NUREG/IA-0221 

 International 

 Agreement Report

 

Reactor Trip Analysis at Krško Nuclear 

Power Plant 

Prepared by: 

A. Prošek, B. Mavko 

Jožef Stefan Institute 

Jamova cesta 39 

SI-1000 Ljubljana, Slovenia 

A. Calvo, NRC Project Manager 

Office of Nuclear Regulatory Research 

U.S. Nuclear Regulatory Commission 

Washington, DC 20555-0001 

February 2010 

 

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-0221

Reactor Trip Analysis at Krško Nuclear 

Power Plant 

Manuscript Completed: July 2007 

Date Published: January 2010 

Prepared by: Andrej Prošek, Borut Mavko 

Jožef Stefan Institute 

Jamova cesta 39 

SI-1000 Ljubljana, Slovenia 

A. Calvo, NRC Project Manager 

Prepared as part of 

The Agreement on Research Participation and Technical Exchange 

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

Division 

Office 

U.S. Nuclear Regulatory Commission 

Washington, DC 20555-0001

iii 

ABSTRACT 

The reactor trip, which occurred at the Krško Nuclear Power Plant (NPP), on April 10, 2005, has 

been analyzed with the RELAP5/MOD3.3 Patch 03 computer code, the most current version 

released. The analysis was performed by the Jožef Stefan Institute, Reactor Engineering 

Division. The RELAP5 input model delivered by the Krško NPP was used. The purpose of the 

analysis was to evaluate the RELAP5 computer code against plant-measured data and validate 

the RELAP5 input model for the Krško NPP, which is a two-loop Westinghouse pressurizedwater reactor. The event analyzed was a malfunction, which occurred during a power reduction 

sequence when regular, periodic testing of the turbine valves was performed. The malfunction 

led to a plant trip. All of the plant’s safety systems responded according to the design 

specification, so the event caused no hazard to the environment or the plant staff and did not 

challenge the plant’s safety. The RELAP5/MOD3.3 Patch 03 calculations agree very well with 

the plant-measured data, when operator actions are modeled properly. The analysis found that 

the long-term transient evolution is very sensitive to the steamflow after reactor trip. However, 

the calculation showed that the measured steamflow was larger than the calculated steam 

generated by available decay heat and therefore measurement of steamflow after reactor trip 

was not reliable. Therefore, the steamflow was tuned to obtain as good a match to the 

measured SG pressure as possible. The value of steamflow was physically reasonable but it is 

not known if this value reflects the reality of the transient. 

v 

CONTENTS

Page

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

ACKNOWLEDGEMENT AND ABBREVIATIONS....................................................... viii

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

2. PLANT DESCRIPTION.............................................................................................. 3

3. INPUT MODEL DESCRIPTION................................................................................. 5

3.1 Hydrodynamic Component Description.............................................................................5

3.2 Regulation and Protection Logic .......................................................................................8

4. ABNORMAL EVENT DESCRIPTION........................................................................ 9

5. RESULTS ................................................................................................................ 11

5.1 Part 1 of the Analysis—Testing of the Turbine Governor Valve......................................11

5.2 Part 2 of the Analysis—Turbine Governor Valve Closure with Reactor Trip ...................26

6. RUN STATISTICS ................................................................................................... 53

7. CONCLUSIONS ...................................................................................................... 55

8. REFERENCES ........................................................................................................ 57
vi 

Figures

Page

1. Krško NPP nodalization scheme..............................................................................................7

2. Core power—testing of turbine governor valve ......................................................................16

3. Rod position—testing of turbine governor valve.....................................................................16

4. Turbine flow—testing of turbine governor valve.....................................................................17

5. Turbine power—testing of turbine governor valve..................................................................17

6. Cold leg loop 1 temperature—testing of turbine governor valve ............................................18

7. Cold leg loop 2 temperature—testing of turbine governor valve ............................................18

8. Hot leg loop 1 temperature—testing of turbine governor valve ..............................................19

9. Hot leg loop 2 temperature—testing of turbine governor valve ..............................................19

10. RCS average temperature—testing of turbine governor valve .............................................20

11. Reference (programmed) temperature—testing of turbine governor valve...........................20

12. PRZ pressure—testing of turbine governor valve .................................................................21

13. PRZ level—testing of turbine governor valve........................................................................21

14. Charging flow—testing of turbine governor valve .................................................................22

15. Letdown flow—testing of turbine governor valve ..................................................................22

16. SG 1 pressure—testing of turbine governor valve ................................................................23

17. SG 2 pressure—testing of turbine governor valve ................................................................23

18. Steamflow SG 1—testing of turbine governor valve .............................................................24

19. Steamflow SG 2—testing of turbine governor valve .............................................................24

20. Feedwater flow SG 1—testing of turbine governor valve......................................................25

21. Feedwater flow SG 2—testing of turbine governor valve......................................................25

22. Core power—turbine governor valve closure with reactor trip ..............................................30

23. Cold leg loop 1 temperature—turbine governor valve closure with reactor trip ....................31

24. Cold leg loop 2 temperature—turbine governor valve closure with reactor trip ....................32

25. Hot leg loop 1 temperature—turbine governor valve closure with reactor trip ......................33

26. Hot leg loop 2 temperature—turbine governor valve closure with reactor trip ......................34

27. RCS average temperature—turbine governor valve closure with reactor trip.......................35

28. Reference temperature—turbine governor valve closure with reactor trip............................36

29. PRZ pressure—turbine governor valve closure with reactor trip...........................................37

30. PRZ level—turbine governor valve closure with reactor trip .................................................38

31. Charging flow—turbine governor valve closure with reactor trip...........................................39

32. Letdown flow—turbine governor valve closure with reactor trip............................................40

33. SG 1 pressure—turbine governor valve closure with reactor trip..........................................41

34. SG 2 pressure—turbine governor valve closure with reactor trip..........................................42

35. SG 1 narrow range level—turbine governor valve closure with reactor trip ..........................43

36. SG 2 narrow range level—turbine governor valve closure with reactor trip ..........................44

37. Steamflow SG 1—turbine governor valve closure with reactor trip.......................................45

38. Steamflow SG 2—turbine governor valve closure with reactor trip.......................................46

39. Feedwater flow SG 1—turbine governor valve closure with reactor trip ...............................47

40. Feedwater flow SG 2—turbine governor valve closure with reactor trip ...............................48

41. SI 1 volumetric flow—turbine governor valve closure with reactor trip..................................49

42. SI 2 volumetric flow—turbine governor valve closure with reactor trip..................................50

43. AFW 1 volumetric flow—turbine governor valve closure with reactor trip .............................51

44. AFW 2 volumetric flow—turbine governor valve closure with reactor trip .............................52
vii 

Tables

Page

1. Phases of the Analysis...........................................................................................................11

2. Initial Conditions for Reactor Trip Transient...........................................................................13

3. Variables Identification in Figures ..........................................................................................15

4. Time Sequence of Main Events during Transient ..................................................................26

5. Run Statistics .........................................................................................................................53
viii 

ACKNOWLEDGEMENT 

The RELAP5/MOD3.3 Krško Nuclear Power Plant base input model and nodalization diagram 

are courtesy of the Krško Nuclear Power Plant. 
ix 

ABBREVIATIONS 

AFW auxiliary feedwater 

CVCS chemical and volume control system 

ECCS emergency core cooling system 

HPIS high-pressure injection system 

K Kelvin 

kg/s kilogram per second 

MFW main feedwater 

MPa megapascal 

MSIV main steam isolation valve 

MWt megawatt thermal 

NPP nuclear power plant 

NSSS nuclear steam supply system 

PORV power-operated relief valve 

PRZ pressurizer 

PWR pressurized-water reactor 

RCS reactor coolant system 

s second 

SI safety injection 

SG steam generator 

1 

1. INTRODUCTION

This report presents the analysis of an abnormal event that occurred at the Krško Nuclear 

Power Plant (NPP) on April 10, 2005. The purpose of the analysis, performed by Jožef Stefan 

Institute, Reactor Engineering Division, was to evaluate the RELAP5/MOD3.3 Patch 03 

computer code (Ref. 1) against plant-measured data and validate the input model for the Krško 

NPP, which is a two-loop Westinghouse pressurized-water reactor (PWR). The analysis used 

the RELAP5 input model delivered by Krško NPP. This is a full two-loop plant model, which 

includes the major components of the primary and secondary system. The model delivered by 

Krško NPP had two limitations: (1) the secondary side was only modeled up to the turbine and 

(2) auxiliary systems consuming steam after a transient were not included. These limitations are 

significant because steamflow is very important to the behavior of the secondary pressure in 

terms of its influence on the primary pressure. Both pressures dictate the operation of the 

control and safety systems. The analysis was performed for uprated power conditions (2,000 

megawatt thermal (MWt)) (6,824·106

 Btu/hr) with new steam generators (SGs) and Cycle 21 

settings, which corresponded to the plant state after outage and refueling in September 2004. 

