NUREG/IA-0442 

 

 International 

 Agreement Report

 

RELAP5/MOD3.3 analysis of steam 

generator tube rupture (SGTR) accident 

for NPP Krško 

Prepared by: 

V. Benčik, D. Grgić

University of Zagreb, Faculty of Electrical Engineering and Computing 

Unska 3 

10000 Zagreb, Croatia 

K. Tien, NRC Project Manager 

Office of Nuclear Regulatory Research 

U.S. Nuclear Regulatory Commission 

Washington, DC 20555-0001 

March 2014 

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-0442

RELAP5/MOD3.3 analysis of steam 

generator tube rupture (SGTR) accident for 

NPP Krško 

Manuscript Completed: December 2013 

Date Published: March 2014 

Prepared by: Vesna Benčik, Davor Grgić

University of Zagreb, Faculty of Electrical Engineering and Computing 

Unska 3 

10000 Zagreb, Croatia 

K. Tien, 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 

Steam Generator Tube Rupture (SGTR) event leads to contamination of the secondary side due 

to leakage of the radioactive coolant from the Reactor Coolant System (RCS) through the 

broken Steam Generator (SG) tube(s). Unlike other loss of coolant accidents, an early operator 

action is necessary to prevent radiological release to environment. The authors have analyzed 

SGTR for NPP Krško (NEK) using RELAP5/MOD3.3 code for two basic scenarios; i.e. with and 

without offsite power available. The plant model has been updated taking into account the 

Resistance Temperature Detector Bypass Elimination (RTDBE) project realized during the 2013 

outage. The actions from the standard Emergency Operating Procedures (EOPs) were 

modelled and the efficiency of operator actions to prevent radiological release to environment 

was evaluated. The time of the start of the operator action was selected as a critical parameter 

influencing occurrence of the release of the contaminated inventory (steam and liquid). In order 

to stop the steam release from the ruptured SG for the scenario with offsite power available the 

operator action has to be taken 15 minutes after transient begin, whereas the liquid solid 

condition and the liquid discharge can be prevented for operator action performed not later than 

45 minutes after transient begin. For the scenario with offsite power not available the operator 

action has to be performed not later than 20 minutes to prevent the broken SG liquid solid 

condition and the liquid discharge. For both cases the operator action successfully stops the 

primary to secondary leakage and the inventory release to the environment.

 v 

CONTENTS

Page 

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

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

TABLES ..................................................................................................................................... viii

EXECUTIVE SUMMARY ............................................................................................................. ix

ACKNOWLEDGEMENTS ........................................................................................................... xi

ABBREVIATIONS ..................................................................................................................... xiii

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

2. COMPUTATION MODEL OF NPP KRŠKO ........................................................................... 3

3. TRANSIENT DESCRIPTION .................................................................................................. 7

3.1 Initial and boundary conditions ..................................................................................... 9 

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

4.1 Analysis and results, CASE 1: Offsite power available ............................................. 13

4.2 Analysis and results, CASE 2: Offsite power not available....................................... 29

4.3 Discussion of differences between CASE 1 and CASE 2 analysis ........................... 46 

5. CONCLUSIONS .................................................................................................................... 53

6. REFERENCES ...................................................................................................................... 55
 
 vii 

FIGURES 

Page 

Figure 1 RELAP5/MOD3.3 nodalization scheme for NPP Krško ............................................. 5

Figure 2 Nodalization scheme for SGTR scenario ................................................................... 6

Figure 3 SGTR analysis, CASE 1a: Break mass flow rate ..................................................... 17

Figure 4 SGTR analysis, CASE 1a: Pressurizer NR level and liquid volume ...................... 17

Figure 5 SGTR analysis, CASE 1a: Pressurizer and SG pressure ....................................... 18

Figure 6 SGTR analysis, CASE 1a: Measured ∆T (compensated) and OT∆T setpoint ...... 18

Figure 7 SGTR analysis, CASE 1a: Nuclear power ................................................................ 19

Figure 8 SGTR analysis, CASE 1a: Reactor core power and SG power .............................. 19

Figure 9 SGTR analysis, CASE 1a: Reactivity ........................................................................ 20

Figure 10 SGTR analysis, CASE 1a: RCS temperature ......................................................... 20

Figure 11 SGTR analysis, CASE 1a: Safety injection mass flow rate .................................. 21

Figure 12 SGTR analysis, CASE 1a: RCS and SG mass ....................................................... 21

Figure 13 SGTR analysis, CASE 1a: Main and auxiliary feedwater flow.............................. 22

Figure 14 SGTR analysis, CASE 1a: Steam header pressure and SG 2 AFW flow ............. 22

Figure 15 SGTR analysis, CASE 1a: Main steam flow and steam dump flow ..................... 23

Figure 16 SGTR analysis, CASE 1a: Steam dump valve opening ........................................ 23

Figure 17 SGTR analysis, CASE 1a: SG NR level .................................................................. 24

Figure 18 SGTR analysis, CASE 1a: Pressurizer spray mass flow rate............................... 24

Figure 19 SGTR analysis, CASE 1a: Pressurizer heaters power .......................................... 25

Figure 20 SGTR analysis, CASE 1a: CVCS mass flow rate ................................................... 25

Figure 21 SGTR sensitivity analysis, CASE 1: Mass of broken SG (SG 1) .......................... 26

Figure 22 SGTR sensitivity analysis, CASE 1: Discharged mass through SG PORV ........ 26

Figure 23 SGTR sensitivity analysis, CASE 1: Discharged mass through broken SG (SG 

1) PORV and broken SG PORV flow liquid fraction ............................................ 27

Figure 24 SGTR sensitivity analysis, CASE 1: RCS subcooling .......................................... 27

Figure 25 SGTR sensitivity analysis, CASE 1: Pressurizer NR level ................................... 28

Figure 26 CASE 2a analysis: Break mass flow rate ............................................................... 33

Figure 27 CASE 2a analysis: RCS mass flow rate ................................................................. 33

Figure 28 CASE 2a analysis: Pressurizer NR level and liquid volume ................................ 34

Figure 29 CASE 2a analysis: Pressurizer and SG pressure ................................................. 34

Figure 30 CASE 2a analysis: Nuclear power .......................................................................... 35

Figure 31 CASE 2a analysis: Reactor core and SG power ................................................... 35

Figure 32 CASE 2a analysis: RCS temperature ..................................................................... 36

Figure 33 CASE 2a analysis: RCS average temperature ....................................................... 36

Figure 34 CASE 2a analysis: Loop 1 temperature and SG 1 auxiliary feedwater flow ....... 37

Figure 35 CASE 2a analysis: RCS subcooling, pressurizer level and pressurizer heaters 

power ....................................................................................................................... 37

Figure 36 CASE 2a analysis: Safety injection flow ................................................................ 38

Figure 37 CASE 2a analysis: RCS and SG mass ................................................................... 38

Figure 38 CASE 2a analysis: Main and auxiliary FW mass flow rate ................................... 39

Figure 39 CASE 2a analysis: Main and auxiliary FW mass flow rate, time (0-20000 s) ...... 39
 viii 

Figure 40 CASE 2a analysis: SG 2 PORV opening ................................................................ 40

Figure 41 CASE 2a analysis: Main steam and SG 2 PORV mass flow rate ......................... 40

Figure 42 CASE 2a analysis: SG pressure, integrated flow through SG PORV .................. 41

Figure 43 CASE 2a analysis: SG NR level .............................................................................. 41

Figure 44 CASE 2a analysis: Pressurizer PORV 1 and spray mass flow rate ..................... 42

Figure 45 CASE 2a analysis: Integral of pressurizer PORV 1 mass flow rate ..................... 42

Figure 46 CASE 2a analysis: CVCS mass flow rate ............................................................... 43

Figure 47 CASE 2 analysis: Mass of broken SG (SG 1)......................................................... 43

Figure 48 CASE 2 analysis: Broken SG (SG 1) steam dome volume liquid fraction .......... 44

Figure 49 CASE 2 analysis: Discharged mass through broken SG (SG 1) PORV, broken 

SG PORV liquid fraction ........................................................................................ 44

Figure 50 CASE 2 analysis: RCS subcooling ......................................................................... 45

Figure 51 CASE 2 analysis: Pressurizer level ........................................................................ 45

Figure 52 CASE 1 vs. CASE 2: 20 min for operator action: Steam dump (CASE 1) and SG 

2 PORV mass flow rate (CASE 2) .......................................................................... 47

Figure 53 CASE 1 vs. CASE 2: 20 min for operator action: SG power ................................. 48

Figure 54 CASE 1 vs. CASE 2: 20 min for operator action: Loop 1 temperature ................ 48

Figure 55 CASE 1 vs. CASE 2: 20 min for operator action: Loop 2 temperature ................ 49

Figure 56 CASE 1 vs. CASE 2: 20 min for operator action: Pressurizer liquid volume ...... 49

Figure 57 CASE 1 vs. CASE 2: 20 min for operator action: Pressurizer pressure, SG 1 

pressure and break (side 1) mass flow rate ......................................................... 50

Figure 58 CASE 1 vs. CASE 2: 20 min for operator action: SG 1 pressure and discharged 

mass through SG 1 PORV ..................................................................................... 50

Figure 59 CASE 1c (45 min for operator action) vs. CASE 2c (25 min for operator action): 

SG 1 pressure, discharged mass through SG 1 PORV and SG 1 mass ............ 51

TABLES 

Page 

Table 1 Initial conditions for SGTR analysis for NPP Krško ................................................. 10

Table 2 Boundary conditions for SGTR analysis for NPP Krško ......................................... 11

Table 3 Time table of main events for NEK SGTR CASE 1 analysis; parameter: begin of 

first operator action .................................................................................................... 16

Table 4 Time table of main events for NEK SGTR CASE 2 analysis; parameter: begin of 

first operator action .................................................................................................... 32

Table 5 NEK SGTR analysis; comparison of CASE 1 and CASE 2 analysis ....................... 47
 ix 

EXECUTIVE SUMMARY 

Steam Generator Tube Rupture (SGTR) event leads to contamination of the secondary side due 

to leakage of the radioactive coolant from the Reactor Coolant System (RCS) through the 

broken Steam Generator (SG) tube(s). Unlike other loss of coolant accidents, an early operator 

action is necessary to prevent radiological release to environment. The major concern for the 

SGTR event is the release of contaminated liquid through the secondary side relief valves to the 

atmosphere that may result in an increase of radiological doses. The primary-to-secondary 

leakage results in the RCS depressurization, which leads to an automatic reactor trip and Safety 

Injection (SI) actuation. Since the RCS pressure tends to stabilize at the value where the 

incoming SI flow rate equals the break flow rate, the operator must terminate the SI flow to stop 

the primary-to-secondary leakage and subsequent broken SG overfill and radioactive releases 

to the atmosphere. First, the operator is expected to determine that the SGTR has occurred and 

to identify and isolate the broken SG to minimize the contamination of the secondary side. The 

subsequent controlled RCS cooldown and depressurization are aimed firstly to achieve the 

conditions that satisfy the SI termination criteria and secondly to reduce the break flow. The goal 

of this part of the recovery procedure is to equalize the RCS and broken SG pressure in order to 

terminate the break flow whereas the RCS cooling is performed via intact SG using either steam 

dump or SG safety/or power operated relief valves. Finally, the plant cooldown and 

depressurization to hot and cold shutdown conditions with simultaneous depressurization of 

broken SG are performed. 

