# RELAP5/MOD3.3 Code Validation with Plant Abnormal Event

Authors: Andrej Prošek; Borut Mavko
Journal: Science and Technology of Nuclear Installations
 (2008)

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## Abstract

Measured plant data from various abnormal events are of great importance for code validation. The purpose of the study was to validate the RELAP5/MOD3.3 Patch 03 computer code with the abnormal event which occurred at Krško Nuclear Power Plant (NPP) on April 10, 2005. The event analyzed was a malfunction, which occurred during a power reduction sequence when regular periodic testing of the turbine valves was performed. Unexpected turbine valve closing caused safety injection signal, followed by reactor trip. The RELAP5 input model delivered by Krško NPP was used. In short term, the calculation agrees very well with the plant measured data. In the long term, this is also true when operator actions and special plant systems are modeled. In the opposite, the transient would progress quite differently. Finally, the calculated data may be supplemental to plant measured data when the information is missing or the measurement is questionable.


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## Body

## 1. Introduction

Usually the validation has been performed using experimental data
from scaled-down test facilities. Several code assessments of best estimate
codes using experimental data were reported in the literature [1, 2].
An overview on the use of experimental data in nuclear reactor thermal hydraulics
is given in [3].
Validation activities for thermal-hydraulic system codes and scaling issues are
concisely described in [4].
It is stated that for validation purposes are important especially validation
matrices of separate effects test and integral test facilities. It is also noted
that the data from NPP can be used, if available, and that the data obtained
are the ones recorded by the system of control of the plant. Typically, real
plant data are limited mostly to operational events such as malfunction of
valves, pumps, or other components, resulting in complex plant response [5–8].
However, real plant data are full scale and have true geometry; therefore they
are of great importance for code validation and for better understanding of the
unit response to deviations from normal operation.In this paper an abnormal event, which occurred at Krško Nuclear Power
Plant (NPP) on April 10, 2005, has been studied with the RELAP5/MOD3.3 Patch 03
computer code [9]. For the analysis the RELAP5 input
model delivered by Krško NPP was used.
This is a full two-loop plant model including major components of the primary
and secondary system. The limitations of the delivered model for this transient
were that the secondary
side was modeled up to the turbine only and that no auxiliary systems consuming
steam after transient were included. Namely, the steam flow is very important
for the behavior of the secondary pressure and consequently the primary
pressure. Both pressures dictate the operation of the control and safety
systems. The analysis was performed for uprated power conditions (2000 MWt)
with new steam generators and cycle 21 settings, corresponding to the plant
state after outage and refuelling in September 2004.A malfunction
occurred during a power reduction sequence when regular periodic testing of the
turbine valves was performed. This caused plant trip, while all the 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 analyze the transient and compare the
results with calculations.The analysis was
divided into five phases. The first four phases were performed to obtain steady-state
conditions. In the first phase steady state at 100% power level was
demonstrated. In the second phase the power was reduced from 100% to 91.72%
level. In the third phase one cycle of turbine governor valve closing and
opening was simulated in order to obtain as close as possible initial
conditions. In the fourth phase the steady state at
91.72% was verified by comparing calculated initial conditions with plant data,
which were available for 53 seconds before the transient start. Finally, in the
last phase the transient was analyzed for 1825 seconds as the measurement was
stopped at that time.


## 2. Input Model, Event, and Analysis Scenario Description

For the abnormal
event analysis the RELAP5/MOD3.3 Patch 03 computer code released in April 2006
was used. The basic RELAP5/MOD3.3 thermal-hydraulic model uses six equations:
two mass conservation equations, two momentum conservation equations, and two
energy conservation equations. The system of basic equations is enclosed with
empirical correlations. For more details the reader is referred to [9].


### 2.1. RELAP5 Input Model Description

To perform the analysis, Krško NPP has provided the qualified base RELAP5 input model, so-called “master input deck,”
which has been used for several analyses, including reference calculations for
Krško full scope simulator verification [10–12]. The simplified scheme of the Krško NPP nodalization
is presented in Figure 1. A full two-loop plant model, delivered by Krško NPP, has been
used for the analysis. It includes the new Siemens-Framatome replacement steam
generators type SG 72 W/D4-2. The analysis was performed for uprated power
conditions (2000 MWt) with new steam generators (SGs) and cycle 21 settings,
corresponding to the plant state after outage and refuelling in September 2004.Figure 1
Krško NPP simplified scheme.The model consists of 469 control volumes, 497 junctions, and 378
heat structures with 2107 radial mesh points. Modelled are important components
as the reactor vessel, pressurizer surge line, pressurizer (PRZ) vessel, pressurizer
spray lines and spray valves, pressurizer power operated relief valves (PORV),
and safety valves. Primary piping includes hot leg, primary side of steam
generator by inlet and outlet plenum, among which a single pipe is representing
the U-tube bundle, intermediate leg and cold leg with reactor coolant pump
(RCP). Loops are symmetrical except for the pressurizer surge line and chemical
and volume control system connections layout (charging and letdown). Modeled is
emergency cooling system (ECCS) with high-pressure injection system (HPIS),
accumulators, and low-pressure injection system (LPIS).The parts of the steam generator secondary side are represented by
riser, separator and separator pool, downcomer, and steam dome. Main steamlines
have main steam isolation valves (MSIVs), SG relief, and safety valves. Turbine
valve and steam dump flow are regulated by corresponding logic. Main feedwater
(MFW) piping is modelled till the MFW pump, which is modelled as time-dependent
junction. Auxiliary feedwater (AFW) is injecting above the SG riser.Besides, 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: rod control system, pressurizer pressure
control system, pressurizer level control system, steam generator level control
system, and steam dump.The plant
protection systems defined using trip logic include reactor trip, safety
injection (SI) signal, turbine trip, steamline isolation, main feedwater
isolation, and auxiliary feedwater start.