A malfunction occurred during a power reduction sequence when regular, periodic testing of the 

turbine valves was performed. This malfunction led to a plant trip. All of the plant’s safety 

systems responded according to the design specification, so the event caused no hazard to the 

environment or plant staff and did not challenge the plant safety. The scope of the analysis was 

to evaluate the transient and to compare the measured data to the calculations, as well as to 

simulate the testing of the governor valves, which involved a power reduction from 100 percent 

to below 92 percent. 

The analysis was divided into five phases. The first phase demonstrated the steady-state 

condition at 100-percent power. In the second phase, the power was reduced from 100 percent 

to 91.72 percent. The third phase simulated one cycle of the turbine governor valve closing and 

opening in order to recreate, as closely as possible, the initial conditions of the transient. In 

Phase 4, the steady state at a power level of 91.72 percent was verified by comparing 

calculated initial conditions with plant data, which were available for 53 seconds before the 

transient started. Finally, in the last phase, the transient was analyzed using data collected for a 

period of 1,825 seconds after the transient began. Measurement data beyond this timeframe 

were not available. 

Section 2 briefly describes the Krško NPP, and Section 3 describes the RELAP5 input model. 

Section 4 details the modeled scenario. Section 5 presents the results of the analysis, and 

compares the RELAP5 data to the plant-measured data. Section 6 summarizes the run 

statistics, and Section 7 provides the conclusions of the analysis. 

3 

2. PLANT DESCRIPTION 

The Krško NPP is a Westinghouse 2-loop PWR plant with a large dry containment. The plant 

has been in commercial operation since 1983. After the plant was modernized in 2000, the plant 

fuel cycle was gradually lengthened from 12 (Cycle 17) to 18 months (Cycle 21). 

The Krško NPP nuclear steam supply system (NSSS) has a power rating of 2,000 MWt 

(6,824·106

 Btu/hr) (1,882 MWt (6,422·106 Btu/hr) before modernization and power uprate), 

comprising a core output of 1,994 MWt (6,804·106

 Btu/hr) (1,876 MWT (6,401·106 Btu/hr)) 

before modernization and power uprate) plus a reactor coolant pump heat input of 6 MWt 

(205·106

 Btu/hr). The NSSS consists of a PWR, reactor coolant system (RCS), and associated 

auxiliary fluid systems. The RCS is arranged as two closed reactor coolant loops connected in 

parallel to the reactor vessel, each containing a reactor coolant pump and an SG. An electrically 

heated pressurizer (PRZ) is connected to one of the loops. 

The reactor core is composed of 121 fuel assemblies. Square spacer grid assemblies and the 

upper and lower end fitting assemblies support the fuel rods in fuel assemblies. Each fuel 

assembly is composed of 16 x 16 rods; of these, only 235 places are used by fuel rods. Of the 

21 remaining places, 20 are provided with thimble tubes, which may be reserved for control 

rods. These 20 places are evenly and symmetrically distributed across the cross section of the 

assembly. The last remaining place is provided for the control instrumentation tube for the incore thimble. 

The reactor coolant pumps, one per coolant loop, are Westinghouse vertical, single-stage 

centrifugal pumps of the shaft-seal type. 

The SGs, one per loop, are vertical U-tube unit, Siemens-Framatome type SG 72 W/D4-2 SGs, 

which were installed during the plant modernization in 2000. These SGs replaced the highly 

degraded Westinghouse D-4 SGs, each having preheating section. 

The plant includes the following engineered safety features to prevent accident propagation or 

to limit the consequences of postulated accidents, which might otherwise lead to system 

damage and release of fission products: 

$ containment spray system 

$ hydrogen control system 

$ emergency core cooling system (ECCS) 

$ component cooling water system 

$ essential service water system 

$ auxiliary feedwater (AFW) system 

In 2006, the main turbine was replaced to gain additional power from the new SGs. Note that 

the event took place in 2005; therefore, the model did not reflect the replacement of the main 

turbine. 

5 

3. INPUT MODEL DESCRIPTION

To perform this analysis, the Krško NPP provided the base RELAP5 input model, referred to as 

the “master input deck,” which has been used for several analyses, including reference 

calculations for Krško full-scope simulator verification (Refs. 2, 3, 4). Figure 1 presents the 

scheme of the Krško NPP nodalization for the RELAP5/MOD3.3 code. The analysis used a full 

two-loop plant model provided by Krško NPP. The model includes the new Siemens-Framatome 

type SG 72 W/D4-2 replacement SGs. The analysis was performed for uprated power 

conditions (2,000 MWt (6,824·106

 Btu/hr)) with new SGs and Cycle 21 settings, corresponding 

to the plant state after outage and refueling in September 2004. 

The model consists of 469 control volumes, 497 junctions, and 378 heat structures with 2,107 

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

the instrumentation, regulation isolation, safety injection (SI) and AFW triggering logic, and 

steamline isolation. 

3.1 Hydrodynamic Component Description

Components numbered from 101 to 165 represent the reactor vessel as follows: 

171, 173, and 175 lower downcomer 

101 and 103 lower head 

105 lower plenum 

107 core inlet 

111 reactor core 

115 core baffle bypass 

121 core outlet 

125, 131, and 141 upper plenum 

151 and 153 upper head 

165 upper downcomer 

113 and 145 guide tubes 

Components 51, 53, and 55 represent the PRZ surge line, and volumes 61, 63, 65, 67, and 69 

represent the PRZ vessel. PRZ spray lines (80, 81, and 84) are connected to the top of the PRZ 

vessel and include spray valves 82 and 83. Valves 28 and 32 represent the two PRZ poweroperated relief valves (PORVs), and valves 14 and 22 represent PRZ safety valves. 

The following components represent the primary piping: 

201, 203, 205, 207, 209, and 211 hot leg no.1 

251, 253, 255, 257, and 259 intermediate leg no.1 with cold leg no.1 loop seal 

265, 271, 273, 275, 277, and 279 cold leg no.1 with the primary coolant pump no.1 

301, 303, 305, 307, 309, and 311 hot leg no.2 

351, 353, 355, 357, and 359 intermediate leg no.2 with cold leg no.2 loop seal 

365, 371, 373, 375, 377, and 379 cold leg no.2 with the primary coolant pump no.2 

Loops are symmetrical except for the PRZ surge line and chemical and volume control system 

(CVCS) connections layout. 
6 

The piping nodalization and connections of the ECCS are represented by hydrodynamic 

components numbered from 701 to 882. The hydrodynamic components representing the highpressure injection system (HPIS) pumps are time-dependent junctions 703 and 803, while timedependent junctions 750 and 850 represent the low-pressure injection system pumps. 

Accumulators are numbered 701 and 801; their lineup provides cold-leg injection only. The 

ECCS connects to both cold legs (junctions 719-01 and 819-01). Direct vessel ECCS injection 

through junctions 746 and 748 opens simultaneously upon SI signal generation. 

The primary side of the SG is represented by inlet and outlet plenum, with a single pipe 

representing the U-tube bundle: 

215, 217, and 219 SG 1 inlet plenum (hot side) and tubesheet inlet 

223, 225, 227, 233, 235, and 237 SG 1 U-tubes 

241, 243, and 245 SG 1 tubesheet outlet and outlet plenum (cold side) 

315, 317, and 319 - SG 2 inlet plenum (hot side) and tubesheet inlet 

323, 325, 327, 333, 335, and 337 SG 2 U-tubes 

341, 343, and 345 SG 2 tubesheet outlet and outlet plenum (cold side) 

The following hydrodynamic components represent the parts of the SG secondary side: 

415, 417, and 419 SG 1 riser 

421 and 427 SG 1 separator and separator pool 

411 and 413 SG 1 downcomer 

423, 425, and 429 SG 1 steam dome 

515, 517, and 519 SG 2 riser 

521 and 527 SG 2 separator and separator pool 

511 and 513 SG 2 downcomer 

523, 525, and 529 SG 2 steam dome 

Main steamlines are represented by volumes 451, 453, 455, 457, 459, and 461 (SG 1) and 551, 

553, 555, 557, 559, and 561 (SG 2), divided by main steam isolation valves (MSIVs) (458 and 

558). SG relief (482 and 582) and safety valves (484, 486, 488, 492, 494, 584, 586, 588, 592, 

and 594) are situated upstream of the isolation valves. Turbine valve (604) and steam dump 

(611) flow is regulated by corresponding logic. 

Main feedwater (MFW) piping is represented by volumes 471, 473, 475, 407, 409 (SG 1) and 

571, 573, 575, 507, and 509 (SG 2), branching from the MFW header (500). 