The authors have analyzed SGTR for NPP Krško using RELAP5/MOD3.3 code for two basic 

scenarios; i.e. with and without offsite power available. The plant model has been updated 

taking into account the Resistance Temperature Detector Bypass Elimination (RTDBE) project 

realized during the 2013 outage. The actions from the standard Emergency Operating 

Procedures (EOPs) were modelled and the efficiency of operator actions to prevent radiological 

release to environment was evaluated. The time of the start of the operator action was selected 

as a critical parameter influencing occurrence of the release of the contaminated inventory 

(steam and liquid). In order to stop the steam release from the ruptured SG for the scenario with 

offsite power available the operator action has to be taken 15 minutes after transient begin, 

whereas the liquid solid condition and the liquid discharge can be prevented for operator action 

performed not later than 45 minutes after transient begin. For operator action performed in time 

period between 15 and 45 minutes a limited amount of steam is discharged through the 

ruptured SG. For the scenario with offsite power not available the operator action has to be 

performed not later than 20 minutes to prevent the broken SG liquid solid condition and the 

liquid discharge. For both cases the operator action successfully stops the primary to secondary 

leakage and the inventory release to the environment. In all the analyzed cases the operator 

performed the complete RCS cooldown & depressurization to Hot ShutDown (HSD) conditions 

when the Residual Heat Removal (RHR) system can be put in operation. 

The report does not include the radiological consequences calculation, but based on the limited 

amount of the discharged fluid, they should be small. 
 
 xi 

ACKNOWLEDGEMENTS 

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

State Office for Nuclear Safety within CAMP program and continuous support from Croatian 

Ministry of science and education (project no. 036-0361590-1589). The RELAP5/MOD3.3 base 

input model was originally developed for Krško nuclear power plant. Special thank goes to 

M.Sc. Božidar Krajnc, director of engineering services division in Krško nuclear power plant, for 

expressing the need for such an analysis and for obtaining required plant data and permission 

to publish the results. 
 
 xiii 

ABBREVIATIONS 

ACC accumulator 

AFW auxiliary feedwater 

ANS american nuclear society 

BOL beginning of life 

CVCS chemical and volume control system 

EOP emergency operating procedure 

FER Faculty of Electrical Engineering and Computing 

HSD hot shutdown 

I&B initial and boundary 

MFIV main feedwater isolation valve 

MFW main feedwater 

MPa megapascal 

MSIV main steam line isolation valve 

NEK nuclear power plant Krško 

NPP nuclear power plant 

NR narrow range 

OP∆T overpower delta T 

OT∆T overtemperature delta T 

PORV power operated relief valve 

PRZ pressurizer 

PWR pressurized water reactor 

RCP reactor coolant pump 

RCS reactor coolant system 

RHR residual heat removal 

RPV reactor pressure vessel 

RSG replacement steam generator 

RTD resistance temperature detector 

RTDBE resistance temperature detector bypass elimination 

SB LOCA small break loss of coolant accident 

SG steam generator 

SGTR steam generator tube rupture 

SI safety injection 

SV safety valve 

US NRC United States Nuclear Regulatory Commission 

1 

1. INTRODUCTION 

Steam Generator Tube Rupture (SGTR) event leads to contamination of the secondary side due 

to leakage of the radioactive coolant from the Reactor Coolant System (RCS) through the 

broken Steam Generator (SG) tube(s). The major concern for the SGTR event is the release of 

contaminated liquid through the secondary side relief valves to the atmosphere that may result 

in an increase of radiological doses. The primary-to-secondary leakage results in the RCS 

depressurization, which leads to an automatic reactor trip (on low pressurizer pressure or 

overtemperature ∆T) and Safety Injection (SI) actuation. Since the RCS pressure tends to 

stabilize at the value where the incoming SI flow rate equals the break flow rate, the operator 

must terminate the SI flow to stop the primary-to-secondary leakage and subsequent broken SG 

overfill and radioactive releases to the atmosphere. 

This technical report is prepared to demonstrate the capability of plant systems as well as 

adequacy of operator actions to prevent the discharge of contaminated inventory to the 

environment. First, the operator is expected to determine that SGTR has occurred and to 

identify and isolate the broken SG to minimize the contamination of the secondary side. The 

subsequent controlled RCS cooldown and depressurization are aimed to achieve the conditions 

that satisfy the SI termination criteria and also result in break flow reduction. The goal of this 

part of the recovery procedure is to equalize the RCS and the broken SG pressure in order to 

terminate the break flow whereas the RCS cooling is performed via intact SG using either steam 

dump or SG safety/or power operated relief valves. Finally, the plant cooldown and 

depressurization to hot and cold shutdown conditions with simultaneous depressurization of 

broken SG are performed. 

The SGTR analysis for NPP Krško for the current plant configuration after Resistance 

Temperature Detector Bypass Elimination (RTDBE) and cycle 26 has been performed using 

RELAP5/MOD3.3 code. The SGTR analysis for the configuration before RTDBE and cycle 24 

has been performed before and the results were published in Ref. 1. The SGTR analysis is 

aimed to estimate the efficiency of operator actions in preventing the release of contaminated 

inventory to the environment. Best estimate initial and boundary conditions as well as realistic 

operator actions were assumed in the analysis. The sensitivity study with various SGTR 

recovery scenarios regarding the availability of offsite power and subsequent operator actions 

was performed to determine the time for operator actions to prevent the steam and liquid 

discharge to the environment. 

The time of the start of the operator action was selected as a critical parameter influencing 

occurrence of the release of the contaminated inventory (steam and liquid). The parameter is 

the time of begin of the first operator action (isolation of broken SG and the first cooldown as a 

preparatory action to fulfill the SI termination criteria). Following cases have been analyzed: 

1) CASE 1: Offsite power available 

CASE 1a: 15 minutes 

The steam discharge from the broken SG is stopped after first operator action. 

CASE 1b: 20 minutes 

The small amount of steam is discharged after first operator action. 
2 

CASE 1c: 45 minutes 

Only steam is discharged from the broken SG. 

CASE 1d: 50 minutes 

Broken SG becomes liquid solid and the liquid is discharged to the environment. 

2) CASE 2: Offsite power not available 

CASE 2a: 15 minutes 

Maximal liquid fraction of the steam dome volume in the broken SG is less than 50%. Only 

steam is discharged after first operator action. 

CASE 2b: 20 minutes 

Broken SG becomes almost liquid solid but only steam is discharged to the environment. 

CASE 2c: 25 minutes 

Broken SG becomes liquid solid and also liquid is discharged. 
 3

2. COMPUTATION MODEL OF NPP KRŠKO 

“Best estimate” code used for the analysis of the Steam Generator Tube Rupture (SGTR) for 

NPP Krško was RELAP5/MOD3.3, Microsoft Windows 98 version. RELAP5/MOD3.3 is the code 

developed for US NRC, for the modeling of complex thermohydraulic systems and is primarily 

intended to be used for the prediction of nuclear power plant behavior in the case of 

transients/accidents, Ref. 2. 

For the purpose of NPP Krško (NEK) transient/accident analyses such model has been 

developed at the Faculty of Electrical Engineering and Computing (FER). The model is in 

compliance with Ref. 2, described in Ref. 3 and qualified on the steady-state level, Ref. 4. 

Base NEK nodalization for the analysis of SGTR for NPP Krško is presented in Figure 1. The 

plant model corresponds to the status after the Resistance Temperature Detector (RTD) Bypass 

Elimination (RTDBE) that has been carried out during the October 2013 outage. The RTD 

bypass manifold system for the narrow range (NR) RCS temperature measurement is removed 

and replaced with the fast-response RTDs that are embedded in the thermowell structure as a 

part of a pipe wall. The RTDBE project affects the RCS temperature measurement response 

time which is accounted for in reactor protection system setpoints as well as in plant control 

system settings. 

The break is located at a bottom of one tube in the loop 1 (loop with pressurizer). The sensitivity 

analyses to identify the location of the break resulting in a maximum break flow were performed 

(the results are not presented here for brevity purposes). The outlet-cold side of the tube was 

found to have the maximum break flow, which is also confirmed by other analyses, e.g., Ref. 5. 

A doubled ended break was assumed having two sides as shown in Figure 2, i.e. the break side 

1 at the tube sheet outlet and the break side 2 at the tube bottom, respectively. The broken Utube is modeled separately with realistic tube cross sectional area and heat transfer area. The 

double ended break of U-tube is modeled by opening of the two valves (valves V1 and V2) 

connecting the break ends with the heat exchanger section on the SG secondary side, and 

closing the valve that connects the ends of tube before break occurrence (valve V3). 

The RELAP5 model consists of 503 thermal-hydraulic volumes, 542 junctions, 398 heat 

structures with 2347 mesh points, 785 control variables and 217 variable and 249 logical trips. It 

includes major modifications related to the Krško modernization project as well as RTDBE 

project; e.g., the model of the replacement steam generator (RSG) based on data provided by 

the RSG designer (Siemens), power uprate, removal of the guide tubes plugs inside the core as 

well as changes to the protection and plant control systems. Also, the new steam generator 

(SG) level and the rod control system for the point kinetics model were introduced, together with 

the model of main feedwater (MFW) and auxiliary feedwater (AFW) lines to the SGs. A detailed 

steam dump system with realistic steam dump valves (valves 624 through 633 in Figure 1) has 

been introduced in the model. The valves are divided into four banks; bank A (valves 624 and 

625), bank B (valves 626, 627 and 628), bank C (valves 629 and 630) and the bank D (valves 

631, 632 and 633), respectively. 

In order to accurately represent the NEK 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 main plant control 

systems: 
 4

 rod control system, 

 pressurizer pressure control system, 

 pressurizer level control system, 

 SG level control system, 

 steam dump. 

The nominal core power has been fixed through the control variable input as described in Ref. 

