safety 

injection actuation and reactor trip. Comparison of the calculated data with plant measured data 

suggests that RELAP5 code can accurately simulate such abnormal event. It has been also 

checked whether the plant operators and plant systems performed as intended. Information on 

the time dependence of the values of parameters that are not directly observable using the plant 

instrumentation has been provided. It has been shown how the pressure change influences the 

low steam pressure signal, which is compensated signal and actuates safety injection signal. 

The steam dump demand signal was also predicted from the measured data. The hypothesis 

done in the internal plant analysis that operator manual main feedwater control did not help in 

secondary pressure stabilization has been also confirmed. It can be concluded that such 

calculations of plant events provide valuable insights into the plant response.

29

6. REFERENCES

1. INTERNATIONAL ATOMIC ENERGY AGENCY, “Deterministic Safety Analysis for

Nuclear Power Plants”, Specific Safety Guide, SSG-2, IAEA, Vienna (2009).

2. INTERNATIONAL INCIDENT REPORTING SYSTEM (IRS), Reactor Trip and Actuation

of Safety Injection System Caused by the Spurious Activation of Bus Protection in 400

KV Switchyard, IRS no. 8300, December 2012.

3. A. Prošek, B. Mavko, “Reactor trip analysis at Krško Nuclear Power Plant”, International

agreement report NUREG/IA, 0221, Office of Nuclear Regulatory Research, U.S.

Nuclear Regulatory Commission, Washington, 2010, pp. 1-57.

4. A. Prošek, I. Parzer, and B. Krajnc, “Simulation of hypothetical small-break loss-ofcoolant accident in modernized nuclear power plant”, Electrotechnical Review, 71(4),

2004, pp. 191-196.

5. I. Parzer, B. Mavko, and B. Krajnc, “Simulation of a hypothetical loss-of-feedwater

accident in a modernized nuclear power plant”, Journal of Mechanical Engineering,

49(9), 2003, pp. 430-444.





NUREG/IA-0458 RELAP5/MOD3.3 Analysis of Event with Actuation of Safety Injection System at 

the Loss of External Power