### 2.2. Event Description

The Krško NPP technical specifications
required that the turbine
overspeed protection system will be demonstrated operable at least once per 31
days by cycling each of the high pressure turbine governor and stop valves
trough at least one complete cycle from the running position. The test
procedure consists of two steps. In the first step the turbine (and by this
reactor power) must be reduced below 92% to fulfil the test conditions. In the
second step the test of turbine governor and stop valves is performed.In the first step
the turbine power is reduced until governor valve number 4 is closed. Then the
turbine power is reduced for another 7% until the nuclear power is less than or
equal to 92%. Then the closure of governor valves is changed from sequential to
single mode of operation. The position of governor valves is checked to be less
than or equal 35% of opening. On the opposite, the power should be additionally
reduced before the test start.In the second step
of testing turbine valves, the allowed maximum position of governor valves is
defined to be 55% of opening. To fulfil this, “valve position limit display” button
is pushed to read “flow demand” and “valve position limit.” Then the valve
position limit is raised to 160% and 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 (less than or
equal 35% of opening). When lowering valve position limit, the value should not
be below “flow demand” value. On the opposite, the governor valves start to
close. In the case of the above-described event these really happened. The
valves were closing for 5 seconds from 35.5% to 12.2% position, then
stabilized for 12 seconds, and after that the position starts to increase to
14%, followed by full valve closure. The valve positions indicate that the
operator sets the valve position limit below flow demand and after 16 seconds
he tried to restore the turbine flow. This resulted in reactor trip in next 2
seconds or less (it should be noted that data were available for each 2 seconds).
Setting the valve position limit below the flow demand was the first operator
error. When operator noticed decreased electrical power output he tried to
correct the setpoint to the desired (higher) value but he was not aware of the
steam dump operating. The increased steam flow demand resulted in the high
steam flow causing the steam generator pressure drop, therefore the SI signal
was generated on low steamline pressure. On SI signal the reactor trip signal
was generated followed by turbine trip. SI signal started also both AFW pumps
with 25 seconds delay.The measured data
were available for 1878 seconds and were sampled every 2 seconds. The data for
the first 52 seconds represent the steady state while at 54 seconds the
governing valves were already closing indicating that the transient started.
Therefore, it was assumed that governor valves started to close at 53 seconds.
This time is transient start time (t=0). The remaining data up to 1878 seconds
represent the transient, lasting 1825 seconds.


### 2.3. Analysis Scenario Description

The RELAP5/MOD3.3
Patch 03 analysis was divided into two parts. In the first part, the power was
reduced and closing and opening of governor valve was simulated. The purpose of
simulating this part was to obtain the RELAP5 initial conditions as close as
possible to the plant initial conditions before the reactor trip. It consists
of four phases as shown in Table1. In the first phase, steady state at 100% power level
was demonstrated. In the second phase, the power was reduced from 100% to
91.72% level and steady state at reduced level was demonstrated. In the third
phase, one cycle of turbine governor valve closing and opening was simulated in
order to obtain as close as possible initial conditions. In total, there are
four turbine governor valves. The stop valves were not simulated as they close
when governor control valve is fully closed. When the governor valve starts to
open, the stop valves open too. Also for the third phase, the steady state was
demonstrated. When at time −500 seconds the
time dependent junction component was replaced by valve component this caused
some transient in the steam flow. Therefore, steady-state calculation with
valve component was performed in the fourth phase at 91.72% power level, giving slightly
different plant condition because of replacing time dependent junction. This
steady state was compared with the plant data, which were available for 53 seconds
before the transient start. By simulating part 1 there was no need to use
artificial controls to achieve steady-state condition at 91.72% level. It
should be also noted that during real testing of turbine governor valve, the
position of other three governor valves is adjusted automatically to keep the
reduced power constant. Also, the plant data were not available at 100% power
to verify initial conditions before power reduction. The novel feature of the
above approach is that the initial conditions were obtained by just maneuvering
the plant, that is, opening and closing the turbine governor valve.Table 1
Subdivision of analysis.
Part of analysisPhase of analysisDescription of phase with the time of analysis durationPart 1Phase 1Steady state at 100% power (1000 seconds)Phase 2Power reduction from 100% to 91.72% for valve testing (1000 seconds)Phase 3Cycling of one turbine governor valve (1500 seconds)Phase 4Steady state at 91.72% power (500 seconds)Part 2Phase 5Turbine governor valve closure with reactor trip (1900 seconds)**measured data available for 1825 seconds.In the second
part, which is the fifth
phase, the transient leading to reactor trip and plant response to turbine and
reactor trip was simulated. The time zero was denoted for the transient start.
This means that part 1 analysis lasted from −4000 seconds to 0
second, while the
transient was analyzed from 0 second till 1900 seconds.


## 2.1. RELAP5 Input Model Description

To perform the analysis, Krško NPP has provided the qualified base RELAP5 input model, so-called “master input deck,”
which has been used for several analyses, including reference calculations for
Krško full scope simulator verification [10–12]. The simplified scheme of the Krško NPP nodalization
is presented in Figure 1. A full two-loop plant model, delivered by Krško NPP, has been
used for the analysis. It includes the new Siemens-Framatome replacement steam
generators type SG 72 W/D4-2. The analysis was performed for uprated power
conditions (2000 MWt) with new steam generators (SGs) and cycle 21 settings,
corresponding to the plant state after outage and refuelling in September 2004.Figure 1
Krško NPP simplified scheme.The model consists of 469 control volumes, 497 junctions, and 378
heat structures with 2107 radial mesh points. Modelled are important components
as the reactor vessel, pressurizer surge line, pressurizer (PRZ) vessel, pressurizer
spray lines and spray valves, pressurizer power operated relief valves (PORV),
and safety valves. Primary piping includes hot leg, primary side of steam
generator by inlet and outlet plenum, among which a single pipe is representing
the U-tube bundle, intermediate leg and cold leg with reactor coolant pump
(RCP). Loops are symmetrical except for the pressurizer surge line and chemical
and volume control system connections layout (charging and letdown). Modeled is
emergency cooling system (ECCS) with high-pressure injection system (HPIS),
accumulators, and low-pressure injection system (LPIS).The parts of the steam generator secondary side are represented by
riser, separator and separator pool, downcomer, and steam dome. Main steamlines
have main steam isolation valves (MSIVs), SG relief, and safety valves. Turbine
valve and steam dump flow are regulated by corresponding logic. Main feedwater
(MFW) piping is modelled till the MFW pump, which is modelled as time-dependent
junction. Auxiliary feedwater (AFW) is injecting above the SG riser.Besides, 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: rod control system, pressurizer pressure
control system, pressurizer level control system, steam generator level control
system, and steam dump.The plant
protection systems defined using trip logic include reactor trip, safety
injection (SI) signal, turbine trip, steamline isolation, main feedwater
isolation, and auxiliary feedwater start.