AFW injects above the SG riser (for SG 1 via volumes 437, 443, 445, and 447; for SG 2 via 

volumes 537, 543, 545, and 547) and its piping is represented by volumes 671 and 673 (motordriven AFW 1); 675 and 677 (motor-driven AFW 2); and 681, 683, 685, 687, 695, and 697 

(turbine-driven AFW). 
7 

151

171

121

111 0605

04030201

115

01

020304

05

06

07

08

175

107

105

103

101

69

656361

201 203 205 207

51

209

53

01 02 03 04 05 06 07

11

10

09

08

55

257

01 02 03 04

259

265 271 273 275 277 279

313

379 377 375 373 371 365

359

357

353

355

01 02 03 04

551

553555

557

559

561

301 303 305 307 309 311

211

253

255

351

906

905

11

10

09

08

0706

05

04

03

02

01

67

901

902

165

131

171

173

0201

719

718

717

715

713 711

801

811 813

815

817

819

818

02 01

02

01

992

991

993

701

Base deck ID:

branchpipetime dependent volume

pumpaccumulatorjunction orientation

crossflow junctiontime dependent junctionvalve

601

603

605

05

04

03

02

01

604

598

271 371

01 02

04

03

05

02

03 04 05

07

06 80 81

0201

03 04

84

82 83

90

91

96

95

88

93

86

92

912 911

913 914

171

727725723

722

721

720

705 805

820

745

743

746 748

749747

872

882

871 881 861

760 860

857

853

851

757

753751

731

732

740

741

831

832

727

582

584

586

588

592

594

951 953

01

08

01

02

02

01

01

0101

01

02

01

01

01

02

01 02

01

141

03

0201

131125

02

02

01

02

01

01 02

03

01 02

01 01 01 01 01 01 01

01

01

02 01

01

02 01

02

01 01 01 01

01

703

01 01

01

01

01

01

01

01 02

01 01

750

01

01

01

803

01 01

01

01

01

850

01

01

01

02

01

02

01 01

375 377

01 01

01

01

01

01

01 01 01 01 01 01

01

01

01

01

02

0101

02 01

02

01 01 01 01

xxx junction described at branch xxx

915

804 704

612

611

916

03

145

04

03

02

01

131

05

ACC 1 ACC 2

RCP 2 RCP 1

SG 2

RPV

PRZ

charging

letdown

451

453

455

457

459

461

217

215 245

243

219 241

933

223

225

07

06

05

04

03

02

01

227

237

08

429

427

423

415

010203040506

411

213

251

0201

413

484

486

488492494

951 953

482

498

03 04 05

01

01

01

01

02

02

01

01

01

0101

01

02

03

01

01

01

02

01

01 01

01

01

01

01

601

SG 1

05

04

030201

417

421

425

419

02 934

443

447

445

01

01

02

01

01

01

315 345

317 343

319 341

935

323

325

07

06

0504

03

02

01

327

337

08

529

527

523

515

511

513

01

01

01

02

02

01

01

01

01

01

01

02

03

01

01

01

02

01

517

521

525

519

02 936

543 545

547

01

01

02

01

01

01

113

01

01

nekCClrv

458 558

01

02

03 04

013

014

01

02

03 04

021

022 028

027

032

01

02 03 04

025 011

01

07 06 05 04

03

02

01

407 409

930

931

01

07 06 05 04

0302

01

507

233

235

01

0102030405060708

333

335

01

010203040506

07

08

121110

09

0807

121110

09

080706

05

04030201

121110090807060504030201

091011

121314

06

153

01

02

01

07

08

09

10

09

08

0706

01

0203040506

07

08

09

10

0908

07

06

05

04030201

509

475

0706

0504030201

406

474

473

0504030201

472

471500

930

931

575

0706

0504030201

506

574

573

04

03

0201

572

571500

939

938

01

02 03

671

672 01 02 03 673 435

941

940

01

02

681

683

01

02

685

686

695

02 01 03

696

687 02

01

697

02

01

943

942

01

02 03

675

676

677

01 02 03 04

535

01 02 03 04 05 06

07 08

10

09 437

11

01

02 03 04 05

08

07

06

537

01

02

03

01

01

01 01

01

02

945

944

947

946

949

948

978

976

974 972

443

543

437 537

MD AFWpump 01

TD AFWpumpMD AFWpump 02

HPIS

LPIS

MFWheader

MFWheader

674

688

678

698

01

607

606

Figure 1 Krško NPP nodalization scheme 
8 

3.2 Regulation and Protection Logic

To accurately represent the behavior of the Krško NPP, the model includes a considerable 

number of control variables and general tables. They represent protection, monitoring, and 

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

main plant control systems: 

$ rod control system 

$ PRZ pressure control system 

$ PRZ level control system 

$ SG level control system 

$ steam dump 

It must be noted that the rod control system has been modeled for point kinetics. The present 

model can be used for transient analysis with either of the following two options: 

(1) constant or predefined core power transient as a function of time (including decay power 

calculation) 

(2) rod control system in auto or manual mode 

The following plant protection systems are defined using trip logic: 

$ reactor trip 

$ SI signal 

$ turbine trip 

$ steamline isolation 

$ MFW isolation 

$ AFW start 
9 

4. ABNORMAL EVENT DESCRIPTION 

The Krško NPP technical specifications required that the operability of the turbine overspeed 

protection system be demonstrated at least once every 31 days by cycling each of the highpressure turbine governor and stop valves through at least one complete cycle from the running 

position. The test procedure consists of two steps. In the first step, the turbine (and thus the 

reactor power) must be reduced below 92 percent to fulfill test conditions. In the second step, 

the test of the turbine governor and stop valves is performed. 

In the first step, the turbine power is reduced until governor valve no. 4 is closed. The turbine 

power is then reduced by another 7 percent until the nuclear power is less than or equal to 

92 percent. The closure of the governor valves is then changed from sequential to single mode 

of operation. The position of the governor valves is checked to ensure that it is less than or 

equal to 35 percent of opening. If it is larger, the power should be reduced before the test start. 

In the second step of the turbine valves test, the allowed maximum position of the governor 

valves is defined as 55 percent of opening. To fulfill this condition, the button “valve position 

limit display” is pushed to read “flow demand” and “valve position limit.” The valve position limit 

is then raised to 160 percent and the valves are tested one by one. The valve is first closed and 

then opened to its initial value. When all valves are tested, the valve position limit is decreased 

to the value at test start (i.e., less than or equal to 35 percent of opening). When lowering the 

valve position limit, the value should stay above the flow demand value. If not, the governor 

valves start to close. This is what happened during the April 5, 2005, transient. The valves 

closed for 5 seconds, from the 35.5-percent to the 12.2-percent position. The valves then 

stabilized for 12 seconds, during which time the position began to increase to 14 percent, 

followed by full closure. The valve positions indicate that the operator set the valve position limit 

below the flow demand; after 16 seconds, he attempted to restore the turbine flow. This resulted 

in a reactor trip, which occurred within the next 2 seconds or less (data were available in 

2-second increments). 

When considering the measured data for the governor valve position at 12.2 percent, it appears 

that the operator confused the desired value of the governor valve position (less than or equal 

to 35 percent opening) with the valve position limit. In other words, the governor valve position 

value of 12.2 percent is equal to 0.35 times 34.9 percent, suggesting that at test start the 

governor valve position was 34.9 percent (less than or equal to 35 percent of opening) and the 

valve position limit was around 100 percent. This was the first operator error. When the operator 

noticed the decreased electrical power output, he attempted to correct the setpoint to the 

desired (i.e., higher) value, but he was not aware that the steam dump was operating. The 

increased demand for steamflow resulted in a high steamflow, which caused a pressure drop. 

The low steamline pressure generated an SI signal. The SI signal led to the reactor trip signal, 

followed by the turbine trip. The SI signal also started both AFW pumps with a 25-second delay. 

Measured data were available for a total of 1,878 seconds in 2-second increments. The data for 

the first 52 seconds represent the steady-state condition. At the 54-second mark, the governing 

valves were already closing, indicating that the transient started. Therefore, the governor valves 

were estimated to have started to close at 53 seconds, which is considered the transient start 

time (t = 0). The remaining data—up to 1,878 seconds—represent the transient, which lasted a 

total of 1,825 seconds. 

11 

5. RESULTS 

The RELAP5/MOD3.3 P03 analysis was divided into two parts. In the first part, the activities in 

the plant before the transient were simulated because measured data were not available. This 

included the monthly testing of the turbine governor and stop valves. The purpose of this 

simulation was to recreate the steady-state condition before the reactor trip. As shown in Table 

1, this part of the analysis consisted of four phases. The first phase demonstrated the steady 

state at a 100-percent power level. In the second phase, the power was reduced from 100 

percent to 91.72 percent, and the steady state at a reduced power level was observed. The third 

phase simulated one cycle of turbine governor valve closing and opening in order to model the 

initial plant conditions as closely as possible. Although there are four turbine governor valves, 

the analysis was performed for only one governor valve because the procedure would be the 

same for each of the four governor valves. The analysis did not simulate the stop valves 

because they close when the governor control valve is fully closed. When the governor valve 

starts to open, the stop valves open as well. Phase 3 also demonstrated the steady state. At 

t = −500 seconds, the time-dependent junction component was replaced by the valve 

component, which caused some transient in the steamflow. Therefore, in Phase 4, steady-state 

calculations, which included the valve component, were performed at a power level of 

91.72 percent. Phase 4 represented a slightly different plant condition because of the replaced 

time-dependent junction. This steady state was compared to the plant data, which were 

available for the 53 seconds before the transient began. The simulation in Part 1 eliminated the 

need to use artificial controls to achieve the steady-state condition at a power level of 

91.72 percent. 