3. Also, primary heat losses were included in the model in order to represent actual plant status 

as close as possible. 

Generally, each control system calculation is enabled through the associated trip and consists 

of associated trips, general tables and control variables. 

Pressurizer pressure and level control system controls chemical and volume control system 

(CVCS) charging flow, pressurizer heaters power and spray control valves open area. As 

described in Ref. 3, pressurizer backup heaters are controlled by the pressurizer level and 

pressurizer pressure control systems. The rod control system calculates added reactivity from 

the integral rod worth versus steps withdrawn for banks d,c,b and a. SG level control system 

controls area of the feedwater control valve (FCV) in the MFW lines. Steam dump control 

system is modeled for three modes of operation, i.e., the load rejection and plant trip mode that 

control the RCS average temperature and the steam header pressure mode. The individual 

steam dump valve openings for each bank (A through D) are modeled by control variables 

taking into account all three modes of operation. 

The RTDBE project affects the operation of automatic rod control system and pressurizer level 

control system as well, since these systems use the measured NR average temperature either 

as a controlled parameter (Automatic rod control system) or as an input to calculate the setpoint 

(pressurizer level). Automatic control rod system constants (gains and time constants) are 

affected by RTDBE and pressurizer control systems constants are not. The constants and 

control functions of the overtemperature delta T (OT∆T) and overpower delta T (OP∆T) 

protection as well as of steam dump system have also been changed due to RTDBE. 
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branchpipe

time dependent volume

pumpaccumulator

xxx junction described at branch xxx

junction orientation

crossflow junction

time dependent junction

single junction

valve

Base deck ID: nekCClrv

MD AFW

Pump 1

TD AFW

MD AFW

Pump 2

Pump

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01

Steam Dump

Figure 1 RELAP5/MOD3.3 nodalization scheme for NPP Krško 
 6

Figure 2 Nodalization scheme for SGTR scenario 
 7

3. TRANSIENT DESCRIPTION 

The SGTR results in the primary-to-secondary leakage that exceeds the capacity of Chemical 

and Volume Control System (CVCS). The loss of coolant through the primary-to-secondary 

break causes the reactor coolant system (RCS) depressurization that leads to an automatic 

reactor trip (on low pressurizer pressure or overtemperature ∆T) and safety injection (SI) 

actuation. After SI actuation, the RCS pressure will tend to stabilize at the value where SI flow 

equals the break flow rate. Unlike other loss of coolant accidents an early operator involvement 

is necessary to prevent the radiological release to environment. If not terminated, the primaryto-secondary leakage causes the filling-up of the secondary side of the affected SG with 

contaminated liquid until the pressure rises above the SG PORV valve opening setpoint. First, 

the steam is discharged through the broken SG PORV and the liquid discharge follows if the 

operator has not stopped primary-to-secondary leakage. The operator actions were adopted 

from the NPP Krško Emergency Operating Procedure (EOP) E-3, Steam Generator Tube 

Rupture, Ref. 7. The operator actions can be divided into three basic steps: 

1. The operator is expected to determine that a SGTR has occurred and to identify and isolate 

the broken SG by closing the main feedwater and the main steam isolation valve. The operator 

shall determine the accident occurrence by observing the difference between steam and 

feedwater flow (if detected before reactor trip) as well as by observing the increase of radiation 

level in the affected SG. 

2. The operator shall terminate the break flow as soon as possible to prevent SG PORV 

opening and steam discharge to the atmosphere. If the operator action was not performed 

before reactor and the subsequent turbine trip and the steam dump is not available, SG PORV 

valve will open on both SGs. In this case the terminating of the primary-to-secondary leakage 

terminates the steam discharge on one side and on the other side it prevents the broken SG 

liquid filled condition and the subsequent liquid discharge. This is particularly important since the 

spillage of the liquid is more critical than the release of only steam. 

In order to stop the primary-to-secondary leakage the operator has to terminate the SI flow. The 

prerequisites for SI termination are a sufficient RCS subcooling margin, the pressurizer level 

that accounts for pressurizer inventory loss due to outsurge after SI termination and the SG 

level in the intact SG that ensures heat sink. The first operator action that precedes the SI 

termination is the cooldown (1st cooldown) performed as fast as possible to the RCS 

temperature that should ensure the required RCS subcooling. The target core exit temperature 

is determined as a saturation temperature corresponding to the damaged SG pressure minus 

the RCS subcooling measurement uncertainty. As soon as the 1st cooldown has been 

performed, the operator should decrease the RCS pressure in order to decrease the break flow. 

The preferred way to perform the cooldown is the steam dump since it has larger capacity than 

the SG PORV and the cooldown can be performed fast. For depressurization, the operator 

should always use pressurizer spray if the RC pumps are in operation since the pressurizer 

spray recovers pressurizer inventory. Thereby, the operator regulates the pressurizer spray flow 

in order to prevent the pressurizer liquid solid conditions by maintaining the pressurizer level. 

On the secondary side, the operator should maintain the SG narrow range level of the intact SG 

not less than 20% in order to ensure the required heat sink. Finally, the operator terminates the 

SI flow. The inherent system behavior with pressurizer pressure setpoint set to the broken SG 

pressure tends to equalize the RCS and broken SG pressure. This leads to termination of the 

break flow and the stop of the filling of the broken SG. 
 8

3. Operator performs the actions to prepare the plant for SG inspection and repair. First, the 

cooldown & depressurization to hot shutdown (HSD) conditions (RCS pressure< 2.8 MPa, RCS 

average temperature < 177 °C) is performed when Residual Heat Removal (RHR) system can 

be put in operation. The goal of this action is twofold, i.e., to depressurize the broken SG and on 

the other side to prepare the plant for cooldown to cold shutdown conditions. At cold shutdown, 

the primary circuit is drained to mid-loop elevation, and the steam generators can be isolated for 

inspection and repair from the rest of the primary circuit. 

The time of the start of the operator action was selected as a critical parameter influencing 

occurrence of the release of the contaminated inventory (steam and liquid). The parameter is 

the time of begin of the first operator action (isolation of broken SG and the first cooldown as a 

preparatory action to fulfill the SI termination criteria). 

Following cases have been analyzed: 

1) CASE 1: Offsite power available 

CASE 1a: 15 minutes 

The steam discharge from the broken SG is stopped after first operator action. 

CASE 1b: 20 minutes 

The small amount of steam is discharged after first operator action. 

CASE 1c: 45 minutes 

Only steam is discharged from the broken SG. 

CASE 1d: 50 minutes 

Broken SG becomes liquid solid and the liquid is discharged to the environment. 

2) CASE 2: Offsite power not available 

CASE 2a: 15 minutes 

Maximal liquid fraction of the steam dome volume in the broken SG (volume 429 in Figure 1) is 

less than 50%. Only steam is discharged after first operator action. 

CASE 2b: 20 minutes 

Broken SG becomes almost liquid solid but only steam is discharged to the environment. 

CASE 2c: 25 minutes 

Broken SG becomes liquid solid and also liquid is discharged. 
 9

3.1 Initial and boundary conditions 

The SGTR analyses were performed for Beginning Of Life (BOL), cycle 26, and nominal power 

(1994 MW). The initial and boundary conditions for SGTR analysis are summarized in Table 1 

and Table 2, respectively. Best estimate initial and boundary conditions were assumed in the 

analysis with the exception of automatic rod control system that is not available. In the analysis 

it was assumed that the operator did not start any action before reactor trip or safety injection. 

The steam dump was assumed available first by controlled operator action, whereas an 

automatic steam dump following the reactor trip was disabled. The operator actions assumed in 

the analyses were adopted from the NEK EOP E-3 procedure, Steam Generator Tube Rupture, 

Ref. 7. The operator actions are performed in two steps: 

1. Identification and isolation of the damaged SG (Main Steam Isolation Valve (MSIV) 

closure and isolation of main feedwater). Next, the operator performs the actions in order to 

terminate the primary-to-secondary leakage, i.e., the first cooldown performed as fast as 

possible followed by subsequent depressurization and finally the SI termination. The latter two 

actions are aimed to equalize the primary and secondary pressure thus stopping the leakage. 

The RCS cooldown is aimed to provide the required RCS subcooling after SI had been 

terminated. The target core exit temperature is determined according to NEK EOP recovery 

procedure, i.e., as the saturation temperature corresponding to the damaged SG pressure 

minus the RCS subcooling uncertainty. The realistic time for operator actions have been 

assumed; i.e., after closing the MSIV, the cooldown is initiated with 3 minutes delay and the 

depressurization 3 minutes after successful 1st cooldown. 

2. RCS cooldown & depressurization to HSD conditions when RHR system can be put in 

operation. The maximum allowed RCS cooldown rate was limited to 55.6 °C/hour and the 

depressurization rate was adjusted to maintain the required RCS subcooling (19 °C). 

During recovery procedure, the operator controls the charging and letdown flow to maintain the 

pressurizer level at 35% for the case with offsite power available and at 50% for the case 

without offsite power. This value was selected to ensure the minimum level for pressurizer 

pressure control during RCS cooldown. The pressurizer spray and PORV operation are defined 

in the pressurizer NR level range (50%, 60%) and (60%, 80%), respectively. These values were 

obtained as a result of performed sensitivity analyses resulting in the sufficient margin to 

pressurizer liquid solid condition and successful cooldown & depressurization to HSD 

conditions. 

The accident was further investigated regarding the major concern for SGTR event, i.e., the 

release of contaminated inventory through the damaged SG PORV. First, the less severe case 

(only steam release) was analyzed. The cases for the offsite power available (CASE 1) where 

steam is released through the damaged SG PORV (CASE 1b) after the first operator action and 

the case with no release after the first operator action (CASE 1a) were identified. For the CASE 

2 (offsite power not available) the cases with only steam release were identified; CASE 2a 

(maximal liquid fraction in the steam dome volume in the broken SG less than 50%) and CASE 

2b with broken SG steam dome volume almost liquid solid but with no liquid discharge. 

Furthermore, for the CASE 1 the maximum time for the first operator action was determined for 

relief of only steam (CASE 1c) and the time where liquid is discharged (CASE 1d), respectively. 

For the CASE 2 the release of liquid was analyzed in the CASE 2c. For all the analyzed cases 

(both with and without liquid discharge through the damaged SG PORV) the whole event with 

cooldown to HSD conditions was simulated. 
10

The results of RELAP5 part of the steady state calculation after 1000 seconds are reported in 

the table below. 