## 2.2. Event Description

The Krško NPP technical specifications
required that the turbine
overspeed protection system will be demonstrated operable at least once per 31
days by cycling each of the high pressure turbine governor and stop valves
trough at least one complete cycle from the running position. The test
procedure consists of two steps. In the first step the turbine (and by this
reactor power) must be reduced below 92% to fulfil the test conditions. In the
second step the test of turbine governor and stop valves is performed.In the first step
the turbine power is reduced until governor valve number 4 is closed. Then the
turbine power is reduced for another 7% until the nuclear power is less than or
equal to 92%. Then the closure of governor valves is changed from sequential to
single mode of operation. The position of governor valves is checked to be less
than or equal 35% of opening. On the opposite, the power should be additionally
reduced before the test start.In the second step
of testing turbine valves, the allowed maximum position of governor valves is
defined to be 55% of opening. To fulfil this, “valve position limit display” button
is pushed to read “flow demand” and “valve position limit.” Then the valve
position limit is raised to 160% and 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 (less than or
equal 35% of opening). When lowering valve position limit, the value should not
be below “flow demand” value. On the opposite, the governor valves start to
close. In the case of the above-described event these really happened. The
valves were closing for 5 seconds from 35.5% to 12.2% position, then
stabilized for 12 seconds, and after that the position starts to increase to
14%, followed by full valve closure. The valve positions indicate that the
operator sets the valve position limit below flow demand and after 16 seconds
he tried to restore the turbine flow. This resulted in reactor trip in next 2
seconds or less (it should be noted that data were available for each 2 seconds).
Setting the valve position limit below the flow demand was the first operator
error. When operator noticed decreased electrical power output he tried to
correct the setpoint to the desired (higher) value but he was not aware of the
steam dump operating. The increased steam flow demand resulted in the high
steam flow causing the steam generator pressure drop, therefore the SI signal
was generated on low steamline pressure. On SI signal the reactor trip signal
was generated followed by turbine trip. SI signal started also both AFW pumps
with 25 seconds delay.The measured data
were available for 1878 seconds and were sampled every 2 seconds. The data for
the first 52 seconds represent the steady state while at 54 seconds the
governing valves were already closing indicating that the transient started.
Therefore, it was assumed that governor valves started to close at 53 seconds.
This time is transient start time (t=0). The remaining data up to 1878 seconds
represent the transient, lasting 1825 seconds.


## 2.3. Analysis Scenario Description

The RELAP5/MOD3.3
Patch 03 analysis was divided into two parts. In the first part, the power was
reduced and closing and opening of governor valve was simulated. The purpose of
simulating this part was to obtain the RELAP5 initial conditions as close as
possible to the plant initial conditions before the reactor trip. It consists
of four phases as shown in Table1. In the first phase, steady state at 100% power level
was demonstrated. In the second phase, the power was reduced from 100% to
91.72% level and steady state at reduced level was demonstrated. In the third
phase, one cycle of turbine governor valve closing and opening was simulated in
order to obtain as close as possible initial conditions. In total, there are
four turbine governor valves. The stop valves were not simulated as they close
when governor control valve is fully closed. When the governor valve starts to
open, the stop valves open too. Also for the third phase, the steady state was
demonstrated. When at time −500 seconds the
time dependent junction component was replaced by valve component this caused
some transient in the steam flow. Therefore, steady-state calculation with
valve component was performed in the fourth phase at 91.72% power level, giving slightly
different plant condition because of replacing time dependent junction. This
steady state was compared with the plant data, which were available for 53 seconds
before the transient start. By simulating part 1 there was no need to use
artificial controls to achieve steady-state condition at 91.72% level. It
should be also noted that during real testing of turbine governor valve, the
position of other three governor valves is adjusted automatically to keep the
reduced power constant. Also, the plant data were not available at 100% power
to verify initial conditions before power reduction. The novel feature of the
above approach is that the initial conditions were obtained by just maneuvering
the plant, that is, opening and closing the turbine governor valve.Table 1
Subdivision of analysis.
Part of analysisPhase of analysisDescription of phase with the time of analysis durationPart 1Phase 1Steady state at 100% power (1000 seconds)Phase 2Power reduction from 100% to 91.72% for valve testing (1000 seconds)Phase 3Cycling of one turbine governor valve (1500 seconds)Phase 4Steady state at 91.72% power (500 seconds)Part 2Phase 5Turbine governor valve closure with reactor trip (1900 seconds)**measured data available for 1825 seconds.In the second
part, which is the fifth
phase, the transient leading to reactor trip and plant response to turbine and
reactor trip was simulated. The time zero was denoted for the transient start.
This means that part 1 analysis lasted from −4000 seconds to 0
second, while the
transient was analyzed from 0 second till 1900 seconds.


## 3. Results

Figure2 shows the
results for part 1 analysis, while Figures 2 and 3 present short and long term results
for part 2 analysis. In part 1 analysis, the power was reduced from nominal
value (100%) to test conditions at around 91.72% and opening of turbine
governor valve was simulated. In part 2 analysis, the turbine governor valve
closure with reactor trip at 91.72% power level, and associated operator
actions were simulated.Achieving steady state at
91.72%: (a) core power, (b) RCS average temperature,
(c) PRZ pressure, (d) SG 1 pressure.
(a)(b)(c)(d)Transient with reactor trip—short term: (a) core power, (b) RCS average temperature, (c) PRZ pressure, (d)
PRZ level, (e) SG 1 pressure, (f) SG 1 NR level, (g) SG1 steam flow, (h) SG 2
steam flow.
(a)(b)(c)(d)(e)(f)(g)(h)