The second part of the analysis, which was Phase 5, simulated the transient leading to the 

reactor trip, as well as the plant response to the turbine and reactor trip. The analysis denoted 

t = 0 seconds as the transient start time. Thus, Part 1 of the analysis encompassed the time 

period from t = –4,000 to t = 0 seconds. Part 2 of the analysis, in which the transient was 

evaluated, spanned the time period from t = 0 seconds to t = 1,900 seconds. 

Table 1 Phases of the Analysis 

Phase of Analysis Description of Phase and Analysis Duration 

Phase 1 Steady state at 100% power (1,000 s) 

Phase 2 Power reduction from 100% to 91.72% for valve testing (1,000 s) 

Phase 3 Cycling of one turbine governor valve (1,500 s) 

Phase 4 Steady state at 91.72% power (500 s) 

Phase 5 Turbine governor valve closure with reactor trip (1,900 s)* 

*

 Measured data were available for 1,825 seconds. 

5.1 Part 1 of the Analysis—Testing of the Turbine Governor Valve

Phases 1 and 4 were steady-state calculations. Phases 2 and 3 were also simulated until the 

point at which steady state was achieved. The Phase 1 simulation was performed to verify 

steady state at 100 percent power, and the Phase 4 simulation was performed to verify steady 

state before the abnormal event began. The Phase 4 steady-state calculation was needed 

because the time-dependent junction component was replaced by the valve component. Only 

53 seconds (from t = –53 seconds to t = 0 seconds) of measured steady-state data were 
12 

available. Based on the average of the sample data, the nuclear power level was at 

91.72 percent. The analysis did not include a simple power reduction scheme to reduce power 

from 100 percent to 91.72 percent because, after being reduced below 92 percent, the reactor 

power level was decreasing and increasing as the turbine governor valves were cycling closed 

and open. To simulate the initial conditions as closely as possible, the model assumed that the 

power was reduced to 68.79 percent and then returned to 91.72 percent. 

If the power level is reduced to 91.72 percent by inserting rods due to a power mismatch 

between the reactor power and turbine power, then the initial conditions will differ from the initial 

conditions created by withdrawing rods. This difference results from the deadband in the 

temperature error signal (i.e., the deadband between the reference temperature and the 

auctioneered average RCS temperature). The difference between the temperature at which the 

rods stop to move in and when they start to move out is 1.4 Kelvin (K) (2.5 degrees Fahrenheit). 

Such a difference causes a change in the pressure on the secondary side (a temperature 

change of 1 K corresponds to a pressure change of 0.125 megapascal (MPa) (18.1 psi)). To 

achieve as close to a match of the secondary-side pressure as possible, the analysis assumed 

that the last request was to withdraw the rods (in the test, the governor valve was first closed 

and then opened). Opening of the governing valves resulted in an increase in turbine power, 

and led to rod withdrawal. The initial secondary pressure is very important because the transient 

occurred on the secondary side, and the SI signal was actuated based on low steamline 

pressure. 

Table 2 presents the initial plant conditions. The first two columns describe the plant variables 

and their units. The third column identifies the average value of the plant-measured initial 

condition. The data were averaged over the time interval between t = −53 seconds and 

t = 0 seconds because the measured values were oscillating slightly for some variables. The 

value t = 0 seconds signifies the start of the reactor trip transient. The fourth column provides 

the plant-measured initial conditions for this time, which differ from the average steady-state 

values in some cases. Finally, the last three columns list the steady-state values at the end of 

Phases 2, 3, and 4. The fifth column reports the calculated initial conditions after the initial 

power was reduced to below 92 percent (rod insertion at t = –2,000 seconds); the sixth column 

reports initial conditions after the rods were withdrawn (t = –500 seconds). Finally, the last 

column presents the initial conditions at the time the transient began (t = 0 seconds). 

Note that, for power reduction, the RELAP5 component, TMDPJUN, was used to model turbine 

flow; therefore, another steady state was calculated when the TMDPJUN component was 

replaced by the valve component, which represented the turbine governor valves. In other 

words, the simulation of both Phase 2 (power reduction) and Phase 3 (governor valve testing) 

was extended until a steady state was reached. 
13 

Table 2 Initial Conditions for Reactor Trip Transient 

Variables Unit measured 

(average)

measured

(t=0 s) 

calculated 

(t=-2,000 s)

calculated 

(t=-500 s) 

calculated

(t=0 s) 

PRZ pressure MPa 

(psia) 

15.48 

(2245) 

15.48 

(2245) 

15.52 

(2251) 

15.51 

(2250) 

15.52 

(2251) 

SG 1 pressure MPa 

(psia) 

6.42 

(931) 

6.42 

(931) 

6.59 

(956) 

6.43 

(933) 

6.47 

(938) 

SG 2 pressure MPa 

(psia) 

6.40 

(928) 

6.40 

(928) 

6.57 

(953) 

6.42 

(931) 

6.45 

(935) 

Feedwater 1 mass flow 

rate 

kg/s 

(lb/s) 

499.00 

(1100.30)

504.00 

(1111.32)

495.20 

(1091.92) 

495.40 

(1092.36) 

495.50 

(1092.58)

Feedwater 2 mass flow 

rate 

kg/s 

(lb/s) 

503.60 

(1110.44)

500.60 

(1103.82)

497.70 

(1097.43) 

498.10 

(1098.31) 

498.10 

(1098.31)

Main steamline 1 mass 

flow rate 

kg/s 

(lb/s) 

493.90 

(1089.05)

492.60 

(1086.18)

495.20 

(1091.92) 

495.40 

(1092.36) 

495.40 

(1092.36)

Main steamline 2 mass 

flow rate 

kg/s 

(lb/s) 

501.60 

(1106.03)

501.50 

(1105.81)

497.80 

(1097.65) 

498.10 

(1098.31) 

498.10 

(1098.31)

PRZ liquid level % 53.02 52.95 56.10 51.88 52.63 

SG 1 narrow range level % 69.25 69.15 69.34 69.26 69.28 

SG 2 narrow range level % 69.06 69.40 69.34 69.25 69.28 

Nuclear power % 91.72 91.94 91.63 91.78 91.77 

Cold leg 1 temperature K 

( ̊F) 

559.41 

(547.27) 

559.36 

(547.18) 

560.74 

(549.66) 

559.15 

(546.80) 

559.51 

(547.45) 

Cold leg 2 temperature K 

( ̊F) 

559.57 

(547.56) 

559.53 

(547.48) 

560.59 

(549.39) 

558.99 

(546.51) 

559.35 

(547.16) 

Hot leg 1 temperature K 

( ̊F) 

593.92 

(609.39) 

593.73 

(609.04) 

594.64 

(610.68) 

593.23 

(608.14) 

593.55 

(608.72) 

Hot leg 2 temperature K 

( ̊F) 

594.58 

(610.57) 

594.62 

(610.65) 

594.64 

(610.68) 

593.23 

(608.14) 

593.55 

(608.72) 

Average RCS 1 

temperature 

K 

( ̊F) 

576.63 

(578.26) 

576.52 

578.07) 

577.69 

(580.17) 

576.19 

(577.47) 

576.53 

(578.08) 

Average RCS 2 

temperature 

K 

( ̊F) 

577.05 

(579.02) 

577.05 

(579.02) 

577.62 

(580.05) 

576.11 

(577.33) 

576.45 

(577.94) 

Programmed Tavg K 

( ̊F) 

576.90 

(578.75) 

576.90 

(578.75) 

576.97 

(578.88) 

576.97 

(578.88) 

577.00 

(578.93) 

Figures 2 through 21 illustrate the main variables for the governor valve monthly testing and 

explain how the initial condition at a 91.72-percent power level was obtained. Where plantmeasured data were available, the calculated and measured data were compared. The 

calculated data (labeled “cal”) were available for the time interval between t = −4000 seconds 

and t = 0 seconds, while the measured steady-state data were available for the time interval 

between t = −53 seconds to t = 0 seconds, for most of the important variables shown in 

Figures 2 through 21. Table 3 describes the variable identification used in the figures. The 

power reduction scheme was such that flow was reduced from a nominal value of 1,086 

kilograms per second (kg/s) (2394 lb/s) to 991 kg/s (2185 lb/s), thereby simulating the initial test 

conditions. A test of the governor valve closing and opening was then performed (with flow 

decreasing to 743.25 kg/s (1638.59 lb/s) and then returning to 991 kg/s (2185 lb/s)). For 
14 

simplicity, the analysis simulated only one out of four valve testing cycles (closing and opening). 