Table 1 Initial conditions for SGTR analysis for NPP Krško 

Parameter Unit RELAP5 calculation 

Nuclear power MW 1994 

Primary pressure MPa 15.51 

Secondary pressure MPa 6.44/6.42 

RCS average temperature K 578.15/578.06 

SG power MW 996.6/1002.5 

Primary volumetric flow rate m3/s 6.27/6.26 

SG mass kg 49092/48960 

PRZR level % 55.8 

SG NR level % 69.3/69.3 

Steam mass flow rate kg/s 541.27/544.39 

Feedwater mass flow rate kg/s 541.27/544.39 

Circulation ratio - 3.75/3.73 
11

Table 2 Boundary conditions for SGTR analysis for NPP Krško 

Boundary condition CASE 1 (Offsite power 

available) 

CASE 2 (Offsite power not 

available) 

RCP trip - At a time of reactor trip 

Type of RCS cooldown Steam dump (not available 

before cooldown) 

SG 2 PORV, Steam dump not 

available 

RCS depressurization Pressurizer spray Pressurizer PORV 

1st operator action: 

Isolation of broken SG (SG 1) and 1st

cooldown (3 minutes delay) 

Operator action stops steam 

release from SG 1 PORV: 

CASE a: 15 min after transient 

begin (operator action 

successful) 

CASE b: 20 min after transient 

begin (limited steam release) 

Operator action to prevent 

liquid discharge through SG 1 

PORV: 

CASE c: 45 min after transient 

begin (operator action 

successful) 

CASE d: 50 min after transient 

begin (SG 1 PORV liquid 

fraction > 0.1) 

CASE a: 15 min after transient 

begin (SG 1 steam dome 

volume liquid fraction < 0.5, 

only steam release) 

Operator action to prevent 

liquid discharge through SG 1 

PORV: 

CASE b: 20 min after transient 

begin (operator action 

successful) 

CASE c: 25 min after transient 

begin (SG 1 PORV liquid 

fraction > 0.1) 

Start of operator action to depressurize 

and recover RCS after first cooldown 

3 minutes after 1st cooldown: 

Operator adjusts pressurizer 

setpoint pressure 2 bar above 

SG 1 pressure 

3 minutes after 1st

 cooldown: 

Operator adjusts pressurizer 

setpoint pressure 2 bar above 

SG 1 pressure 

Operator turns off SI (3 minutes delay) RCS depressurization finished 

RCS subcooling >19 °C 

PRZR level >15% 

NR level of intact SG>20% 

RCS depressurization finished 

RCS subcooling >19 °C 

PRZR level >15% 

NR level of intact SG>20% 

2nd cooldown: 

- Operator starts RCS depressurization 

& cooldown to hot shutdown (2.8 MPa, 

177 °C) 

- Operator enables CVCS (two charging 

pumps available) 

0.5 hours after SI termination 

PRZR level setpoint=35 % 

0.5 hours after SI termination 

PRZR level setpoint=50 % 

SG NR level setpoint for auxiliary 

feedwater operation 

SG 1: cycling between 50 and 

60% 

SG 2: cycling between 60 and 

70% 

SG 1: cycling between 50 and 

60% 

SG 2: cycling between 60 and 

70% 

PRZ level setpoint for PRZ spray/PRZ 

PORV operation 

PRZ spray operation for PRZ 

level < 60%; cycling: (50%, 

60%) 

PRZ PORV operation for PRZ 

level < 80%; cycling: (60%, 

80%) 

PRZ level setpoint for PRZ heaters 

(actuated to maintain PRZ pressure 

greater than 1.8 MPa) 

- PRZ proportional heaters 

operation enabled for PRZ level 

>20%; cycling: (20%, 30%) 

- PRZ backup heaters disabled 

- PRZ proportional heaters 

operation enabled for PRZ level 

>20%; cycling: (20%, 30%) 

- PRZ backup heaters disabled 

 

13 

4. RESULTS 

4.1 Analysis and results, CASE 1: Offsite power available 

The transient was initiated after 1000 seconds of steady state calculation by simultaneously 

opening of two break valves simulating the double ended break of one U-tube to the bottom of 

the SG 1 riser section and closing the valve connecting the U-tube ends. The main events are 

summarized in Table 3. The cases were identified regarding to the discharge through the 

broken SG PORV following the first operator action; i.e. the case without any discharge (CASE 

1a), the case with only steam discharge (CASE 1b), the case for the latest operator action 

where only steam is discharged (CASE 1c) and the case where the operator action does not 

prevent the broken SG liquid discharge (CASE 1d). Here, the case with no discharge after first 

operator action (CASE 1a) is presented in a more detail. Due to loss of RCS inventory through 

the break, Figure 3, the pressurizer level, Figure 4, decreases thus reducing the primary 

pressure, Figure 5. The automatic reactor trip (162.2 s after transient begin) was actuated on 

OT∆T reactor trip signal (actuated due to primary pressure decrease), Figure 6, and the turbine 

trip is actuated immediately after reactor trip. Following reactor trip, the large negative scram 

reactivity is inserted, Figure 9, and nuclear power as well as core thermal power decrease to noload value, Figure 7 and Figure 8. The cooldown following the reactor trip, Figure 10, causes 

decrease of coolant specific volume, which increases the outsurge flow from the pressurizer and 

the RCS pressure starts to decrease more rapidly. Finally, the SI on low-2 pressurizer pressure 

is actuated (at time=346.1 s), Figure 11. The SI adds the inventory to the RCS and increases 

the primary pressure which supports the primary-to-secondary leakage and the increase of the 

broken SG inventory, Figure 12. The main feedwater is isolated before SI actuation on low RCS 

average temperature signal in combination with reactor trip (at time=256.7 s). On the secondary 

side, the pressure increases after turbine trip, Figure 5, and the SG PORV valve opens on both 

SG 1 and SG 2, Figure 22. The secondary pressure decrease following the SG PORV operation 

continues even after closure of the SG PORVs due to condensation of steam after injection of 

cold auxiliary feedwater (AFW), Figure 13. This rather slow pressure decrease ends at 500 s. 

Due to the fact that the steam dump was assumed unavailable before first operator action (not 

before 1080 s in the CASE 1a, the secondary pressure increased after closing the AFW flow in 

both SGs. The first operator action consists of the isolation (closing of the main steam isolation 

valve (MSIV) of the broken SG) and the cooldown (1st cooldown) & depressurization performed 

as fast as possible to terminate the SI and stop the primary-to-secondary leakage. In order to 

perform the RCS cooldown the operator uses the steam dump in steam header pressure mode 

and sets the steam header pressure setpoint to the value that would result in the target core exit 

temperature. The target temperature is determined as a saturation temperature corresponding 

to the broken SG pressure at a time of the begin of the cooldown taking into account the 

subcooling measurement uncertainty and an additional subcooling uncertainty (11.11 °C). In the 

analysis, it was assumed that the operator has enabled the steam dump bank A having two 

valves (out of 10 valves for all the banks). This has resulted in the fast first cooldown that lasted 

2 minutes and a few seconds. The secondary pressure of both SGs that were coupled via 

steam header, Figure 5, decouple after SG 1 isolation. The pressure of the intact SG that was 

very close to the broken SG pressure rapidly decreased after start of steam relief via steam 

dump. The broken SG pressure decreases, too, despite of MSIV isolation. The reason is in the 

strong RCS cooldown and heat flux reversal in the broken SG, Figure 8, that causes the broken 

SG temperature and pressure decrease. The pressure in the broken SG fell below the PORV 

opening setpoint and the release through the broken SG is thus stopped. The RCS pressure 

decreases during cooldown due to outsurge from the pressurizer. However, as soon as the 
14

cooldown had been finished the RCS pressure rises again due to persisting SI flow. Three 

minutes after cooldown had been finished, the operator started the depressurization with target 

RCS pressure equal to broken SG pressure (plus 2 bar in order to account for the difference 

between pressurizer and the SG tube bottom) using the pressurizer spray, Figure 18. During the 

depressurization the operator has fully opened spray valves until the required pressure was 

reached. Thereafter, the pressurizer spray was controlled automatically. The pressurizer spray 

was closed when the pressurizer level increased above 60% in order to prevent the liquid solid 

condition. After closing the pressurizer spray the RCS pressure started to rise again due to 

persisting SI flow that has substantially increased due to RCS pressure decrease. During the 

spray operation the pressurizer inventory has recovered which was one of the prerequisites for 

SI termination. After finishing the RCS depressurization and with the required criteria fulfilled; 

i.e., pressurizer level greater than 15%, subcooling greater than 19 °C and NR level of intact SG 

greater than 20% the SI termination was performed with 3 minutes delay (at time=1729 s). The 

pressure difference between the primary and secondary side is sufficiently high to fill up the 

broken SG for about 20 minutes after SI termination. Gradually, the primary pressure decreases 

and approaches the broken SG pressure, whereas the resultant break flow decreases to zero 

and the primary-to-secondary leakage is stopped. 

The safety injection has been identified to have the major role in supporting the primary-tosecondary leakage. Therefore, the time of the first operator action aimed to prepare the plant 

conditions for SI termination has been chosen as the parameter in sensitivity analyses aimed to 

determine the maximum time for the start of the first operator action to prevent steam and liquid 

discharge. In the analysis, the steam discharge after first operator action was obtained if the 

operator has performed the first action 20 minutes after transient begin, whereas for the 15 

minutes there was no additional discharge, Table 3. If the operator action was not started in a 

due time to prevent the broken SG filled with liquid, liquid discharge would follow after steam 

had been discharged. The comparison of the results for the cases with and without discharge 

(Parameter is the time of the first operator action.) are shown in Figure 21 through Figure 25. 

The results are summarized below: 

CASE 1a (15 min), no release after first operator action, total: 4972 kg 

CASE 1b (20 min), discharged mass=74 kg of steam after first operator action (total 7307 kg) 

CASE 1c (45 min), discharged mass=13952 kg of steam (no liquid) 

CASE 1d (50 min), discharged mass=15745 kg (steam and also liquid discharge). 

Here, the liquid fraction of the flow through the SG 1 PORV greater than 0.1 has been selected 

as a criteria for liquid discharge. For the CASE 1d the SG became liquid solid, (liquid fraction in 

the steam dome volume (volume 429) liquid fraction=1), whereas for the CASE 1c only steam is 

discharged despite of almost liquid solid condition in the broken SG (max. liquid fraction in the 

steam dome volume=97.1%). The duration of the discharge through the SG 1 PORV increases 

with increasing the delay for the first operator action; e.g., for the CASE 1b discharge lasts for 

29 minutes, 33 minutes for the CASE 1c and 45 minutes for the CASE 1d, respectively. Thus, if 

not performed in due time to prevent any discharge, the operator actions have proven to be 

efficient in at least limiting the amount of discharged mass. 