### 3.1. Part 1 Analysis—Achieving Steady State at 91.72% Level

Figure2 shows
some important calculated variables during simulated governor valve opening and
closing and explains how initial condition at 91.72% power level was obtained.
The calculated data (labelled “RELAP5 calculation”) are shown in the time
interval (−4000 seconds–0 second) while the measured steady-state data (labelled “NPP
measurement”) were available for interval (−53 seconds–0 second) only. The power
reduction scheme was such that flow was reduced from nominal value 1086 kg/second
to 991 kg/second simulating the turbine valve test initial conditions. Then the
simulation of closing and opening of one governor valve was performed without
operating other turbine governor valves. This caused rod insertion and withdrawal.
For closing and opening, 5 minutes were assumed for 25% power reduction from
91.72% power level and 5 minutes for power increase. This is less than 5% of
nominal power per minute load reduction. In this way, the steam dump operation
was prevented. When the VALVE component was introduced back into the input
model at −3500 seconds, short oscillation is introduced which quickly stabilizes
during the fourth phase.The obtained initial
conditions are shown in Table2. The first two columns describe the plant
variables and their units. The third column shows average value of plant
measured initial condition. The data were averaged in the time interval (−53 seconds–0 second) because the measured values were slightly oscillating
for some variables. The time 0 second was chosen as start of reactor trip
transient. For this time, the plant measured initial conditions are given in
the fourth column, which in some cases differ from average steady-state values.
In the fourth column is given design accuracy for the measured channels. The
design accuracy can be obtained by calibrating the channels. The real accuracy
is lower as time drift and environmental effect should be taken into account
too. Finally, in the last three columns steady-state values at the end of the second, the third, and the
fourth phases are given. In the sixth column are given calculated
initial conditions after initial power reduction below 92% (rod insertion at
time −2000 seconds), in
the seventh initial conditions after rods withdrawal (at time −500 seconds), and
in the last column the initial conditions at the time of transient start (t=0).
When comparing the RELAP5 initial conditions with measured initials conditions,
with the exception of feedwater flow for loop 2, all values are within design
accuracy.Table 2
Initial conditions for reactor trip transient.
VariablesUnitMeasuredMeasuredDesignCalculatedCalculatedCalculated(average)(t=0 second)accuracy(t=−2000 seconds)(t=−500 seconds)(t=0 second)Pressurizer pressureMPa15.4815.48± 0.37 %15.5215.5115.52SG 1 pressureMPa6.426.42± 0.37 %6.596.436.47SG 2 pressureMPa6.406.40± 0.37 %6.576.426.45Feedwater 1 mass flow ratekg/s499.0504.0± 0.38 %495.2495.4495.5Feedwater 2 mass flow ratekg/s503.6500.6± 0.38 %497.7498.1498.1Main steamline 1 mass flowratekg/s493.9492.6± 0.46 %495.2495.4495.4Main steamline 2 mass flowratekg/s501.6501.5± 0.46 %497.8498.1498.1Pressurizer liquid level%53.0252.95± 0.37 %56.1051.8852.63Steam generator 1 NR level%69.2569.15± 0.37 %69.3469.2669.28Steam generator 2 NR level%69.0669.40± 0.37 %69.3469.2569.28Nuclear power%91.7291.94± 0.26 %91.6391.7891.77Cold leg 1 temperatureK559.41559.36± 0.29 %560.74559.15559.51Cold leg 2 temperatureK559.57559.53± 0.29 %560.59558.99559.35Hot leg 1 temperatureK593.92593.73± 0.29 %594.64593.23593.55Hot leg 2 temperatureK594.58594.62± 0.29 %594.64593.23593.55Average RCS 1 temperatureK576.63576.52± 0.32 %577.69576.19576.53Average RCS 2 temperatureK577.05577.05± 0.32 %577.62576.11576.45Programed TavgK576.90576.90± 0.39 %576.97576.97577.00Please note that for power reduction, the turbine flow was modeled by RELAP5 component TMDPJUN, with
which linear flow decrease and increase can be prescribed. The benefit of
having linear power decrease was to see how the plant would respond to linear
power decrease, what would be very difficult with the VALVE component (valve
opening is not linear with the steam flow). It should be noted, that this does
not happened in the plant, but was just the tactics for achieving steady-state
conditions. The nonlinear closing and opening could be performed by VALVE component
too, but it would require more time as 5%/minute decrease is the maximum
allowed load reduction. Another steady state had to be calculated when TMDPJUN
component was replaced by VALVE component representing turbine governor valves.The reason why
simple power reduction scheme was not performed to reduce the power from 100%
to 91.72% was that in the case of just lowering the power to 91.72% by
inserting rods due to power mismatch between reactor power and turbine power
some initial conditions are different from initial conditions when withdrawing
rods (see Figures2(b) and 2(d)). The reason is the deadband in the
temperature error signal (between the reference temperature and the
auctioneered average reactor coolant system (RCS) temperature). The difference
when the rods stop to move in and start to move out is 1.4 K. Such a difference
causes difference in the pressure on the secondary side too (1 K temperature
change corresponds to 0.125 MPa pressure change).Due to rod movement, the reactor power changes as it is shown in Figure2(a), following
the turbine power, which is modelled as a linear function of turbine flow. The
RCS average temperature did not decrease immediately as expected when power was
decreased but increased in the initial 150 seconds of the second phase (till −2850 seconds) due
to delay caused by a combination of loop transport time, resistance temperature
detectors manifold arrangement, and instrument processing time (see Figure 2(b)).
Then the temperature started to linearly drop to new steady-state value. Same
phenomenon repeated at the beginning of the third phase (temperature increase with later
decrease). When power is increased the opposite happened. The temperature first
decreased and then started to increase at −1530 seconds (the
turbine governor valve starts to open at −1700 seconds).Proportional
heaters compensate the pressurizer pressure during power changes. During power
decrease, the pressure initially increases and then returns to its nominal
value, and vice versa during power increase (see Figure2(c)). Finally, the
steam generator 1 pressure shown in Figure 2(d) is increasing during turbine
valve closing and decreasing during turbine valve opening. When the turbine
valve stops to move, the SG pressure changes the direction and stabilizes at
certain value depending on the value of RCS average temperature.


