Distribution grid capacity for reactive power support

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IN

DEGREE PROJECT ELECTRICAL ENGINEERING, SECOND CYCLE, 30 CREDITS

STOCKHOLM SWEDEN 2017,

Distribution grid capacity for reactive power support

EYSTEINN EIRÍKSSON

KTH ROYAL INSTITUTE OF TECHNOLOGY SCHOOL OF ELECTRICAL ENGINEERING

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Distribution grid capability for reactive power support

Eysteinn Eiríksson

Master Thesis, 2017

KTH - Royal Institute of Technology

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Abstract

The modern power system is changing at a rate faster than would have been expected 20 years ago. More and more conventional power plants will be shut down in favour of distribution generation (DG). This is happening now with the trend of introducing renewable energy sources (RES) to the power system.

The grids were designed to transfer power from generating units connected to the high voltage grids towards the end consumers connected to the low voltage grids. With changed power mix, power flows in the system will change resulting in possible grid problems. One of the main problems is keeping the voltage within operational limits of the system. When the generation exceeds the consumption in a distribution network, the power will flow from the low voltage network towards the high voltage network (reverse power flow) which will cause the voltage to rise in the low voltage network. Reactive power support from DG can be a valuable resource to mitigate the problem. Reactive power is necessary to operate the power system. The main source of reactive power is synchronous generators. If this source is shut down, the reactive power must come from another source.

This thesis investigates if DG could be used to support reactive power to the high voltage transmission network to control the voltage. For this purpose, a distribution system located close to Worms, Germany will be studied. This distribution system consists of two MV feeders with high penetration of DG, mostly photovoltaic (PV) but also wind turbines (WT). Consumption and generation measurement data was provided by the local distribution system operator (DSO). A few reactive power control methods are introduced and tested on this system. From the results, it is concluded that it is possible to provide reactive power support from distribution networks and a voltage dependent reactive power control can be used to this purpose.

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1 Sammanfattning

Det moderna kraftsystemet förandras snabbara än vad som hade förväntats för 20 år sedan. Fler och fler konventionella kraftverk kommer att stängas till fördel för distributionsgenering. Detta händer nu med trenden att introducera förnybara energikällor till kraftsystemet.

Nätverket utformades för att överföra kraft från generatorer som är anslutna till högspän- ningsnätet mot konsumenter anslutna till lågspänningsnätet. Med ändrad kraftblandning kommer strömflödena i systemet att förändras vilket resulterar i eventuella nätproblem.

Ett av huvudproblemen är att hålla spänningen inom operativa gränser för systemet.

När generationen överstiger förbrukningen i ett distributionsnät, kommer strömmen att strömma från lågspänningsnätet till högspänningsnätet vilket kommer att leda till att spänningen stiger i lågspänningsnätet. Reaktivt kraftstöd från distributionsgenering kan vara en värdefull resurs för att mildra problemet. Reaktiv effekt är nödvändig för att driva elsystemet. Huvudkällan för reaktiv kraft är synkrona generatorer. Om den här källan stängs av måste den reaktiva effekten komma från en annan källa.

Denna avhandling undersöker om distributionsgenering skulle kunna användas för att stödja reaktiv kraft till högspänningsöverföringsnätet för att styra spänningen. För detta ändamål studeras ett distributionssystem som ligger nära Worms, Tyskland. Detta distributionssystem består av två MV-matare med med mycket distributionsgenerering, främst solceller men även vindturbiner. Förbruknings- och generationsmätningsdata tillhan- dahölls av den lokala distributionssystemoperatören. Några reaktiva effektstyrningsme- toder introduceras och testas på detta system. Av resultaten dras slutsatsen att det är möjligt att tillhandahålla reaktivt kraftstöd från distributionsnät och en spännings- beroende reaktiv effektstyrning kan användas för detta ändamål.

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2 Acknowledgement

I would like to thank my supervisors, Stefan Stankovic and Poria Hasanpor Divshali, at the Department of Electric Power and Energy Systems for excellent supervision during this project. I would also like to thank Lennart Söder at the Department of Electric Power and Energy Systems for useful advice and for being my exminer. Lastly, I would like to thank my friends and family for endless support throughout the progression of this project.