A half an hour after terminating the SI flow, the operator starts the final cooldown & 

depressurization to hot shutdown conditions. Also, the normal CVCS is actuated, Figure 20. In 

the analysis, the operator adjusts the steam header setpoint pressure (steam dump system) in 
15

order to perform the cooldown to hot shutdown conditions, Figure 10. Similarly to the first 

cooldown, the operator has enabled the steam dump valves of the bank A (two valves) to 

perform the final cooldown. The resulting steam dump flow and the valve opening are shown in 

Figure 15 and Figure 16. The realistic valve model is used and the valve opening increases with 

decreasing SG 2 pressure in order to obtain the required flow. Along with the cooldown the RCS 

depressurization takes place aimed on one side to follow the RCS temperature during cooldown 

and on the other side to depressurize the broken SG. Pressurizer spray operation was 

determined by the pressurizer pressure setpoint and by the pressurizer level not greater than 60 

% in order to prevent pressurizer liquid solid conditions, Figure 18. Along with the RCS 

depressurization, Figure 5, the back flow from the SG 1 to the RCS is established and the mass 

of broken SG decreases, Figure 12. By finishing the RCS depressurization approx. 3 hours after 

first operator action the net break flow from the two break sides is zero and the stable conditions 

both on primary as well as on secondary side are established. At the end of cooldown and 

depressurization the pressurizer pressure was equal to 1.8 MPa, whereas the RCS average 

temperature oscillated with a small amplitude around its target value (450 K). The RCS 

temperature oscillations are caused by the oscillatory behaviour of the steam header pressure 

which on the other side is affected by the ON/OFF injection of the auxiliary feedwater, Figure 

14. The steam dump valve opening, Figure 16, that is controlled by the steam dump control in 

steam header pressure mode as well as steam dump flow oscillate as well. The cooldown to the 

HSD conditions was performed at around 53.4 °C/hour that is close to maximum allowed 

cooldown rate (55.6 °C/hour). It lasted for approximately 1 hour and 40 minutes for all the 

analyzed cases. At the end of depressurization the pressurizer pressure, Figure 5 is held slightly 

greater than broken SG pressure to maintain the constant SG inventory. On the other side the 

pressurizer pressure is maintained above the lower limit (1.8 MPa) that is determined by the 

RHR operation and subcooling requirement. The subcooling during the cooldown procedure 

was considerably larger than the limiting value (19 °C), Figure 24 and pressurizer level was 

maintained within the acceptable range (25%-60%), Figure 25. The primary side mass after the 

end of the cooldown to HSD conditions is affected by the normal CVCS charging and letdown 

flow aimed to maintain the programmed pressurizer level (35 %), Figure 12, Figure 4 and Figure 

20. 
16

Table 3 Time table of main events for NEK SGTR CASE 1 analysis; parameter: begin of 

first operator action 

Event CASE 1a 

(15 min) 

CASE 1b 

(20 min) 

CASE 1c 

(45 min) 

CASE 1d 

(50 min) 

Transient start 0 s 0 s 0 s 0 s 

Reactor trip (OT∆T trip, loop 2) 162.2 s 162.2 s 162.2 s 162.2 s 

Turbine trip (on reactor trip) 162.2 s 162.2 s 162.2 s 162.2 s 

Main FW isolation (on low RCS 

average temperature & reactor 

trip) 

256.7 s 256.7 s 256.7 s 256.7 s 

SI actuation (on low-2 pressurizer 

pressure) 

346.1 s 346.1 s 346.1 s 346.1 s 

1st operator action: MSIV 1 

isolation 

900 s 1200 s 2700 s 3000 s 

1st cooldown 1080 s 1380 s 2880 s 3180 s 

Time to achieve target core exit 

temperature during first cooldown 

1214 s 

(542.1 K) 

1511 s 

(542.0 K) 

3016 s 

(541.5 K) 

3315 s 

(541.6 K) 

1st RCS depressurization 1394 s 1691 s 3196 s 3495 s 

Operator turns off SI (180 s 

delay) 

1729 s 2016 s 3541 s 3852 s 

End of primary-to-secondary 

leakage 

2950 s 3334 s 5350 s 5670 s 

Discharge through SG 1 PORV 

(after 1st operator action) 

- 2525 s 3170 s 3470 s 

SG 1 steam dome liquid fraction 

> 10% 

- - 3735 s 3040 s 

Max. SG 1 steam dome liquid 

fraction 

0.02% (197 s) 0.02% (197 s) 97.1% (5350 s) 100% (4525 s) 

Liquid discharge - SG 1 PORV 

(voidfj > 0.1) 

- - - 4600 s 

End of discharge 1140 s 2960 s 4685 s 5690 s 

Total discharged mass through 

SG 1 PORV after 1st operator 

action 

0 kg 74 kg 372 kg 1165 kg 

Total discharged mass through 

SG 1 PORV 

4972 kg 7307 kg 13952 kg 15745 kg 

2nd cooldown & depressurization 

to HSD; CVCS enabled, operator 

isolates accumulators 

3529 s 3816 s 5341 s 5652 s 

HSD conditions achieved, 

cooldown rate 

9540 s 

(53.3 °C/hour) 

9820 s 

(53.4 °C/hour) 

11320 s 

(53.6 °C/hour) 

11670 s 

(53.2 °C/hour) 
17

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e( s)

M ass f low ( k g/s)

-2

0

2

4

6

8

10

12

14

Break side 1 

Break side 2 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 3 SGTR analysis, CASE 1a: Break mass flow rate 

Volume (m3)

0 2 4 6 8 10 12 14 16 18

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e( s)

Level (% )

-10 0 10 20 30 40 50 60 70 80

PRZ level 

PRZ liquid volume 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 4 SGTR analysis, CASE 1a: Pressurizer NR level and liquid volume 
18

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e( s)

Pressure (M Pa)

2 4 6 8 10 12 14

PRZ 

SG 1 

SG 2 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 5 SGTR analysis, CASE 1a: Pressurizer and SG pressure 

0 50 100 150 200 250 300 350 400 450 500

T im e( s)

DT (K)

0 5 10 15 20 25 30 35 40 45 50

OTDT setpoint,loop 1 

Measured DT,loop 1 

OTDT setpoint,loop 2 

Measured DT,loop 2 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 6 SGTR analysis, CASE 1a: Measured ∆T (compensated) and OT∆T setpoint 
19

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e ( s)

N uclear pow er (M W )

0

200

400

600

800

1000

1200

1400

1600

1800 RKTPOW 0 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 7 SGTR analysis, CASE 1a: Nuclear power 

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e( s)

Pow er (M W )

0 200 400 600 800 1000 1200 1400 1600 1800

Reactor core 

SG 1 

SG 2 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 8 SGTR analysis, CASE 1a: Reactor core power and SG power 
20

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e( s)

Reactivity (D O LLA RS)

-16 -14 -12 -10 -8 -6 -4 -2 0 2

Scram 

Total 

Moderator 

Boron 

Doppler 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 9 SGTR analysis, CASE 1a: Reactivity 

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e( s)

T emperature (K )

460 480 500 520 540 560 580

Cold leg 1 

Cold leg 2 

Hot leg 1 

Hot leg 2 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 10 SGTR analysis, CASE 1a: RCS temperature 
21

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e ( s)

M ass flow (kg/s)

0

5

10

15

20

25

30

35

40

45

CNTRLVAR 757 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 11 SGTR analysis, CASE 1a: Safety injection mass flow rate 

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e( s)

M ass ( t)

50 60 70 80 90 100 110 120 130 140 150

RCS 

SG 1 

SG 2 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 12 SGTR analysis, CASE 1a: RCS and SG mass 
22

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e ( s)

M ass f low ( k g/s)

0

50

100

150

200

250

300

350

400

450

500 MFW 1 

MFW 2 

AFW 1 

AFW 2 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 13 SGTR analysis, CASE 1a: Main and auxiliary feedwater flow 

M ass f low ( k g/s)

0 5 10 15 20 25

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e ( s)

Pressure (M Pa)

12345678

Steam header pressure 

AFW 2 flow 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 14 SGTR analysis, CASE 1a: Steam header pressure and SG 2 AFW flow 
23

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e( s)

M ass f low ( k g/s)

-50 0 50 100 150 200 250 300 350 400 450 500 550

SG 1 

SG 2 

Steam dump 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 15 SGTR analysis, CASE 1a: Main steam flow and steam dump flow 

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e( s)

Valve opening (-)

0 .1 .2 .3 .4 .5 .6 .7 .8 .9 1

Bank A 

Bank B 

Bank C 

Bank D 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 16 SGTR analysis, CASE 1a: Steam dump valve opening 
24

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e( s)

Level (% )

10 20 30 40 50 60 70 80 90

SG 1 

SG 2 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 17 SGTR analysis, CASE 1a: SG NR level 

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e ( s)

M ass f low ( k g/s)

0

5

10

15

20

25

30

35

40 MFLOWJ 84010000 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 18 SGTR analysis, CASE 1a: Pressurizer spray mass flow rate 
25

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e ( s)

Pow er (kW )

0 100 200 300 400 500 600 700

Proportional heaters 

Backup heaters 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 19 SGTR analysis, CASE 1a: Pressurizer heaters power 

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e( s)

M ass f low ( k g/s)

0 .5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6

Charging 

Pump seal 1 

Pump seal 2 

Letdown 

N EK SGTR CY C 26 BOL, CASE 1a

Figure 20 SGTR analysis, CASE 1a: CVCS mass flow rate 
26

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e ( s)

M ass (kg)

50000

60000

70000

80000

90000

100000

110000

CASE 1a 

CASE 1b 

CASE 1c 

CASE 1d 

N EK SGTR CY C 26 BOL, CASE 1

Figure 21 SGTR sensitivity analysis, CASE 1: Mass of broken SG (SG 1) 

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e ( s)

M ass (kg)

0

2000

4000

6000

8000

10000

12000

14000

SG 1 PORV,CASE 1a 

SG 2 PORV,CASE 1a 

SG 1 PORV,CASE 1b 

SG 2 PORV,CASE 1b 

SG 1 PORV,CASE 1c 

SG 2 PORV,CASE 1c 

SG 1 PORV,CASE 1d 

SG 2 PORV,CASE 1d 

N EK SGTR CY C 26 BOL, CASE 1

Figure 22 SGTR sensitivity analysis, CASE 1: Discharged mass through SG PORV 
27

Liquid fraction (-)

0 .05 .10 .15 .20 .25 .30 .35 .40

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e ( s)

M ass (kg)