Because there were no measured data on the timing of valve closing and opening, the analysis 

assumed a 5 percent per minute load reduction and increase, as shown in Figure 4. In other 

words, 5 minutes were needed to achieve a 25-percent power reduction from the 91.72-percent 

power level, and 5 minutes were needed for the power to increase. In this way, the steam dump 

operation was prevented. Figure 4 indicates that the turbine flow was reduced linearly both 

during power reduction and valve cycling. At t = –500 seconds, the valve component was 

introduced, temporarily causing the flow to spike. Because the turbine is not modeled explicitly, 

but rather by logic, turbine power (Figure 5) is calculated as a function of flow (Figure 4). The 

control rods start to move in when the turbine flow demand is reduced and to move out when 

the turbine flow demand is increased (Figure 3). Rod movement causes the reactor power to 

change, as shown in Figure 2. Reference temperature follows the generated power (Figure 11). 

The PRZ level (Figure 13) shows a slight increase initially after power reduction (from 

t = −3,000 seconds to t = −2,880 seconds) as a result of the power imbalance. Rod motion and 

reactor power then decrease the RCS average temperature. The resulting density change 

brings the pressurizer level down at t = –2,400 seconds. During testing, the same phenomenon 

occurs when the governor valve closes. When the governor valve opens, the opposite 

phenomenon occurs. 

Charging flow (Figure 14) also varies slightly to accommodate the density changes, and letdown 

flow (Figure 15) is held constant. Both flows are higher than the initial plant values. However, 

the difference between the flows is similar, and the letdown flow is higher than the charging flow 

in both the calculations and the plant measurements. The RCS average temperature does not 

decrease as expected in the initial 150 seconds of Phase 2 (until t = –2,850 seconds) because 

of a delay resulting from a combination of the loop transport time, resistance temperature 

detector manifold arrangement, and instrument processing time (Figure 10). The temperature 

then begins to decrease. At the beginning of Phase 3, similar to the above-described delay, the 

temperature first increases and then decreases. The temperature also starts to increase, with a 

delay, at t = –1,530 seconds (the turbine governor valve starts to open at t = –1,700 seconds). 

Figures 6 through 9 represent the hot- and cold-leg temperatures. The differences between the 

measured and calculated initial values at t = 0 seconds were less than 0.4 K (0.72  ̊F), except 

for the hot leg 1 temperature. The reason for this exception is the nearly symmetrical conditions 

in the RELAP5 calculation; in the measured data, there is slight asymmetry between the 

steamflows and the hot-leg temperatures. The plant data seem consistent—the loop 2 hot-leg 

temperature is lower and the steamflow is higher. The initial SG 1 and 2 pressure overshoot (as 

depicted in Figures 16 and 17) in the beginning of Phase 2 is caused by the RCS average 

temperature. Continued rod motion (rod insertion) eventually brought the RCS average 

temperature to the reference temperature at around t = −2,400 seconds (i.e., the upper side of 

the deadband). When the turbine governor valve is tested, the SG pressure behaves similarly 

during valve closing, while opening the turbine governor valves initially caused a further 

decrease in pressure. Finally, rod withdrawal brought the RCS temperature to the reference 

temperature, thereby increasing both SG pressures (from t = −1,370 seconds to 

t = −1,170 seconds). 

As rods stop to move out (at the lower side of the deadband), the SG pressure differs from the 

pressure before valve testing despite the approximately same reactor power level. When the 

valve component was introduced into the input model, the SG pressure first spiked and then 

stabilized in Phase 4 at a slightly higher value than at the end of Phase 3. The steamflow 
15 

(Figures 18 and 19) follows the modeled turbine flow. At the end of Phase 4, the calculated 

steamflows are in good agreement with the steady-state steamflows measured at the plant. The 

feed flow/steamflow mismatch circuit in the SG level control regulates the feedwater flow 

(Figure 20 and Figure 21). Again, the calculated feedwater flows agree well with the steadystate feedwater flows measured at the plant. 

Table 3 Variables Identification in Figures 

ID Code Variable 

1 AF00793_FT205 Charging flow 

2 AF00795_FT132 Letdown flow 

3 AF00798_FT510A Feedwater flow SG 1 

4 AF00799_FT512A Steamflow SG 1 

5 AF00803_FT520A Feedwater flow SG 2 

6 AF00804_FT522A Steamflow SG 2 

7 AF03308_FT302 AFW 1 volumetric flow 

8 AF03309_FT301 AFW 1 volumetric flow 

9 AF04033_FT901 SI 1 volumetric flow 

10 AF04034_FT902 SI 2 volumetric flow 

11 AL00813_LT517 SG 1 narrow range level 

12 AL00815_LT527 SG 2 narrow range level 

13 AL00818_LT465 PRZ level 

14 AN00846_NM41F Core power 

15 AP00871_PT514 SG 1 pressure 

16 AP00872_PT524 SG 2 pressure 

17 AP00874_PT455 PRZ pressure 

18 AT00941_TE412A RCS average temperature 

19 AT00942_TE410B Cold leg loop 1 temperature 

20 AT01360_TE420B Cold leg loop 2 temperature 

21 AT01377_TE660 Reference (programmed) temperature 

22 AT05973_TE410A Hot leg loop 1 temperature 

23 AT05974_TE420A Hot leg loop 2 temperature 
16 

0

20

40

60

80

100

120

-4000 -3000 -2000 -1000 0

Time (s)

Power (%)

cal

AN00846_NM41F

Phase 1 Phase 2 Phase 3 Phase 4

Figure 2 Core power—testing of turbine governor valve 

0

100

200

300

400

500

600

700

-4000 -3000 -2000 -1000 0

Time (s)

Integral position (steps)

cal

Phase 1 Phase 2 Phase 3 Phase 4

Figure 3 Rod position—testing of turbine governor valve 
17 

0

200

400

600

800

1000

1200

-4000 -3000 -2000 -1000 0

Time (s)

Mass flow (kg/s)

cal

Phase 1 Phase 2 Phase 3 Phase 4

Figure 4 Turbine flow—testing of turbine governor valve 

0

20

40

60

80

100

120

-4000 -3000 -2000 -1000 0

Time (s)

Power (%)

cal

Phase 1 Phase 2 Phase 3 Phase 4

Figure 5 Turbine power—testing of turbine governor valve 
18 

557

558

559

560

561

562

563

564

-4000 -3000 -2000 -1000 0

Time (s)

Temperature (K)

cal

AT00942_TE410B

Phase 1 Phase 2 Phase 3 Phase 4

Figure 6 Cold leg loop 1 temperature—testing of turbine governor valve 

557

558

559

560

561

562

563

564

-4000 -3000 -2000 -1000 0

Time (s)

Temperature (K)

cal

AT01360_TE420B

Phase 1 Phase 2 Phase 3 Phase 4

Figure 7 Cold leg loop 2 temperature—testing of turbine governor valve 
19 

588

590

592

594

596

598

600

-4000 -3000 -2000 -1000 0

Time (s)

Temperature (K)

cal

AT05973_TE410A

Phase 1 Phase 2 Phase 3 Phase 4

Figure 8 Hot leg loop 1 temperature—testing of turbine governor valve 

588

590

592

594

596

598

600

-4000 -3000 -2000 -1000 0

Time (s)

Temperature (K)

cal

AT05974_TE420A

Phase 1 Phase 2 Phase 3 Phase 4

Figure 9 Hot leg loop 2 temperature—testing of turbine governor valve 
20 

574

575

576

577

578

579

580

-4000 -3000 -2000 -1000 0

Time (s)

Temperature (K)

cal

AT00941_TE412A

Phase 1 Phase 2 Phase 3 Phase 4

Figure 10 RCS average temperature—testing of turbine governor valve 

574

575

576

577

578

579

580

-4000 -3000 -2000 -1000 0

Time (s)

Temperature (K)

cal

AT01377_TE660

Phase 1 Phase 2 Phase 3 Phase 4

Figure 11 Reference (programmed) temperature—testing of turbine governor valve 
21 

15

15.2

15.4

15.6

15.8

16

-4000 -3000 -2000 -1000 0

Time (s)

p (MPa)

cal

AP00874_PT455

Phase 1 Phase 2 Phase 3 Phase 4

Figure 12 PRZ pressure—testing of turbine governor valve 

0

10

20

30

40

50

60

70

-4000 -3000 -2000 -1000 0

Time (s)