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Abbreviations and Symbols

DG Distributed Generation HV High Voltage

MV Medium Voltage LV Low Voltage PV Photovoltaic Q Reactive power

SUS Secondary Unit Substation (MV to LV) WT Wind Turbine

p.f. Power factor

OLTC On-Load Tap Changer p.u. Per unit

NLTC No-Load Tap Changer DSO Distribution System Operator

cap. Capacitive power factor (generating Q) ind. Inductive power factor (consuming Q) RES Renewable Energy Sources

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3 Introduction

Distribution generation sources (DG) are becoming an increasingly important factor in the active power production in power systems. One of the main sources of reactive power are synchronous generators. With increasing renewable energy sources (RES) connected to the distribution grid, these synchronous generators will be shut down one by one. With growing demand of stable electric power, reactive power importance is increasing. If one of the main source of reactive power is going away, there is a need for another source of reactive power. In this thesis, DG will be proposed as a new source of reactive power. It will be investigated if and to what extent the distribution grid is capable of providing reactive power support. One of the problems with a large penetration of DG in low voltage networks is operating within voltage limits. DGs can cause reverse power flows and over-voltage in the low voltage grid. Reactive power support can be used to mitigate this problem. The main objective of this thesis is to investigate if DG is capable to provide reactive power support for voltage control in the overlaying grids, i.e. high voltage transmission grid, while still operating within voltage limits.

A real German distribution grid with a high penetration of DG (mainly photovoltaic (PV) but also wind turbines (WT)) is used to analyse this problem. This distribution grid was modelled in DigSilent PowerFactory where all simulations were done. A few reactive power control methods will be proposed and tested on this system.

3.1 Overview of the report

First, a literature review of reactive power, DG and voltage control will be given in Chapter 4. Then a description of the system will be given in Chapter 5. In Chapter 6.1, the implementation in DigSilent will be explained and the base case investigated. Different methods of reactive power control and the results are presented in Chapter 7. Finally, conclusion and future work is discussed in Chapter 9 and 10.

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4 Background and literature review

4.1 Reactive power

4.1.1 Basics

AC power systems produce and consume two types of electrical power, active and reactive power. Active power is the true power given to any load. Active power is measured in units of watts (W). Reactive power moves back and forth in the power system. It is produced by inductive and capacitive loads. It only exists when there is a phase displacement between voltage and current. It is measured in units of volt-ampere reactive (VAr).

The apparent power is the total power (combination of active and reactive power). It is measured in units of volt-ampere (VA). [1]

Equation 4.1 shows the relationship between active, reactive and apparent power.

S = p

P²+ Q² (4.1)

where S is the apparent power, P is the active power and Q is the reactive power.

Another way to see the relationship is to look at the power triangle shown in Figure 1

Figure 1: Power Triangle

The angle difference between the voltage and current is denoted with φ. The current can both lead and lag the voltage causing leading and lagging power factors. In this thesis, we will talk about capacitive power factor when the DGs/loads are injecting reactive power and inductive power factor when they are consuming reactive power.

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4.1.2 Importance of reactive power

Importance of reactive power in power systems is increasing with growing demand for electric power. Electric power must be generated in a stable, reliable and cost effective way. Reactive power is an important factor to be able to do that. The main reasons why reactive power is so important are:

4.1.2.1 Voltage Control

Reactive power is an important factor in controlling the voltage. Over voltage can damage the insulation in equipments and low voltage can cause poor performance and also overheating of the equipments because of possible bigger currents.

How the voltage can be controlled by reactive power will be explained in more detail in Section 4.2.

4.1.2.2 Electrical Blackouts

If we look at the following equation:

P = U · I (4.2)

Power equals voltage times current. If the voltage is poorly controlled, it can cause high current which can over load the lines and cause blackouts. In order to control the voltage correctly, reactive power is important like discussed in the previous chapter.

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4.2 DG effect on distribution grid

High penetration of distributed generation (DG) such as photovoltaic (PV) and wind turbines (WT), have caused new challenges such as voltage rise and reverse power flows.

This constantly growing use of DG in medium-voltage distribution networks will highly impact the development of future electrical systems.

Distribution networks are normally built up in the following way: The HV transmission network is connected to the MV distribution network via a primary substation. A number of feeders are connected to this substation. These feeders are in general radially connected.