### 3.2. Part 2 Analysis–Transient with Reactor Trip

The time sequence
of main events during the transient is shown in Table3. This time sequence was determined based on the
measured data of plant variables. The measured data showed that the turbine
governor valves were closing for 5 seconds from 35.5% to 12.2% position, and
then stabilized for 12 seconds. When the position starts to increase to 14%
(opening caused by operator), there was full closure of turbine valves. The
power level showed that the reactor was tripped. The reason for the reactor
trip was low steamline pressure generating SI signal. The low steamline
pressure signal resulted from the turbine flow increase. As at 15 seconds, the
valve position was 12.2% and at 17 seconds was already 14.1% it was assumed
that operator starts to open the turbine governor valves at 16 seconds. On SI
signal also main feedwater isolation and main steamline isolation valve signal
are generated, SI pump is actuated, and letdown and charging are isolated.Table 3
Time sequence of main events during transient.
EventMeasurementCalculationTurbine flow reduction0 second–5 seconds0 second–5 secondsOperator action (start of governor valve opening)16 seconds16 secondsSI signal on low steamline pressure17 seconds*16.7 secondsSI pump injection start21 seconds22 secondsSG power operated relief valve (PORV) opening27 seconds31 secondsAFW flow actuation42 seconds42 seconds*based on 25 seconds delay of AFW actuation.It should be noted
that the sequence of events was determined from the measured data, which were
used for the plots; 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 delay in signals and rod drop time is not
exactly known.To obtain the
correct time sequence of events in short term, it was needed to model the
operator actions, resulting in closure and subsequent opening of turbine
governor valve. How this influences the steam mass flows from the steam
generators number 1 and 2, is shown in Figures3(g) and 3(h), respectively. Please
note that steam flow in the calculations depends on the position of turbine
valves and SG PORVs. In the calculation, the turbine valves were closed at 20 seconds
while the SG PORVs open at 27 seconds. After the trip, the calculated steam
flow was smaller than in the plant. From the measured data, it could be
concluded that steam dump was operating after turbine governor valve closure.
In the RELAP5 model these systems were not modelled in detail what resulted in
small differences.Figure3(a) shows
the power drop when the reactor is tripped. The measurement of power range
channel is based on the neutron flux. After reactor shutdown, only a part of
decay heat is due to neutron flux from delayed neutrons and spontaneous fission
neutrons. Decay heat comes also from other sources as unstable fission products
and unstable actinides. Therefore, the measured neutron flux is lower than in
the reality and this is the major reason for disagreement with the calculation.
The decay heat is simulated with RELAP5 while the measured data do not show
correctly this decay.The RCS average
temperature is shown in Figure3(b). After transient initiation, the
temperature starts to increase until reactor is tripped in 17 seconds. Then the
temperature is a function of cooling the primary system (by primary side
injection) and the secondary heat sink.In Figure3(c) is
shown pressurizer pressure. The initial pressure increase is calculated very well.
The pressure is rapidly increasing until the pressurizer sprays are actuated.
It can be seen that proportional sprays”. very efficiently
reduce the pressure increase before reactor trip. When the reactor is tripped,
the pressurizer pressure further decreased. Initial agreement is very good
including peak pressure. However, it can be seen that after 25 seconds the
calculated pressure shows repressurization of the primary system. The reason is
the difference between calculated and measured steam flows (see Figures 3(g)
and 3(h)). It should be noted that in the calculation position of turbine
governor valve was simulated till 17 seconds when the valve closed on turbine
trip in 3 seconds, while from the plant measured data, the steam flows start to
drop at 21 seconds. In the case of calculation termination of steam flow caused
SG pressure increase what deteriorated cooling of the primary side resulting in
repressurization. However, when secondary side cooling was re-established by SG
PORV opening at 27 seconds, the RCS pressure starts to decrease again. In
addition, some cooling on the primary side was established by HPIS injection,
while in the calculation the injection started in 50 seconds. No adjustment was
made in the input model to tune the HPIS injection, SG PORV operation, and
steam flows.The steam
generator pressure was calculated very well as shown in Figure3(e). The first
SG pressure peak is due to governor valve closure and the second peak due to
the turbine trip. When the operator opened the turbine governor valves, the SG
pressure after first peak started to decrease; therefore, SI signal was
generated on low steamline pressure. The second peak caused the SG PORV valve
opening.The steam
generator levels also agree well initially as shown in Figure3(f). The reactor
trip caused turbine trip and main feedwater isolation. The closure of the
turbine valves and core heat transferred to the steam generators resulted in
the steam pressure increase (see Figure 3(e)), which had a shrink effect on the
steam generator level instrumentation. On SI signal with 25 seconds delay, the
AFW injection was started removing the decay heat and filling the steam
generators. Following the main feedwater isolation, the steam generator level
is affected by auxiliary feedwater and released steam. However, it was observed
that in the time period from 26 seconds to 73 seconds, when SG PORV 1 is
operated, the calculated level is higher than the measured data. An explanation
for this behavior could be in the RELAP5 input model; the damping of the
oscillating water flow between the downcomer and the riser in the steam
generators is underpredicted.In the long term,
the secondary pressure dictates the transient progression. The measured data
for AFW flow were used in the calculation to simulate the operation of AFW
pumps. To obtain exact match of SG pressures, small steam flow was modeled also
as indicated by the measured data (see Figures4(g) and 4(h)). Namely, the
plant is designed such that after the main steamline isolation after the
turbine trip there is some steam flow to the gland steam system. The steam in
the steam generators is generated based on the available heat (mostly decay
heat). From Figure 4(h), it can be seen that the measured value of steam flow
is much higher than the maximum value of generated steam for one steam
generator (label “calculation limiting”). Therefore, the steam flow was tuned
in such a way to obtain as much as possible good agreement of SG pressures. The
value of steam flows in the calculation is physically feasible, but it is not
known if it was so in the reality. Also, the transient is very sensitive to
this variable. Without assuming any steam flow after reactor trip or assuming
measured data for steam flow, the SG pressure would be overpredicted (requiring
SG PORV opening) or underpredicted. In the case of tuning steam flows all other
calculated variables are in excellent agreement with the measured variables as
shown in Figure 4. The measurement of power range channel is based on the
neutron flux as already mentioned; therefore, the measured data are lower than
the calculated power based on the decay heat (Figure 4(a)). Due to the steam
generator pressure tuning (Figure 4(e)) also the RCS average temperature (Figure
4(b)) and SG level (Figure 4(f)) are closely matched. There is some discrepancy
in the pressurizer pressure and level (Figures 4(c) and 4(d)) because the SI
flow in the calculation was different from the measured data. It was decided
not to tune the calculated SI flow to the measured data (SI pumps operated approx.
5 minutes). Later, the primary system is filled by operation of pressurizer
sprays and charging flow.Transient with reactor trip—long term: (a) core
power, (b) RCS average temperature, (c) PRZ pressure, (d) PRZ level, (e) SG 1
pressure, (f) SG 1 NR level, (g) SG1 steam flow, (h) SG2 steam flow.
(a)(b)(c)(d)(e)(f)(g)(h)Important was the
finding that RELAP5 computer code calculation suggests some steam flow and
later it was found out that there is some larger steam flow to the gland steam
system in a special case of steamline isolation after turbine trip, which
occurred in the analyzed event. Namely, the gland steam system was not included
in the base RELAP5 input model.