0 2000 4000 6000 8000 10000 12000 14000

Disch. mass,CASE 1a 

Disch. mass,CASE 1b 

Disch. mass,CASE 1c 

Disch. mass,CASE 1d 

Liq. fraction,CASE 1a 

Liq. fraction,CASE 1b 

Liq. fraction,CASE 1c 

Liq. fraction,CASE 1d 

N EK SGT R CY C 26 BOL, CASE 1

Figure 23 SGTR sensitivity analysis, CASE 1: Discharged mass through broken SG 

(SG 1) PORV and broken SG PORV flow liquid fraction 

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e ( s)

Subcooling (C)

20 25 30 35 40 45 50 55 60 65

CASE 1a 

CASE 1b 

CASE 1c 

CASE 1d 

N EK SGT R CY C 26 BOL, CASE 1

Figure 24 SGTR sensitivity analysis, CASE 1: RCS subcooling 
28

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 22000

T im e ( s)

Level (% )

-10 0 10 20 30 40 50 60 70 80

CASE 1a 

CASE 1b 

CASE 1c 

CASE 1d 

N EK SGTR CY C 26 BOL, CASE 1

Figure 25 SGTR sensitivity analysis, CASE 1: Pressurizer NR level 
29

4.2 Analysis and results, CASE 2: Offsite power not available 

The transient was initiated after 1000 seconds of steady state calculation in the same manner 

as for CASE 1, i.e., the two break valves simulating the double ended break of one U-tube are 

open simultaneously with closing the valve that connects the U-tube ends before the break. The 

main events are summarized in Table 4. The results for the cases with steam (cases 2a and 2b) 

and also with liquid discharge (CASE 2c) through the broken SG PORV are summarized. The 

CASE 2 is identical to the CASE 1 until reactor trip when in the CASE 2 a loss of offsite power is 

assumed. Loss of offsite power results in a coastdown of both RCPs and automatic closure of 

steam dump valves. In reality, loss of offsite power would cause loss of main feedwater, but in 

the analysis it was conservatively assumed that the normal feedwater was in operation until 

either reactor trip in combination with low RCS average temperature or SI signal trip the 

feedwater pumps. The results are graphically presented in Figure 26 to Figure 51. Here, the 

case with only steam discharge and the steam dome volume of the broken SG filled with less 

than 50% with liquid (CASE 2a – 15 minutes for the first operator action) is presented in a more 

detail. Until reactor trip at 162.2 s after transient begin the transient is identical to the previously 

analyzed case (CASE 1). Immediately after reactor trip, loss of offsite power occurs resulting in 

a loss of forced RCS flow, Figure 27. The cooldown following the reactor trip, Figure 32, causes 

decrease of coolant specific volume, which increases outsurge flow from the pressurizer and the 

RCS pressure decreases more rapidly. Finally, the SI on low-2 pressurizer pressure is actuated 

(at time=300 s), Figure 36. The SI adds the inventory to the RCS and increases the primary 

pressure which supports the primary-to-secondary leakage and the increase of the broken SG 

inventory, Figure 37. The main feedwater is isolated before SI actuation on low RCS average 

temperature signal in combination with reactor trip (at time=289.2 s). The secondary pressure 

increases after turbine trip, Figure 29, and the PORV valve opens on both intact and broken SG. 

The first operator action consists of the isolation (closing of the main steam isolation valve of the 

broken SG) and the cooldown (1st cooldown) followed by the depressurization with 3 minutes 

delay each. In order to perform the RCS cooldown the operator adjusts the SG 2 PORV setpoint 

pressure to the value that would result in the cooldown to the target core exit temperature. As 

for the previously analyzed case, the target core exit temperature is determined as a saturation 

temperature corresponding to the broken SG pressure at a time of the begin of the cooldown 

taking into account the subcooling measurement uncertainty (here for normal containment 

conditions) and an additional subcooling uncertainty (11.11 °C). The resulting SG 2 PORV mass 

flow rate is five times less than the steam dump flow (2 steam dump valves) in the CASE 1, 

Figure 41, Figure 15, even with fully open SG PORV valve, Figure 40. The secondary pressure 

of both SGs that were coupled via steam header before the isolation of the damaged SG, Figure 

29, decouple after SG 1 isolation. However, the effect of the decoupling becomes significant first 

after start of the first cooldown when the pressure of the intact SG decreases at a fast rate and 

the broken SG pressure slowly decreases. Due to lower capacity of one SG PORV than the 

steam dump flow in the CASE 1, the cooldown to the target core exit temperature lasted 

significantly longer (about 12 minutes in the CASE 2 vs. 2 minutes in the CASE 1). The RCS 

pressure decreased during cooldown due to outsurge from the pressurizer. However, as soon 

as the cooldown had been finished the RCS pressure rises again due to persisting SI flow. 

Three minutes after finishing the cooldown, the operator starts the RCS depressurization using 

the pressurizer PORV, Figure 44 and Figure 45. Due to the loss of forced primary flow, the 

pressure difference between the cold leg and pressurizer spray nozzle is very low and the 

pressurizer spray flow is negligible despite of fully open pressurizer spray valve. During the 

depressurization the operator monitors the pressurizer level and closes the pressurizer PORV 

when the pressurizer level exceeds 80% in order to prevent the pressurizer liquid solid 

condition, Figure 28, Figure 44 and Figure 45. The RCS pressure started to rise again due to SI 
30

flow. Finally, at time=2266 s, the operator has terminated SI with the required conditions fulfilled 

(RCS subcooling>19°C, PRZR level>15% and intact SG level>20%). After SI termination the 

primary pressure decreases and approaches the broken SG pressure. The break flow reverses, 

Figure 26, and the secondary-to-primary flow is established, thus decreasing the broken SG 

mass, Figure 37, whereas the RCS mass is subsequently increased. If primary-to-secondary 

leakage was not stopped in a due time, the broken SG fills up with liquid, Figure 47 and Figure 

48. Similarly to the previously analyzed case the safety injection flow has been identified to have 

the major effect on filling the broken SG with the liquid and the subsequent liquid discharge. 

Consequently, the time of the operator actions that prepare the plant for the SI termination was 

selected as a major criteria for sensitivity analysis. The comparison of the results for the cases 

with and without liquid discharge (Parameter is the time of the first operator action.) are shown 

in Figure 47 through Figure 51. The results are summarized below: 

CASE 2a (15 minutes), max. SG dome volume liquid fraction=47%, discharged mass=4558 kg 

of steam 

CASE 2b (20 minutes), max. SG dome volume liquid fraction=96.8%, discharged mass=6084 kg 

of steam 

CASE 2c (25 minutes), broken SG liquid solid, discharged mass=7811 kg of steam-liquid 

mixture. 

Similarly to the CASE 1, the analyses have shown that the primary-to-secondary leakage as 

well as discharge through the broken SG (either steam or both steam and liquid) are 

successfully stopped about half an hour after SI termination, Table 4 and Figure 49. 

A half an hour after terminating the SI flow, the operator starts the final cooldown & 

depressurization to hot shutdown conditions. Also, the normal CVCS is actuated, Figure 46. The 

begin of 2nd cooldown & depressurization has no influence on discharge through the broken SG 

PORV, since the discharge finishes before 2nd cooldown, Table 4, Figure 49. During 2nd

cooldown the operator adjusts the intact SG PORV valve opening in order to perform the 

cooldown at maximum possible rate, Figure 40. However, due to decreasing difference between 

the SG 2 and atmospheric pressure, the SG 2 PORV flow is very low when compared with the 

steam dump flow in the CASE 1. Consequently, the low RCS cooldown rate, Figure 32, was 

obtained (approximately 5.7 °C/hour) and the cooldown to hot shutdown conditions lasted for 

about 14 hours that is much longer than the cooldown for the CASE 1 (1 hour and 40 minutes). 

Along with the RCS cooldown, the pressurizer pressure was reduced from 8 MPa to 1.9 MPa. In 

order to prevent the loss of RCS subcooling, the pressurizer pressure setpoint was adjusted to 

follow the actual cooldown rate, Figure 29 and Figure 50. Pressurizer PORV operation was 

determined by the pressurizer pressure setpoint and by the pressurizer level not greater than 

80% in order to prevent pressurizer liquid solid condition, Figure 28. Due to loss of forced RCS 

flow after reactor trip, the temperature difference between the hot and cold leg is much higher 

(not less than 20 o

C), Figure 32, throughout the transient when compared with the CASE 1. 

Whereas in the intact loop a low positive flow was established and almost constant temperature 

difference between the hot and cold leg was maintained, in the broken loop the fluid was almost 

stagnant, Figure 27 and the temperatures were greatly influenced by the break flow. During the 

SI injection the cold leg temperature in the broken loop is also affected by the injection of the 

cold SI flow and stagnant conditions due to break. In the period of the intensive back flow from 

the secondary to primary side that lasted until approx. 14100 s, the cold leg temperature in the 

broken loop was dominantly influenced by the incoming secondary flow and it was greater than 

the hot leg temperature. First after secondary to primary flow was terminated, the fluid in the 
31

broken SG moved from the hot to the cold leg thus reversing the hot to cold leg temperature 

difference. During the cooldown and depressurization the SG level in the broken SG fell below 

50% and the AFW flow was actuated. The condensation on the cold AFW water causes the 

broken SG pressure decrease which on the other side causes the primary-to-secondary 

leakage. Due to ON/OFF opening of the AFW flow in the broken SG, Figure 38, that controls the 

broken SG level in the range (50%, 60%) the periodic oscillations of the break flow results. This 

causes further oscillation behaviour for a number of parameters, e.g., RCS and broken SG 

pressure and mass as well as the RCS temperature in the broken loop, Figure 34. On the other 

side, the periodic ON/OFF operation of the AFW flow in the intact loop causes the temperature 

oscillations in that loop only due to oscillations of the transferred heat. The heat transferred in 

the broken loop is negligible throughout the transient due to the fact that the broken SG is 

isolated as well as due to the stagnant flow conditions on its primary side. The maximum 

average temperature (out of two loops) was monitored as criteria for ending the cooldown to 

HSD conditions (177 °C). Finally, the successful cooldown & depressurization to hot shutdown 

conditions was performed with RCS subcooling larger than the limiting value (19 °C), Figure 50 

and pressurizer level within the acceptable range (20%-80%), Figure 51. One hour after the 

HSD conditions had been achieved the operator has turned ON the PRZ proportional heaters in 

order to prevent the primary pressure decrease below 1.8 MPa as well as the loss of RCS 

subcooling, Figure 35. Thereby, the pressurizer pressure stabilizes, which on the other 

side instigates the primary to secondary leakage, Figure 37. This urges the operator to switch to 

RHR operation and initiate the cooldown to cold shutdown conditions. 
32

Table 4 Time table of main events for NEK SGTR CASE 2 analysis; parameter: begin of 

first operator action 

Event CASE 2a 

(15 min) 