Level (%)

cal

AL00818_LT465

Phase 1 Phase 2 Phase 3 Phase 4

Figure 13 PRZ level—testing of turbine governor valve 
22 

0

2

4

6

8

-4000 -3000 -2000 -1000 0

Time (s)

Volumetric flow (l/s)

cal

AF00793_FT205

Phase 1 Phase 2 Phase 3 Phase 4

Figure 14 Charging flow—testing of turbine governor valve 

0

2

4

6

8

-4000 -3000 -2000 -1000 0

Time (s)

Volumetric flow (l/s)

cal

AF00795_FT132

Phase 1 Phase 2 Phase 3 Phase 4

Figure 15 Letdown flow—testing of turbine governor valve 
23 

6.2

6.4

6.6

6.8

7

-4000 -3000 -2000 -1000 0

Time (s)

p (MPa)

cal

AP00871_PT514

Phase 1 Phase 2 Phase 3 Phase 4

Figure 16 SG 1 pressure—testing of turbine governor valve 

6.2

6.4

6.6

6.8

7

-4000 -3000 -2000 -1000 0

Time (s)

p (MPa)

cal

AP00872_PT524

Phase 1 Phase 2 Phase 3 Phase 4

Figure 17 SG 2 pressure—testing of turbine governor valve 
24 

0

100

200

300

400

500

600

-4000 -3000 -2000 -1000 0

Time (s)

Mass flow (kg/s)

cal

AF00799_FT512A

Phase 1 Phase 2 Phase 3 Phase 4

Figure 18 Steamflow SG 1—testing of turbine governor valve 

0

100

200

300

400

500

600

-4000 -3000 -2000 -1000 0

Time (s)

Mass flow (kg/s)

cal

AF00804_FT522A

Phase 1 Phase 2 Phase 3 Phase 4

Figure 19 Steamflow SG 2—testing of turbine governor valve 
25 

0

100

200

300

400

500

600

-4000 -3000 -2000 -1000 0

Time (s)

Mass flow (kg/s)

cal

AF00798_FT510A

Phase 1 Phase 2 Phase 3 Phase 4

Figure 20 Feedwater flow SG 1testing of turbine governor valve 

0

100

200

300

400

500

600

-4000 -3000 -2000 -1000 0

Time (s)

Mass flow (kg/s)

cal

AF00803_FT520A

Phase 1 Phase 2 Phase 3 Phase 4

Figure 21 Feedwater flow SG—testing of turbine governor valve 
26 

5.2 Part 2 of the Analysis—Turbine Governor Valve Closure with Reactor Trip

Table 4 presents the time sequence of the main events in the transient. This time sequence was 

determined based on measured data of plant variables. Measured data showed that the turbine 

governor valves were closing for 5 seconds—from the 35.5-percent to the 12.2-percent 

position—and then stabilized for 12 seconds. When the position started to increase to 

14 percent, based on operation action, full closure of the turbine valves occurred, causing a 

turbine trip. The power level showed that the reactor was tripped. The reason for the reactor trip 

was low steamline pressure, which generated an SI signal. The low steamline pressure resulted 

from the turbine flow increase (note that data were available for each 2-second increment). At 

t = 15 seconds, the valve position was 12.2 percent, and at t = 17 seconds, the valve position 

was already 14.1 percent. Therefore, it was assumed that the operator started to open the 

turbine governor valves at t = 16 seconds. The SI signal also resulted in the generation of MFW 

isolation and MSIV signals; the HPIS was actuated, and letdown and charging were isolated. 

Note that the sequence of events for the plant was determined from measured data, which were 

used for the plots presented in the figures that follow; therefore, the values are rounded to 

seconds. For example, the core power starts to drop after 19 seconds. The exact time of reactor 

trip could not be determined because signal delay and rod drop time is not known exactly. 

Table 4 Time Sequence of Main Events during Transient 

Event Measurement Calculation 

Turbine flow reduction 0–5 s 0–5 s 

Operator action (start of governor valve 

opening) 

16 s 16 s 

SI signal on low steamline pressure 17 s* 16.7 s 

SI pump injection start 21 s 20 s 

SG PORV opening 27 s 31 s 

AFW flow actuation 42 s 42 s 

*

 Based on a 25-second delay of AFW actuation 

The transient data available spanned a total of 1,825 seconds. Because the event following 

turbine valve closure happened very quickly, the plots for the Phase 5 analysis are shown for 

the following three time windows: 

(1) Window 1 (t = −50 seconds to t = 50 seconds): Reactor trip with SG pressure increase 

and SG PORV opening 

(2) Window 2 (t = −50 seconds to t = 450 seconds): SG pressure decrease and primary 

pressure increase 

(3) Window 3 (t = −50 seconds to t = 1,825 seconds): SG pressure increase followed by SG 

pressure stabilization 

Figures 22 thorough 44 present the results of the Phase 5 analysis. For the plant variables 

identification, refer to Table 3. 

Figure 22 represents the core power. The power drops when the reactor is tripped and the rods 

start to drop. The measurement of the power range channel is based on the neutron flux. After 
27 

reactor shutdown, only part of the decay heat is due to neutron flux from delayed neutrons and 

spontaneous fission neutrons. Decay heat also results from other sources, such as unstable 

fission products and unstable actinides. Therefore, the measured flow is lower than the actual 

flow, which is the major reason for the disagreement between the measured data and the 

calculation. In Figure 22(c), it can be seen from the calculated data that the decay heat is 

simulated with RELAP5, while the measured data do not correctly depict this decay. Figure 23 

shows the cold-leg temperature in loop 1, and Figure 24 shows the cold-leg temperature in 

loop 2. Because of the power mismatch between the reactor and turbine power, the cold-leg 

temperatures initially increased and then decreased, while the hot-leg temperatures in both 

loops (Figure 25 and Figure 26) remained practically constant. However, when the reactor was 

tripped, the hot-leg temperatures began to drop, and the cold-leg temperatures started to 

increase. These temperature values approach each other because the difference between the 

hot- and cold-leg temperatures is smaller after reactor trip (i.e., just a few degrees K). 

Figure 27 shows the RCS average temperature. After transient initiation, the temperature starts 

to increase until the reactor is tripped at t = 17 seconds. At this point, the temperature is a 

function of the primary system cooling (by primary-side injection) and the secondary-side heat 

sink. The secondary-side heat sink dominates; therefore, the shape of the RCS average 

temperature plot is similar to the plots of both SG pressure trends (see Figure 33 and 

Figure 34). The reference temperature shown in Figure 28 corresponds to turbine power. As in 

the RELAP5 input model, the turbine is not explicitly modeled; the reference temperature follows 

the turbine flow. When the turbine flow was reduced, the reference temperature decreased 

initially. When the operator opened the turbine valves, the turbine flow increased until the 

reactor tripped. Then, the flow dropped to no load conditions. The measured reference 

temperature follows the turbine load (impulse pressure). The comparison is relevant only to the 

time of reactor trip. Also, in the presence of steam dump flow, the turbine flow could not be 

determined accurately based on total steamflow. The calculated reference temperature could be 

simulated correctly only in the case in which either the steam dump flow or the turbine flow is 

known in addition to the steamflow. 

Figure 29 shows the PRZ pressure. The model calculates the initial pressure increase very well. 

The pressure rapidly increases until the PRZ sprays are actuated. It can be seen that 

continuous sprays efficiently reduced the pressure increase before reactor trip. When the 

reactor tripped, the PRZ pressure decreased further. Initial agreement between the calculated 

data and the measured data is very good, including the peak pressure values. However, it can 

be seen that, after 25 seconds, the calculated pressure indicates a repressurization of the 

primary system. This may result from earlier SI termination (see Figure 41 and Figure 42). Later 

agreement between the calculated and measured data is good. The pressure returned to its 

normal value via the PRZ control system. The sprays were actuated when the pressure began 

to increase above the spray setpoint, at around t = 650 seconds. At around t = 900 seconds, the 

operators decided to reestablish charging and letdown flow (see Figure 31 and Figure 32). At 

around t = 1,500 seconds, the sprays were terminated. Figure 30 illustrates the PRZ level. 

There was some discrepancy between the calculated and the measured SI flow; however, it 

was decided not to tune the calculated SI flow to the measured data. 

Figure 31 and Figure 32 depict the charging and letdown flow, respectively. Both charging and 

letdown flow were isolated upon the SI signal in the calculation, although the measured data 

showed some delay in isolation. After t = 900 seconds, the measured data show that the 

operators reestablished both charging and letdown (operator action); therefore, the calculations 

also assumed these flows (note that approximate values were used). 
28 

The calculated SG pressures were in good agreement with the measurement data (Figure 33 

and Figure 34). The reason for this agreement is partly the AFW flow value, which was based 

on actual plant measurement (see Figure 43 and Figure 44). The operators were changing the 

AFW flow as the transient began. However, in the initial period when the AFW was not injecting, 

the first SG pressure peak resulted from closure of the governor valve, and the second peak 

resulted from the turbine trip. When the operator opened the turbine governor valves, the SG 

pressure after the first peak started to decrease, causing an SI signal to be generated based on 

low steamline pressure. The second peak caused the SG PORV valve to open. To obtain an 

exact match of SG pressures, the smaller steamflow than measured was modeled as indicated 

by measured data (Figure 37 and Figure 38). 