### 3.3. Quantitative Assessment

The obtained results shown in Figure4 were quantitatively assessed
using fast Fourier transform based method (FFTBM). Both the original FFTBM [13] and improved FFTBM by
signal mirroring were used [14]. Simplified quantitative assessment
by applying FFTBM was done to confirm the conclusions done based on the
analysis above. The readers not familiar with FFTBM can refer to references [1, 14]. For the purpose of this paper, it is important to
know that lower is the average amplitude (AA), higher is the accuracy and that
total accuracy below 0.3 means very good calculation. For primary pressure the AA
below 0.1 means acceptable accuracy. Table 4 shows the AA for three time
intervals, the time interval (−20 seconds–0 second) for steady state, short-term (0 second–80 seconds), and long-term (0 second–1800 seconds) results.Table 4
Quantitative results for different time intervals.
Original FFTBMFFTBM by signal mirroringAAAAAAAAAAAA(−20 seconds–(0 second–(0 second–(−20 seconds–(0 second–(0 second–0 second)80 seconds)1800 seconds)0 second)80 seconds)1800 seconds)Core power0.0050.2390.2340.0070.3060.304RCS average temperature0.0000.0080.0090.0000.0100.010PRZ pressure0.0030.0410.0550.0030.0500.067PRZ level0.0080.1440.5060.0080.1800.450SG 1 pressure0.0100.0870.0790.0100.1150.106SG 1 NR level0.0050.2360.2770.0060.3500.330SG 1 steam flow0.0180.7040.6940.0200.8950.879SG 2 steam flow0.0220.6550.6520.0220.7800.787The results for time interval (−20 seconds–0 second) showed that the
initial condition is very well predicted. This confirms the results in Table2,
where it is shown that all variables shown in Table 4 are within design
accuracy of measuring channels. For the short- and long-term calculation the
accuracy is rather similar, indicating very good calculation. When comparing
original FFTBM and improved FFTBM by signal mirroring, as expected the differences
are due to the unphysical edge effect (difference between the first and last
data point of the signal) contributing to frequency spectrum in the original
FFTBM. When edge is present in the experimental (measured) signal, this gives
lower AA in the case of original FFTBM, that is, core power and steam generator
narrow range level. For information, how edge effect could be eliminated by
signal mirroring, the reader can refer to [14].


## 3.1. Part 1 Analysis—Achieving Steady State at 91.72% Level

Figure2 shows
some important calculated variables during simulated governor valve opening and
closing and explains how initial condition at 91.72% power level was obtained.
The calculated data (labelled “RELAP5 calculation”) are shown in the time
interval (−4000 seconds–0 second) while the measured steady-state data (labelled “NPP
measurement”) were available for interval (−53 seconds–0 second) only. The power
reduction scheme was such that flow was reduced from nominal value 1086 kg/second
to 991 kg/second simulating the turbine valve test initial conditions. Then the
simulation of closing and opening of one governor valve was performed without
operating other turbine governor valves. This caused rod insertion and withdrawal.
For closing and opening, 5 minutes were assumed for 25% power reduction from
91.72% power level and 5 minutes for power increase. This is less than 5% of
nominal power per minute load reduction. In this way, the steam dump operation
was prevented. When the VALVE component was introduced back into the input
model at −3500 seconds, short oscillation is introduced which quickly stabilizes
during the fourth phase.The obtained initial
conditions are shown in Table2. The first two columns describe the plant
variables and their units. The third column shows average value of plant
measured initial condition. The data were averaged in the time interval (−53 seconds–0 second) because the measured values were slightly oscillating
for some variables. The time 0 second was chosen as start of reactor trip
transient. For this time, the plant measured initial conditions are given in
the fourth column, which in some cases differ from average steady-state values.
In the fourth column is given design accuracy for the measured channels. The
design accuracy can be obtained by calibrating the channels. The real accuracy
is lower as time drift and environmental effect should be taken into account
too. Finally, in the last three columns steady-state values at the end of the second, the third, and the
fourth phases are given. In the sixth column are given calculated
initial conditions after initial power reduction below 92% (rod insertion at
time −2000 seconds), in
the seventh initial conditions after rods withdrawal (at time −500 seconds), and
in the last column the initial conditions at the time of transient start (t=0).
When comparing the RELAP5 initial conditions with measured initials conditions,
with the exception of feedwater flow for loop 2, all values are within design
accuracy.Table 2
Initial conditions for reactor trip transient.
VariablesUnitMeasuredMeasuredDesignCalculatedCalculatedCalculated(average)(t=0 second)accuracy(t=−2000 seconds)(t=−500 seconds)(t=0 second)Pressurizer pressureMPa15.4815.48± 0.37 %15.5215.5115.52SG 1 pressureMPa6.426.42± 0.37 %6.596.436.47SG 2 pressureMPa6.406.40± 0.37 %6.576.426.45Feedwater 1 mass flow ratekg/s499.0504.0± 0.38 %495.2495.4495.5Feedwater 2 mass flow ratekg/s503.6500.6± 0.38 %497.7498.1498.1Main steamline 1 mass flowratekg/s493.9492.6± 0.46 %495.2495.4495.4Main steamline 2 mass flowratekg/s501.6501.5± 0.46 %497.8498.1498.1Pressurizer liquid level%53.0252.95± 0.37 %56.1051.8852.63Steam generator 1 NR level%69.2569.15± 0.37 %69.3469.2669.28Steam generator 2 NR level%69.0669.40± 0.37 %69.3469.2569.28Nuclear power%91.7291.94± 0.26 %91.6391.7891.77Cold leg 1 temperatureK559.41559.36± 0.29 %560.74559.15559.51Cold leg 2 temperatureK559.57559.53± 0.29 %560.59558.99559.35Hot leg 1 temperatureK593.92593.73± 0.29 %594.64593.23593.55Hot leg 2 temperatureK594.58594.62± 0.29 %594.64593.23593.55Average RCS 1 temperatureK576.63576.52± 0.32 %577.69576.19576.53Average RCS 2 temperatureK577.05577.05± 0.32 %577.62576.11576.45Programed TavgK576.90576.90± 0.39 %576.97576.97577.00Please note that for power reduction, the turbine flow was modeled by RELAP5 component TMDPJUN, with
which linear flow decrease and increase can be prescribed. The benefit of
having linear power decrease was to see how the plant would respond to linear
power decrease, what would be very difficult with the VALVE component (valve
opening is not linear with the steam flow). It should be noted, that this does
not happened in the plant, but was just the tactics for achieving steady-state
conditions. The nonlinear closing and opening could be performed by VALVE component
too, but it would require more time as 5%/minute decrease is the maximum
allowed load reduction. Another steady state had to be calculated when TMDPJUN
component was replaced by VALVE component representing turbine governor valves.The reason why
simple power reduction scheme was not performed to reduce the power from 100%
to 91.72% was that in the case of just lowering the power to 91.72% by
inserting rods due to power mismatch between reactor power and turbine power
some initial conditions are different from initial conditions when withdrawing
rods (see Figures2(b) and 2(d)). The reason is the deadband in the
temperature error signal (between the reference temperature and the
auctioneered average reactor coolant system (RCS) temperature). The difference
when the rods stop to move in and start to move out is 1.4 K. Such a difference
causes difference in the pressure on the secondary side too (1 K temperature
change corresponds to 0.125 MPa pressure change).Due to rod movement, the reactor power changes as it is shown in Figure2(a), following
the turbine power, which is modelled as a linear function of turbine flow. The
RCS average temperature did not decrease immediately as expected when power was
decreased but increased in the initial 150 seconds of the second phase (till −2850 seconds) due
to delay caused by a combination of loop transport time, resistance temperature
detectors manifold arrangement, and instrument processing time (see Figure 2(b)).
Then the temperature started to linearly drop to new steady-state value. Same
phenomenon repeated at the beginning of the third phase (temperature increase with later
decrease). When power is increased the opposite happened. The temperature first
decreased and then started to increase at −1530 seconds (the
turbine governor valve starts to open at −1700 seconds).Proportional
heaters compensate the pressurizer pressure during power changes. During power
decrease, the pressure initially increases and then returns to its nominal
value, and vice versa during power increase (see Figure2(c)). Finally, the
steam generator 1 pressure shown in Figure 2(d) is increasing during turbine
valve closing and decreasing during turbine valve opening. When the turbine
valve stops to move, the SG pressure changes the direction and stabilizes at
certain value depending on the value of RCS average temperature.