CASE 2b 

(20 min) 

CASE 2c 

(25 min) 

Transient start 0 s 0 s 0 s 

Reactor trip (OT∆T trip, loop 2) 162.2 s 162.2 s 162.2 s 

Turbine trip (on reactor trip) 162.2 s 162.2 s 162.2 s 

RCP trip (1 sec delay) 163.2 s 163.2 s 163.2 s 

Main FW isolation (on low RCS 

average temperature & reactor 

trip) 

289.2 s 289.2 s 289.2 s 

SI actuation (on low-2 pressurizer 

pressure) 

300.0 s 300.0 s 300.0 s 

1st operator action: MSIV 1 

isolation 

900 s 1200 s 1500 s 

1st cooldown 1080 s 1380 s 1680 s 

Time to achieve target core exit 

temperature during first cooldown

1845 s 

(541.8 K) 

2100 s 

(541.8 K) 

2365 s 

(541.7 K) 

1st RCS depressurization 2025 s 2280 s 2545 s 

Operator turns off SI (180 s 

delay) 

2266 s 2518 s 2782 s 

End of primary-to-secondary 

leakage 

4000 s 4320 s 4585 s 

SG 1 steam dome liquid fraction 

> 10% 

2027 s 2100 s 2115 s 

Max. SG 1 steam dome liquid 

fraction 

47.0% (3970 s) 96.8% (4315 s) 100% (3010 s) 

Liquid discharge - SG 1 PORV 

(voidfj > 0.1) 

- - - 

End of discharge 3945 s 4290 s 4560 s 

Total discharged mass through 

SG 1 PORV 

4558 kg 6084 kg 7811 kg 

2nd cooldown & depressurization 

to HSD; CVCS enabled, operator 

isolates accumulators 

4066 s 4318 s 4582 s 

HSD conditions achieved, 

cooldown rate 

54350 s 

(5.7 °C/hour) 

55530 s 

(5.7 °C/hour) 

56000 s 

(5.7 °C/hour) 
33

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

M ass f low ( k g/s)

-4

-2

0

2

4

6

8

10

12

14

Break side 1 

Break side 2 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 26 CASE 2a analysis: Break mass flow rate 

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

M ass f low ( k g/s)

0

500

1000

1500

2000

2500

3000

3500

4000

4500

Loop 1 

Loop 2 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 27 CASE 2a analysis: RCS mass flow rate 
34

Volume (m3)

0 2 4 6 8 10 12 14 16 18

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

Level (% )

0 10 20 30 40 50 60 70 80

PRZ level 

PRZ liquid volume 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 28 CASE 2a analysis: Pressurizer NR level and liquid volume 

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

Pressure (M Pa)

2 4 6 8 10 12 14

PRZ 

SG 1 

SG 2 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 29 CASE 2a analysis: Pressurizer and SG pressure 
35

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

N uclear pow er (M W )

0

200

400

600

800

1000

1200

1400

1600

1800 RKTPOW 0 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 30 CASE 2a analysis: Nuclear power 

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

Pow er (M W )

-20 0 20 40 60 80 100 120 140 160 180 200

Reactor core 

SG 1 

SG 2 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 31 CASE 2a analysis: Reactor core and SG power 
36

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

T emperature (K )

440 460 480 500 520 540 560 580

Cold leg 1 

Cold leg 2 

Hot leg 1 

Hot leg 2 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 32 CASE 2a analysis: RCS temperature 

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

T emperature (K )

440 460 480 500 520 540 560 580

Loop 1 

Loop 2 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 33 CASE 2a analysis: RCS average temperature 
37

M ass f low ( k g/s)

0 5 10 15 20 25

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

T emperature (K )

440 460 480 500 520 540 560 580

Cold leg 1 temperature 

Hot leg 1 temperature 

AFW 1 flow 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 34 CASE 2a analysis: Loop 1 temperature and SG 1 auxiliary feedwater flow Pow er (kW ) 0 20 40 60 80 100 120 140 160 180 200 220 Subcooling (C) 20 25 30 35 40 45 50 55 60 65

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

Level (% )

0 10 20 30 40 50 60 70 80

PRZ level 

RCS subcooling 

PRZ heaters power 

N EK SGTR CY C 26 BOL, CASE 2a

 Figure 35 CASE 2a analysis: RCS subcooling, pressurizer level 

 and pressurizer heaters power 
38

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

M ass flow (kg/s)

0

5

10

15

20

25

30

35

40

45

CNTRLVAR 757 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 36 CASE 2a analysis: Safety injection flow 

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

M ass ( t)

50 60 70 80 90 100 110 120 130 140 150

RCS 

SG 1 

SG 2 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 37 CASE 2a analysis: RCS and SG mass 
39

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

M ass f low ( k g/s)

0 50 100 150 200 250 300 350 400 450 500

MFW 1 

MFW 2 

AFW 1 

AFW 2 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 38 CASE 2a analysis: Main and auxiliary FW mass flow rate 

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000

T im e ( s)

M ass f low ( k g/s)

0 50 100 150 200 250 300 350 400 450 500

MFW 1 

MFW 2 

AFW 1 

AFW 2 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 39 CASE 2a analysis: Main and auxiliary FW mass flow rate, time (0-20000 s) 
40

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

Valve opening (-)

0

.1

.2

.3

.4

.5

.6

.7

.8

.9

1

CNTRLVAR 1827 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 40 CASE 2a analysis: SG 2 PORV opening 

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

M ass f low ( k g/s)

-10 -5 0 5 10 15 20 25 30 35 40 45 50

SG 1 

SG 2 

SG 2 PORV 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 41 CASE 2a analysis: Main steam and SG 2 PORV mass flow rate 
41

M ass ( t)

0 50 100 150 200 250 300 350 400

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

Pressure (M Pa)

12345678

SG 1 pressure 

SG 2 pressure 

SG 2 PORV mass 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 42 CASE 2a analysis: SG pressure, integrated flow through SG PORV 

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

Level (% )

30 40 50 60 70 80 90 100

SG 1 

SG 2 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 43 CASE 2a analysis: SG NR level 
42

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

M ass f low ( k g/s)

0 2 4 6 8 10 12 14 16 18 20 22

PRZ PORV 1 

PRZ spray 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 44 CASE 2a analysis: Pressurizer PORV 1 and spray mass flow rate 

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

M ass (kg)

0

200

400

600

800

1000

1200

1400

1600

1800

2000

2200

CNTRLVAR 835 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 45 CASE 2a analysis: Integral of pressurizer PORV 1 mass flow rate 
43

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

M ass f low ( k g/s)

0 2 4 6 8 10 12 14

Charging 

Pump seal 1 

Pump seal 2 

Letdown 

N EK SGTR CY C 26 BOL, CASE 2a

Figure 46 CASE 2a analysis: CVCS mass flow rate 

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

M ass ( t)

50

55

60

65

70

75

80

85

90

95

100

105

110

CASE 2a 

CASE 2b 

CASE 2c 

N EK SGTR CY C 26 BOL, CASE 2

Figure 47 CASE 2 analysis: Mass of broken SG (SG 1) 
44

0 5000 10000 15000 20000 25000 30000

T im e ( s)

Liquid fraction (-)

0 .10 .20 .30 .40 .50 .60 .70 .80 .90

CASE 2a 

CASE 2b 

CASE 2c 

N EK SGT R CY C 26 BOL, CASE 2

Figure 48 CASE 2 analysis: Broken SG (SG 1) steam dome volume liquid fraction Liquid fraction (-)

0 .05 .10 .15 .20 .25 .30

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

M ass (kg)

0 1000 2000 3000 4000 5000 6000 7000

Disch. mass,CASE 2a 

Disch. mass,CASE 2b 

Disch. mass,CASE 2c 

Liq. fraction,CASE 2a 

Liq. fraction,CASE 2b 

Liq. fraction,CASE 2c 

N EK SGT R CY C 26 BOL, CASE 2

Figure 49 CASE 2 analysis: Discharged mass through broken SG 

 (SG 1) PORV, broken SG PORV liquid fraction 
45

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

Subcooling (C)

20 25 30 35 40 45 50 55 60 65

CASE 2a 

CASE 2b 

CASE 2c 

N EK SGTR CY C 26 BOL, CASE 2

Figure 50 CASE 2 analysis: RCS subcooling 

0 5000 10000 15000 20000 25000 30000 35000 40000 45000 50000 55000 60000

T im e ( s)

Level (% )

0 10 20 30 40 50 60 70 80

CASE 2a 

CASE 2b 

CASE 2c 

N EK SGTR CY C 26 BOL, CASE 2

Figure 51 CASE 2 analysis: Pressurizer level 
46

4.3 Discussion of differences between CASE 1 and CASE 2 analysis 

Here, the major differences between the CASE 1 and CASE 2 will be discussed. The 

comparison between the two cases is presented in Table 5 and Figure 52 to Figure 59. In 

general, an earlier operator action is required for the CASE 2 than for the CASE 1 to both stop 

the steam discharge and to prevent the broken SG liquid solid condition. However, the analyses 

have shown that for the CASE 1 the larger amount of inventory was discharged through the 

broken SG than for the CASE 2 (e.g., 4972 kg and 4558 kg for 15 minutes and 7307 kg and 

6084 kg for 20 minutes, respectively). On the other side, after the first operator action discharge 

was stopped earlier for the CASE 1 than for the CASE 2. In general, a more efficient heat 

transfer from primary to secondary side in the CASE 1 due to forced RCS flow causes higher 

secondary pressure in the broken SG than for the CASE 2, Figure 53, Figure 57 and Figure 59. 

Therefore, for the same delay for the first operator action the higher amount of discharged 

inventory was obtained for the CASE 1 than for the CASE 2. The difference for the transferred 

heat between the two cases has been increased at a time of the start of the cooldown. The 

steam dump valves (CASE 1) have significantly higher capacity than one SG 2 PORV valve 

(CASE 2), Figure 52. Immediately after start of the 1st cooldown the heat removed by the intact 

SG in the CASE 1 increases rapidly, Figure 52 and Figure 53. The RCS temperature decreases, 

Figure 54 and Figure 55 and the pressurizer outsurge flow increases due to coolant shrinkage, 

Figure 56. Consequently, the primary pressure decreases thus resulting in the reduction of the 

break flow as well, Figure 57. On the contrary, for the CASE 2 the transferred heat in the intact 

SG is much lower than in the CASE 1. The primary pressure decreased only slightly following 

the first cooldown. The break flow remains relatively high and the broken SG fills with liquid. 