Following the main steamline isolation after the turbine trip, there was some steamflow to the 

gland steam system. Because the steam is generated based on available heat (mostly decay 

heat), the model indicated the maximum value of generated steam, which was lower than the 

measured data (labeled “cal. limiting”). Therefore, the steamflow was tuned to obtain as good a 

match to the measured SG pressure as possible. The value of steamflow is physically 

reasonable, but it is not known if this value reflects the reality of the transient. In addition, the 

transient was very sensitive to this variable. Without assuming the measured steamflow after 

reactor trip or the measured data for steamflow, the SG pressure would be overpredicted 

(requiring SG PORV opening) or underpredicted. Only these variables required tuning; all other 

calculated variables were in excellent agreement with measured variables. The analysis 

revealed an important finding—the RELAP5 computer code calculation suggested some 

steamflow to the gland steam system. It was later discovered that there is greater steamflow to 

the gland steam system when steamline isolation occurs following a turbine trip. This particular 

circumstance occurred in the analyzed event. The base input model did not include the 

steamflow to the gland steam system. 

The SG levels also agreed well initially (see Figure 35 and Figure 36). The reactor trip caused 

both turbine trip and MFW isolation. The closure of the turbine valves and core heat transferred 

to the SG resulted in the steam pressure increase (see Figure 33 and Figure 34), which had a 

shrink effect on the SG-level instrumentation (see Figure 35 and Figure 36). Upon an SI signal, 

following a 25-second delay, the AFW injection was started to remove the decay heat and fill the 

SGs. Following the MFW isolation, the SG level was affected by AFW and released steam. 

However, it was observed that, in the time period between t = 26 seconds and t = 73 seconds 

and t = 70 seconds, when SG PORVs 1 and 2 were operated, respectively, the calculated level 

is higher than the measured data. In addition, level oscillates were observed around the 

measured trend until t = 1,000 seconds due to oscillating steamflow. One possible explanation 

for this behavior could be that the RELAP5 input model underpredicted the damping of the 

oscillating water flow between the downcomer and the riser in the SG. 

Figures 37 through 40 illustrate the steamline and feedwater flows. Most important is the initial 

phase. It can be seen that, in the calculation, the SI signal was generated immediately after the 

turbine valve closure, while the measured data showed some delay. Nevertheless, the major 

phenomena were simulated, and the steamflow values matched very well. Although the steam 

dump opened, no measured data were available for steam dump flow. The steamflows in both 

steamlines (Figure 37 and Figure 38) represent the flow to both the steam dump and turbine. As 

mentioned earlier, the measured values of steamflows are not reliable after reactor trip upon an 

SI signal. 
29 

Similarly, the feedwater flow is not correct in the time interval immediately after reactor trip. The 

feedwater isolation valves closed upon the SI signal. The measured feedwater flow data shown 

Figure 39 and Figure 40 indicate some flow after reactor trip. As shown in Figure 41 and 

Figure 42. the calculated SI flow was lower than the plant-measured data. The spike in 

calculated data resulted from the initial surge of injection flow into the reactor vessel. As 

discussed previously, the disagreement between the calculated and measured data has some 

influence on the PRZ level shown in Figure 30. 
30 

0

10

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50

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-50 -25 0 25 50

Time (s)

Power (%)

cal

AN00846_NM41

(a)

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10

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50

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80

90

100

-50 50 150 250 350 450

Time (s)

Power (%)

cal

AN00846_NM41

(b)

0

10

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30

40

50

60

70

80

90

100

-50 450 950 1450

Time (s)

Power (%)

cal

AN00846_NM41

(c)

Figure 22 Core power—turbine governor valve closure with reactor trip 
31 

558

560

562

564

566

568

570

-50 -25 0 25 50

Time (s)

Temperature (K)

cal

AT00942_TE410B

(a)

558

560

562

564

566

568

570

-50 50 150 250 350 450

Time (s)

Temperature (K)

cal

AT00942_TE410B

(b)

558

560

562

564

566

568

570

-50 450 950 1450

Time (s)

Temperature (K)

cal

AT00942_TE410B

(c)

Figure 23 Cold leg loop 1 temperature—turbine governor valve closure with reactor trip 
32 

558

560

562

564

566

568

570

-50 -25 0 25 50

Time (s)

Temperature (K)

cal

AT01360_TE420B

(a)

558

560

562

564

566

568

570

-50 50 150 250 350 450

Time (s)

Temperature (K)

cal

AT01360_TE420B

(b)

558

560

562

564

566

568

570

-50 450 950 1450

Time (s)

Temperature (K)

cal

AT00942_TE410B

(c)

Figure 24 Cold leg loop 2 temperature—turbine governor valve closure with reactor trip 
33 

560

565

570

575

580

585

590

595

600

-50 -25 0 25 50

Time (s)

Temperature (K)

cal

AT05973_TE410A

(a)

560

565

570

575

580

585

590

595

600

-50 50 150 250 350 450

Time (s)

Temperature (K)

cal

AT05973A_TE410A

(b)

560

565

570

575

580

585

590

595

600

-50 450 950 1450

Time (s)

Temperature (K)

cal

AT05973_TE410A

(c)

Figure 25 Hot leg loop 1 temperature—turbine governor valve closure with reactor trip 
34 

560

565

570

575

580

585

590

595

600

-50 -25 0 25 50

Time (s)

Temperature (K)

cal

AT05974_TE420A

(a)

560

565

570

575

580

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590

595

600

-50 50 150 250 350 450

Time (s)

Temperature (K)

cal

AT05974_TE420A

(b)

560

565

570

575

580

585

590

595

600

-50 450 950 1450

Time (s)

Temperature (K)

cal

AT05974_TE420A

(c)

Figure 26 Hot leg loop 2 temperature—turbine governor valve closure with reactor trip 
35 

560

565

570

575

580

585

-50 -25 0 25 50

Time (s)

Temperature (K)

cal

AT00941_TE412A

(a)

560

565

570

575

580

585

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Time (s)

Temperature (K)

cal

AT00941_TE412A

(b)

560

565

570

575

580

585

-50 450 950 1450

Time (s)

Temperature (K)

cal

AT00941_TE412A

(c)

Figure 27 RCS average temperature—turbine governor valve closure with reactor trip 
36 

560

565

570

575

580

585

-50 -25 0 25 50

Time (s)

Temperature (K)

cal

AT01377_TE660

(a)

560

565

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585

-50 50 150 250 350 450

Time (s)

Temperature (K)

cal

AT01377_TE660

(b)

560

565

570

575

580

585

-50 450 950 1450

Time (s)

Temperature (K)

cal

AT01377_TE660

(c)

Figure 28 Reference temperature—turbine governor valve closure with reactor trip 
37 

144

146

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150

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-50 -25 0 25 50

Time (s)

Pressure (MPa)

cal

AP00874_PT455

(a)

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150

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162

-50 50 150 250 350 450

Time (s)

Pressure (MPa)

cal

AP00874_PT455

(b)

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150

152

154

156

158

160

162

-50 450 950 1450

Time (s)

Pressure (MPa)

cal

AP00874_PT455

(c)

Figure 29 PRZ pressure—turbine governor valve closure with reactor trip 
38 

0

10

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50

60

70

-50 -25 0 25 50

Time (s)

Level (%)

cal

AL00818_LT465

(a)

0

10

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60

70

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Time (s)

Level (%)

cal

AL00818_LT465

(b)

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60

70

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Time (s)

Level (%)

cal

AL00818_LT465

(c)

Figure 30 PRZ level—turbine governor valve closure with reactor trip 
39 

0

2

4

6

8

-50 -25 0 25 50

Time (s)

Volumetric flow (l/s)

cal

AF00793_FT205

(a)

0

2

4

6

8

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Time (s)

Volumetric flow (l/s)

cal

AF00793_FT205

(b)

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2

4

6

8

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Time (s)

Volumetric flow (l/s)

cal

AF00793_FT205

(c)

Figure 31 Charging flow—turbine governor valve closure with reactor trip 
40 

0

2

4

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8

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Time (s)

Volumetric flow (l/s)

cal

AF00795_FT132

(a)

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2

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8

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Time (s)

Volumetric flow (l/s)

cal

AF00795_FT132

(b)

0

2

4

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8

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Time (s)

Volumetric flow (l/s)

cal

AF00795_FT132

(c)

Figure 32 Letdown flow—turbine governor valve closure with reactor trip 
41 

64

68

72

76

80

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Time (s)