## 3.2. Part 2 Analysis–Transient with Reactor Trip

The time sequence
of main events during the transient is shown in Table3. This time sequence was determined based on the
measured data of plant variables. The measured data showed that the turbine
governor valves were closing for 5 seconds from 35.5% to 12.2% position, and
then stabilized for 12 seconds. When the position starts to increase to 14%
(opening caused by operator), there was full closure of turbine valves. The
power level showed that the reactor was tripped. The reason for the reactor
trip was low steamline pressure generating SI signal. The low steamline
pressure signal resulted from the turbine flow increase. As at 15 seconds, the
valve position was 12.2% and at 17 seconds was already 14.1% it was assumed
that operator starts to open the turbine governor valves at 16 seconds. On SI
signal also main feedwater isolation and main steamline isolation valve signal
are generated, SI pump is actuated, and letdown and charging are isolated.Table 3
Time sequence of main events during transient.
EventMeasurementCalculationTurbine flow reduction0 second–5 seconds0 second–5 secondsOperator action (start of governor valve opening)16 seconds16 secondsSI signal on low steamline pressure17 seconds*16.7 secondsSI pump injection start21 seconds22 secondsSG power operated relief valve (PORV) opening27 seconds31 secondsAFW flow actuation42 seconds42 seconds*based on 25 seconds delay of AFW actuation.It should be noted
that the sequence of events was determined from the measured data, which were
used for the plots; 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 delay in signals and rod drop time is not
exactly known.To obtain the
correct time sequence of events in short term, it was needed to model the
operator actions, resulting in closure and subsequent opening of turbine
governor valve. How this influences the steam mass flows from the steam
generators number 1 and 2, is shown in Figures3(g) and 3(h), respectively. Please
note that steam flow in the calculations depends on the position of turbine
valves and SG PORVs. In the calculation, the turbine valves were closed at 20 seconds
while the SG PORVs open at 27 seconds. After the trip, the calculated steam
flow was smaller than in the plant. From the measured data, it could be
concluded that steam dump was operating after turbine governor valve closure.
In the RELAP5 model these systems were not modelled in detail what resulted in
small differences.Figure3(a) shows
the power drop when the reactor is tripped. The measurement of power range
channel is based on the neutron flux. After reactor shutdown, only a part of
decay heat is due to neutron flux from delayed neutrons and spontaneous fission
neutrons. Decay heat comes also from other sources as unstable fission products
and unstable actinides. Therefore, the measured neutron flux is lower than in
the reality and this is the major reason for disagreement with the calculation.
The decay heat is simulated with RELAP5 while the measured data do not show
correctly this decay.The RCS average
temperature is shown in Figure3(b). After transient initiation, the
temperature starts to increase until reactor is tripped in 17 seconds. Then the
temperature is a function of cooling the primary system (by primary side
injection) and the secondary heat sink.In Figure3(c) is
shown pressurizer pressure. The initial pressure increase is calculated very well.
The pressure is rapidly increasing until the pressurizer sprays are actuated.
It can be seen that proportional sprays”. very efficiently
reduce the pressure increase before reactor trip. When the reactor is tripped,
the pressurizer pressure further decreased. Initial agreement is very good
including peak pressure. However, it can be seen that after 25 seconds the
calculated pressure shows repressurization of the primary system. The reason is
the difference between calculated and measured steam flows (see Figures 3(g)
and 3(h)). It should be noted that in the calculation position of turbine
governor valve was simulated till 17 seconds when the valve closed on turbine
trip in 3 seconds, while from the plant measured data, the steam flows start to
drop at 21 seconds. In the case of calculation termination of steam flow caused
SG pressure increase what deteriorated cooling of the primary side resulting in
repressurization. However, when secondary side cooling was re-established by SG
PORV opening at 27 seconds, the RCS pressure starts to decrease again. In
addition, some cooling on the primary side was established by HPIS injection,
while in the calculation the injection started in 50 seconds. No adjustment was
made in the input model to tune the HPIS injection, SG PORV operation, and
steam flows.The steam
generator pressure was calculated very well as shown in Figure3(e). The first
SG pressure peak is due to governor valve closure and the second peak due to
the turbine trip. When the operator opened the turbine governor valves, the SG
pressure after first peak started to decrease; therefore, SI signal was
generated on low steamline pressure. The second peak caused the SG PORV valve
opening.The steam
generator levels also agree well initially as shown in Figure3(f). The reactor
trip caused turbine trip and main feedwater isolation. The closure of the
turbine valves and core heat transferred to the steam generators resulted in
the steam pressure increase (see Figure 3(e)), which had a shrink effect on the
steam generator level instrumentation. On SI signal with 25 seconds delay, the
AFW injection was started removing the decay heat and filling the steam
generators. Following the main feedwater isolation, the steam generator level
is affected by auxiliary feedwater and released steam. However, it was observed
that in the time period from 26 seconds to 73 seconds, when SG PORV 1 is
operated, the calculated level is higher than the measured data. An explanation
for this behavior could be in the RELAP5 input model; the damping of the
oscillating water flow between the downcomer and the riser in the steam
generators is underpredicted.In the long term,
the secondary pressure dictates the transient progression. The measured data
for AFW flow were used in the calculation to simulate the operation of AFW
pumps. To obtain exact match of SG pressures, small steam flow was modeled also
as indicated by the measured data (see Figures4(g) and 4(h)). Namely, the
plant is designed such that after the main steamline isolation after the
turbine trip there is some steam flow to the gland steam system. The steam in
the steam generators is generated based on the available heat (mostly decay
heat). From Figure 4(h), it can be seen that the measured value of steam flow
is much higher than the maximum value of generated steam for one steam
generator (label “calculation limiting”). Therefore, the steam flow was tuned
in such a way to obtain as much as possible good agreement of SG pressures. The
value of steam flows in the calculation is physically feasible, but it is not
known if it was so in the reality. Also, the transient is very sensitive to
this variable. Without assuming any steam flow after reactor trip or assuming
measured data for steam flow, the SG pressure would be overpredicted (requiring
SG PORV opening) or underpredicted. In the case of tuning steam flows all other
calculated variables are in excellent agreement with the measured variables as
shown in Figure 4. The measurement of power range channel is based on the
neutron flux as already mentioned; therefore, the measured data are lower than
the calculated power based on the decay heat (Figure 4(a)). Due to the steam
generator pressure tuning (Figure 4(e)) also the RCS average temperature (Figure
4(b)) and SG level (Figure 4(f)) are closely matched. There is some discrepancy
in the pressurizer pressure and level (Figures 4(c) and 4(d)) because the SI
flow in the calculation was different from the measured data. It was decided
not to tune the calculated SI flow to the measured data (SI pumps operated approx.
5 minutes). Later, the primary system is filled by operation of pressurizer
sprays and charging flow.Transient with reactor trip—long term: (a) core
power, (b) RCS average temperature, (c) PRZ pressure, (d) PRZ level, (e) SG 1
pressure, (f) SG 1 NR level, (g) SG1 steam flow, (h) SG2 steam flow.
(a)(b)(c)(d)(e)(f)(g)(h)Important was the
finding that RELAP5 computer code calculation suggests some steam flow and
later it was found out that there is some larger steam flow to the gland steam
system in a special case of steamline isolation after turbine trip, which
occurred in the analyzed event. Namely, the gland steam system was not included
in the base RELAP5 input model.