First after the RCS depressurization (at 2025 s for the CASE 2a and at 2280 s for the CASE 2b) 

the primary pressure and the break flow are reduced. The high break flow together with the less 

amount of the discharged steam in the CASE 2 than in the CASE 1 lead to the faster 

accumulation of the liquid in the former case. The same trend is illustrated in Figure 59 where 

the CASE 1c (45 minutes for the operator action) and the CASE 2c (25 minutes) are compared. 

In the CASE 1c the broken SG has not become liquid solid but the amount of the discharged 

inventory is significantly larger (13952 kg vs. 7811 kg) than for the CASE 2 (broken SG liquid 

solid). The more efficient heat transfer from primary to the secondary side has also resulted in 

an earlier end of the discharge after first operator action in the CASE 1 (4 minutes and half an 

hour for the CASE 1 vs. 50 and 51 minutes for the CASE 2, Table 5 and Figure 58). Due to very 

intensive heat removal and RCS cooldown in the CASE 1 the broken SG pressure decreases 

below the SG PORV setpoint and the discharge is thus quickly stopped. Contrary to the CASE 1 

in the CASE 2 the broken SG remains unaffected by the RCS cooldown primarily due to 

stagnant RCS flow conditions. The broken SG pressure decreases slowly and the discharge 

lasts longer than in the CASE 1. 
47

Table 5 NEK SGTR analysis; comparison of CASE 1 and CASE 2 analysis 

Event CASE 1a 

(15 min) 

CASE 2a 

(15 min) 

CASE 1b 

(20 min) 

CASE 2b 

(20 min) 

1st cooldown 1080 s 1080 s 1380 s 1380 s 

1st RCS depressurization 1394 s 2025 s 1691 s 2280 s 

End of primary-to-secondary 

leakage 

2950 s 4000 s 3334 s 4320 s 

SG 1 steam dome liquid fraction 

> 10% 

- 2027 s - 2100 s 

Max. SG 1 steam dome liquid 

fraction 

0.02% 47.0% 0.02% 96.8% 

Liquid discharge - SG 1 PORV 

(voidfj > 0.1) 

- - - - 

End of discharge 1140 s 3945 s 2960 s 4290 s 

Total discharged mass through 

SG 1 PORV 

4972 kg 4558 kg 7307 kg 6084 kg 

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000

T im e ( s)

M ass f low ( k g/s)

0

20

40

60

80

100

120

140

160

180

200

220

240

Steam dump-CASE 1 

SG 2 PORV-CASE 2 

N E K SG T R C Y C 26 B O L , 20 m inutes for operator action

Figure 52 CASE 1 vs. CASE 2: 20 min for operator action: Steam dump (CASE 1) and 

SG 2 PORV mass flow rate (CASE 2) 
48

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000

T im e ( s)

Pow er (M W )

0

100

200

300

400

500

600

700

800

900

1000

SG 1-CASE 1 

SG 2-CASE 1 

SG 1-CASE 2 

SG 2-CASE 2 

N E K SG T R C Y C 26 B O L , 20 m inutes for operator action

Figure 53 CASE 1 vs. CASE 2: 20 min for operator action: SG power 

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000

T im e ( s)

T emperature (K )

440

460

480

500

520

540

560

580 Tcl 1-CASE 1 

Thl 1-CASE 1 

Tcl 1-CASE 2 

Thl 1-CASE 2 

N E K SG T R C Y C 26 B O L , 20 m inutes for operator action

Figure 54 CASE 1 vs. CASE 2: 20 min for operator action: Loop 1 temperature 
49

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000

T im e ( s)

T emperature (K )

500

510

520

530

540

550

560

570

580

590

600

Tcl 2-CASE 1 

Thl 2-CASE 1 

Tcl 2-CASE 2 

Thl 2-CASE 2 

N E K SG T R C Y C 26 B O L , 20 m inutes for operator action

Figure 55 CASE 1 vs. CASE 2: 20 min for operator action: Loop 2 temperature 

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000

T im e ( s)

Volume (m3)

0

2

4

6

8

10

12

14

16

18

CASE 1 

CASE 2 

N E K SG T R C Y C 26 B O L , 20 m inutes for operator action

Figure 56 CASE 1 vs. CASE 2: 20 min for operator action: Pressurizer liquid volume 
50

Break mass flow (kg/s)

-4 -2 0 2 4 6 8 10 12 14

SG 1 pressure (M Pa)

6 6.2 6.4 6.6 6.8 7 7.2 7.4 7.6 7.8 8 8.2 8.4

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000

T im e ( s)

Pressurizer pressure (M Pa)

2 4 6 8 10 12 14

PRZ pressure-CASE 1 

PRZ pressure-CASE 2 

SG1 pressure-CASE 1 

SG1 pressure-CASE 2 

Break flow-CASE 1 

Break flow-CASE 2 

N E K SG T R C Y C 26 B O L , 20 m inutes for operator action

Figure 57 CASE 1 vs. CASE 2: 20 min for operator action: Pressurizer pressure, SG 1 

pressure and break (side 1) mass flow rate 

M ass (k g)

0 1000 2000 3000 4000 5000 6000 7000

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000

T im e ( s)

Pressure (M Pa)

6 6.2 6.4 6.6 6.8 7 7.2 7.4 7.6 7.8 8 8.2 8.4

SG1 press.-CASE 1 

SG1 press.-CASE 2 

Disc.mass-CASE 1 

Disc.mass-CASE 2 

N E K SG T R C Y C 26 B O L , 20 m inutes for operator action

Figure 58 CASE 1 vs. CASE 2: 20 min for operator action: SG 1 pressure and 

discharged mass through SG 1 PORV 
51

M ass (kg)

50000 60000 70000 80000 90000 100000 110000

D ischarged mass (kg)

0 2000 4000 6000 8000 10000 12000

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000

T im e ( s)

SG 1 pressure (M Pa)

6 6.2 6.4 6.6 6.8 7 7.2 7.4 7.6 7.8 8 8.2 8.4

SG 1 pressure-1c 

SG 1 pressure-2c 

Disch. mass-1c 

Disch. mass-2c 

SG 1 mass-1c 

SG 1 mass-2c 

N E K SG T R C Y C 2 6 B O L , C A SE 1c vs. 2c

Figure 59 CASE 1c (45 min for operator action) vs. CASE 2c (25 min for operator action): 

SG 1 pressure, discharged mass through SG 1 PORV and SG 1 mass 

53

5. CONCLUSIONS 

The results of SGTR analysis for NPP Krško are presented. The guidelines from the NPP Krško 

EOP procedures for recovery following the SGTR event were applied for the modelling of 

operator actions. The analyses were primarily performed to demonstrate the capability of the 

plant systems as well as adequacy of operator actions to prevent the discharge of the 

contaminated inventory to the environment. Also the plant conditions during cooldown & 

depressurization to hot shutdown conditions were monitored to ensure the safe operation, i.e., 

the adequate RCS subcooling margin, pressurizer level and intact SG inventory for heat 

removal. The performed analyses did not include the radiological consequences calculation, but 

based on the limited amount of the mass of the discharged fluid, they should be small. Following 

conclusions can be drawn from the presented analyzed cases: 

1. The analyses have been performed for different times for the operator action aimed to 

stop the primary-to-secondary leakage and the subsequent discharge of the contaminated 

inventory to the environment. The operator actions are primarily aimed to isolate the broken SG 

and to terminate the safety injection that has the major influence on filling the ruptured SG with 

liquid. The SI can be terminated first after successfully finishing the first cooldown & 

depressurization initiated by the operator. 

2. The analyses have shown that an earlier operator action is required in the case without 

offsite power (CASE 2) than in the case with offsite power available (CASE 1) to both stop the 

steam discharge and to prevent the broken SG liquid solid condition. On the other side, for the 

same delay for the first operator action the total amount of the discharged inventory is larger in 

the CASE 1 than in the CASE 2. The differences in the heat transferred in both the broken and 

intact SG are responsible for the different transient outcome for the two cases. Due to better 

heat transfer in the broken SG, the higher broken SG pressure and the higher amount of the 

discharged inventory were obtained for the CASE 1 than for the CASE 2. On the other side, the 

more efficient cooldown in the CASE 1 when compared with the CASE 2 has two important 

consequences, i.e., an earlier stop of the break flow and an earlier stop of the discharge through 

the broken SG PORV. 

3. Discharge through the broken SG PORV can be stopped immediately if the first 

operator action is initiated not later than 15 minutes after transient begin for the CASE 1 and the 

small amount of steam is discharged for 20 minutes. In order to prevent liquid discharge the first 

operator action must be initiated not later than 45 minutes for the CASE 1 and not later than 20 

minutes for the CASE 2, respectively. In all the analyzed cases (also with liquid discharge) the 

operator can successfully stop the primary-to-secondary leakage and the discharge through the 

broken SG PORV. 

The complete RCS cooldown & depressurization to hot shutdown conditions has been 

performed for all the analyzed scenarios. The procedure lasted about 1 hour and 40 minutes for 

the CASE 1 (steam dump available) with the cooldown rate equal to around 53.4°C/hour that is 

close to the maximum allowed (55.6 °C/hour). In the CASE 2 due to low capacity of one SG 

PORV, the cooldown lasted very long (14 hours) with the cooldown rate equal to around 

5.7°C/hour. 

55 

6. REFERENCES 

1. Benčik, V., Grgić, D., Čavlina, N., Analysis of Steam Generator Tube Rupture (SGTR) 

Accident for NPP Krško, Proceedings of the International Conference Nuclear Energy for 

New Europe 2012, September 5-7 2012, Ljubljana, Slovenia. 

2. RELAP5/MOD3.3 Users Manual, The RELAP5 Code Development Team, NUREG/CR5535/Rev 1, Information Systems Laboratories, Inc., Rockville - Maryland, Idaho Falls - 

Idaho, January 2002. 

3. NEK RELAP5/MOD3.3 Post-RTDBE Nodalization Notebook, NEK ESD TR 02/13, 

Revision 0, Krško 2013. 

4. NEK RELAP5/MOD3.3 Post-RTDBE Steady State Qualification Report, NEK ESD-TR03/13, Revision 0, Krško 2013. 

5. Decrease in Reactor Coolant Inventory, SSR-NEK-7.6, Revision 2, WEC, April 2000 

6. Precautions, Limitations and Setpoints for Nuclear Steam Supply System (2000 MWt 

Rating), Revision 26, Krško, May 2012. 

7. NEK Emergency Operating Procedure (EOP) E-3, Steam Generator Tube Rupture, NPP 

Krško. 




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RELAP5/MOD 3.3 Analysis of Steam Generator 

Rupture (SGTR) Accident for NPP Krško