Pressure (MPa)

cal

AP00871_PT514

(a)

64

68

72

76

80

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Time (s)

Pressure (MPa)

cal

AP00871_PT514

(b)

64

68

72

76

80

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Time (s)

Pressure (MPa)

cal

AP00871_PT514

(c)

Figure 33 SG 1 pressure—turbine governor valve closure with reactor trip 
42 

64

68

72

76

80

-50 -25 0 25 50

Time (s)

Pressure (MPa)

cal

AP00872_PT524

(a)

64

68

72

76

80

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Time (s)

Pressure (MPa)

cal

AP00872_PT524

(b)

64

68

72

76

80

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Time (s)

Pressure (MPa)

cal

AP00872_PT524

(c)

Figure 34 SG 2 pressure—turbine governor valve closure with reactor trip 
43 

0

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80

-50 -25 0 25 50

Time (s)

Level (%)

cal

AL00813_LT517

(a)

0

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Time (s)

Level (%)

cal

AL00813_LT517

(b)

0

10

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30

40

50

60

70

80

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Time (s)

Level (%)

cal

AL00813_LT517

(c)

Figure 35 SG 1 narrow range level—turbine governor valve closure with reactor trip 
44 

0

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Time (s)

Level (%)

cal

AL00815_LT527

(a)

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Time (s)

Level (%)

cal

AL00815_LT527

(b)

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Time (s)

Level (%)

cal

AL00815_LT527

(c)

Figure 36 SG 2 narrow range level—turbine governor valve closure with reactor trip 
45 

0

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700

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Time (s)

Mass flow (kg/s)

cal

AF00799_FT512A

(a)

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Time (s)

Mass flow (kg/s)

cal

AF00799_FT512A

(b)

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50

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Time (s)

Mass flow (kg/s)

cal

AF00799_FT512A

cal. limiting

(c)

Figure 37 Steamflow SG 1—turbine governor valve closure with reactor trip 
46 

0

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700

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Time (s)

Mass flow (kg/s)

cal

AF00804_FT522A

(a)

0

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400

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600

700

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Time (s)

Mass flow (kg/s)

cal

AF00804_FT522A

(b)

0

10

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30

40

50

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Time (s)

Mass flow (kg/s)

cal

AF00804_FT522A

calc. limiting

(c)

Figure 38 Steamflow SG 2—turbine governor valve closure with reactor trip 
47 

0

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600

-50 -25 0 25 50

Time (s)

Mass flow (kg/s)

cal

AF00798_FT510A

(a)

0

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500

600

-50 50 150 250 350 450

Time (s)

Mass flow (kg/s)

cal

AF00798_FT510A

(b)

0

100

200

300

400

500

600

-50 450 950 1450

Time (s)

Mass flow (kg/s)

cal

AF00798_FT510A

(c)

Figure 39 Feedwater flow SG 1—turbine governor valve closure with reactor trip 
48 

0

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300

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500

600

-50 -25 0 25 50

Time (s)

Mass flow (kg/s)

cal

AF00803_FT520A

(a)

0

100

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600

-50 50 150 250 350 450

Time (s)

Mass flow (kg/s)

cal

AF00803_FT520A

(b)

0

100

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300

400

500

600

-50 450 950 1450

Time (s)

Mass flow (kg/s)

cal

AF00803_FT520A

(c)

Figure 40 Feedwater flow SG 2—turbine governor valve closure with reactor trip 
49 

0

5

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15

20

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Time (s)

Volumetric flow (l/s)

cal

AF04033_FT901

(a)

0

5

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15

20

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Time (s)

Volumetric flow (l/s)

cal

AF04033_FT901

(b)

0

5

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15

20

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Time (s)

Volumetric flow (l/s)

cal

AF04033_FT901

(c)

Figure 41 SI 1 volumetric flow—turbine governor valve closure with reactor trip 
50 

0

5

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20

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Time (s)

Volumetric flow (l/s)

cal

AF04034_FT902

(a)

0

5

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20

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Time (s)

Volumetric flow (l/s)

cal

AF04034_FT902

(b)

0

5

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15

20

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Time (s)

Volumetric flow (l/s)

cal

AF04034_FT902

(c)

Figure 42 SI 2 volumetric flow—turbine governor valve closure with reactor trip 
51 

0

5

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15

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25

30

35

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Time (s)

Volumetric flow (l/s)

cal

AF03308_FT302

(a)

0

5

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15

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25

30

35

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Time (s)

Volumetric flow (l/s)

cal

AF03308_FT302

(b)

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5

10

15

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25

30

35

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Time (s)

Volumetric flow (l/s)

cal

AF03308_FT302

(c)

Figure 43 AFW 1 volumetric flow—turbine governor valve closure with reactor trip 
52 

0

5

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25

30

35

-50 -25 0 25 50

Time (s)

Volumetric flow (l/s)

cal

AF03309_FT301

(a)

0

5

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20

25

30

35

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Time (s)

Volumetric flow (l/s)

cal

AF03309_FT301

(b)

0

5

10

15

20

25

30

35

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Time (s)

Volumetric flow (l/s)

cal

AF03309_FT301

(c)

Figure 44 AFW 2 volumetric flow—turbine governor valve closure with reactor trip 
53 

6. RUN STATISTICS 

The transient was calculated using a Hewlett Packard personal computer with a 1.60-gigahertz 

Intel Pentium M processor running Microsoft Windows XP, Professional Version 2002, Service 

Pack 2. Table 5 summarizes the run statistics. Note that the CPU time was shorter than that of 

the actual transient duration. 

Table 5 Run Statistics 

Number of volumes 469 

Number of time steps 54523 

Transient time 1900 s 

CPU time 1166.6 s 

CPU time/Transient time 0.61 

55 

7. CONCLUSIONS

This study evaluated the RELAP5/MOD3.3 P03 computer code against plant-measured data for 

the reactor trip that occurred at the Krško NPP on April 10, 2005. In addition to the code 

assessment, the analysis served to validate the input model for the Krško NPP, which is a twoloop Westinghouse PWR. 

The event analyzed was a malfunction that occurred during a power reduction sequence while 

regular, periodic testing of the turbine valves was performed. The reactor trip analysis was 

divided into two parts. In the first part, the power was reduced from a nominal value of 

100 percent to test conditions at around 91.72 percent. The first part of the analysis also 

simulated the testing of the turbine governor valves. The second part of the analysis simulated 

the turbine governor valve closure with reactor trip, as well as the associated operator actions. 

A steady state of 91.72-percent power was achieved by manipulating the plant RELAP5 model. 

in such a way that the calculated initial conditions were close to the initial conditions at the plant. 

The results demonstrated that the transient very much depends on both the primary- and 

secondary-side injection flows. After the initial phase of the transient, the operators set the 

flows; therefore, it was necessary to use the plant-measured data in the calculation for charging 

and letdown on the primary side and the AFW on the secondary side. The analysis revealed 

that the long-term transient evolution is very sensitive to steamflow following a reactor trip. The 

calculation showed that the measured steamflow was larger than the calculated steam 

generated by available decay heat and as consequence measurement of steamflow after 

reactor trip was not reliable. Therefore, the steamflow was tuned to obtain as good a match to 

the measured SG pressure as possible. 

In general, the analysis found that proper modeling of operator actions was needed to obtain 

good agreement between the calculated results and the plant-measured data. Initially, proper 

modeling of the governor valve closure was required to obtain the SI signal upon low steamline 

pressure. In the later phase, proper modeling of the filling of the primary and secondary system 

was important. Without modeling the operator actions which happened, close agreement 

between calculation and measured data would not be achieved. Finally, the calculated data may 

be used to supplement plant-measured data when the information is missing or the 

measurement is questionable. 

57 

8. REFERENCES

1. U.S. Nuclear Regulatory Commission, “RELAP5/MOD3.3 Code Manual,” 

NUREG/CR-5535, Rev. P3, Information Systems Laboratories, Inc., Nuclear Safety 

Analysis Division, Idaho Falls, ID. Prepared for the NRC, Washington, DC, March 2003. 

2. Parzer, I., B. Mavko, and B. Krajnc, “Simulation of a Hypothetical Loss-of-Feedwater 

Accident in a Modernized Nuclear Power Plant,” Journal of Mechanical Engineering, 

2003, Vol. 49, No. 9, pp. 430–444. 

3. Prošek, A., I. Parzer, and B. Krajnc, “Simulation of Hypothetical Small-Break Loss-ofCoolant Accident in Modernized Nuclear Power Plant,” Electrotechnical Review, 2004, 

Vol. 71, No. 4, pp. 199–204. 

4. Parzer, I., “Break Model Comparison in Different RELAP5 Versions,” International 

Conference Nuclear Energy for New Europe 2003, September 8-11, 2003, Portorož, 

Slovenia, Nuclear Society of Slovenia, 2003, pp. 217.1–217.8.