## 3.3. Quantitative Assessment

The obtained results shown in Figure4 were quantitatively assessed
using fast Fourier transform based method (FFTBM). Both the original FFTBM [13] and improved FFTBM by
signal mirroring were used [14]. Simplified quantitative assessment
by applying FFTBM was done to confirm the conclusions done based on the
analysis above. The readers not familiar with FFTBM can refer to references [1, 14]. For the purpose of this paper, it is important to
know that lower is the average amplitude (AA), higher is the accuracy and that
total accuracy below 0.3 means very good calculation. For primary pressure the AA
below 0.1 means acceptable accuracy. Table 4 shows the AA for three time
intervals, the time interval (−20 seconds–0 second) for steady state, short-term (0 second–80 seconds), and long-term (0 second–1800 seconds) results.Table 4
Quantitative results for different time intervals.
Original FFTBMFFTBM by signal mirroringAAAAAAAAAAAA(−20 seconds–(0 second–(0 second–(−20 seconds–(0 second–(0 second–0 second)80 seconds)1800 seconds)0 second)80 seconds)1800 seconds)Core power0.0050.2390.2340.0070.3060.304RCS average temperature0.0000.0080.0090.0000.0100.010PRZ pressure0.0030.0410.0550.0030.0500.067PRZ level0.0080.1440.5060.0080.1800.450SG 1 pressure0.0100.0870.0790.0100.1150.106SG 1 NR level0.0050.2360.2770.0060.3500.330SG 1 steam flow0.0180.7040.6940.0200.8950.879SG 2 steam flow0.0220.6550.6520.0220.7800.787The results for time interval (−20 seconds–0 second) showed that the
initial condition is very well predicted. This confirms the results in Table2,
where it is shown that all variables shown in Table 4 are within design
accuracy of measuring channels. For the short- and long-term calculation the
accuracy is rather similar, indicating very good calculation. When comparing
original FFTBM and improved FFTBM by signal mirroring, as expected the differences
are due to the unphysical edge effect (difference between the first and last
data point of the signal) contributing to frequency spectrum in the original
FFTBM. When edge is present in the experimental (measured) signal, this gives
lower AA in the case of original FFTBM, that is, core power and steam generator
narrow range level. For information, how edge effect could be eliminated by
signal mirroring, the reader can refer to [14].


## 4. Conclusions

In this study, plant
measured data for abnormal event resulting in the reactor trip at Krško NPP were used
for validation of the RELAP5/MOD3.3 Patch 03 computer code. The analysis was
divided into two parts. In the first part, an approach by maneuvering the plant
was proposed to achieve steady-state conditions. In the second part, the
turbine governor valve closure with reactor trip and the associated operator
actions were simulated.The calculated
initial conditions at 91.72% power level were achieved close to the plant initial
conditions by just maneuvering the plant. These results suggest that the input
model for RELAP5 code is a good representation of the plant. The results of the
abnormal event analysis showed good agreement between the calculated and
measured data in the short term. This is true also for long term when operator
actions are properly modeled.The limitation of
the plant measured data for code validation is that some information was not
available or reliable. Namely, the calculated results showed that the transient
evolution is very sensitive to the steam flow after reactor trip. In the short
term, it would be very valuable to have separate measurements of steam flow to
steam dump and through SG relief valve. This would clarify differences in flow
a few seconds after reactor trip. Important is the finding that in the long term
the measured data indicate steam flow after main steamline isolation. To match
the secondary pressure also RELAP5 computer code calculation suggests some
steam flow. After investigating design documentation it was found out that
there is some steam flow to the gland steam system in a special case of
steamline isolation after turbine trip, which occurred in the analyzed event.
Namely, the gland steam system was not included in the base RELAP5 input model.
But, the study of maximum steam generated based on decay heat showed that
measurement of steam flow was not reliable. Therefore, the steam flow was tuned
in such a way to obtain close agreement between the calculated and measured
steam generator pressure. In this way also all other plant variables agree very
well with the plant measured data.In general, the conclusion is that
the RELAP5/MOD3.3 Patch 03 computer code is capable of simulating the abnormal event but it
requires qualified input model. In the presented study, proper modelling of
operator actions and gland steam system is needed to obtain good quantitative agreement.
Finally, the calculated data may be supplemental to the plant measured data
when the information is missing or the measurement is questionable.



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*Source: 745178-2008-07-15.xml*