Some feeders are connected in a ring but then one line is usually disconnected with a switch so that no loop flow can occur. Underground cables are mostly used in these feeders and they have capacitive characteristics so they produce reactive power. Loads connected to these feeders are mostly resistive, i.e. have a power factor very close to 1. Some big loads are connected to the MV network and they are required to have a power factor within a range of 0.9 inductive and 0.9 capacitive [2]. The voltage drop along the feeder can be approximated by:

∆U ≈ R ∗ P_Load+ X ∗ Q_Load

U_N (4.3)

Where,

∆U Voltage change across the line

P_Load Active power consumption by the load (negative) R Resistance of the line

Q_Load Reactive power consumption by the load (negative) X Reactance of the line

U_N Nominal voltage

the voltage in distribution networks with no DG decreases therefore from the primary substation to the end of the feeder.

When DGs are connected, the power flow can be reverse. So the voltage can be higher at the end of the feeder than at the primary substation.

∆U = R ∗ (P_Load+ P_DG) + X ∗ (Q_Load+ Q_DG)

U_N (4.4)

If the generation is a lot higher than the demand, the voltage rise can exceed the limits.

To avoid this, the reactive power in the generation units can be utilized. Normally, loads have a power factor close to unity. PVs and WTs are usually connected through an inverter that can adjust the active and reactive power almost freely but limited by the current limit of the inverter. When a DG unit is operated inductively, it consumes reactive power so QDG comes negative which lowers the voltage. Capacitive operation however injects reactive power which increases the voltage. The impact that reactive power adjustments have depends highly on the R/X ratio of the lines. In MV grids, the R/X ratio is usually around 1, so active and reactive power have equal impact on the voltage rise.

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4.3 Regulations

The VDE 4105 code has regulations that must be followed for DG installation in Ger- many. [3]

4.3.1 Voltage regulations

Generation units connected to the MV grid in Germany are required to be able:

• to stay connected during fault

• to support the voltage by providing reactive power during the fault

• to consume the same or less reactive power after the fault clearance 4.3.2 Reactive power regulations

It is required that the capability of the inverters to feed in with a displacement up to 0.95 leading or lagging and if the plant power exceeds 13.8 kVA, a displacement up to 0.90 must be supported.

4.3.3 Three phase connection

Connections larger than 4.6 kVA must be three phase connected. Smaller connections are allowed to be one phase connected.

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4.4 Voltage control in distributed networks

In this chapter, a few control methods used in distribution grids will be discussed and explained. As can be seen in equation 4.1, the voltage depends on the active and reactive power, so by controling them, the voltage can be controlled. Active power controls and reactive power controls will therefore be explained in this chapter. There are also more direct methods to control the voltage that will be explained.

4.4.1 Voltage Control 4.4.1.1 OLTC for transformers

On-load tap changers (OLTC) are used to control the voltage directly, i.e. without using active or reactive power control. Normally, the HV/MV transformers that connects the distribution network to the transmission grid has an OLTC to control the voltage at the MV busbar. However, this control could be more advanced. The OLTC controls the voltage on the MV busbar. One or more feeders are connected to this busbar. If the DG is uneven, e.g. on one feeder there is a lot of generation but on another feeder there is not as much because of lack of DG capacity or clouds, then the voltage profile for these feeders would be very different and this could cause under or over-voltage. An advanced approach could be to monitor the voltage at various points in the distribution grid. The downside of this approach however is additional cost. The MV/LV transformers normally have no-load tap changers (NLTC). They have a fixed operation point and can only be changed on-site when the transformer is disconnected. OLTC have a high advantage over NLTC. By using ONTC on the MV/LV transformers, the LV network could operate almost independent of the MV network. Then the voltage on the LV side could be set to below nominal voltage during high in-feed and above nominal voltage during low in-feed. [4]

4.4.2 Active power control

One way to control the voltage is by controlling the active power. There are a few ways that this can be done, for example:

4.4.2.1 Batteries

Batteries are built to store energy. When the DG is high and the voltage rises, batteries can be used to store the extra energy and lower the voltage. Also, when the DG is low and the voltage is low, batteries can use this extra energy to inject active power in to the grid and prevent the voltage to lower further.

4.4.2.2 Active power curtailment

Active power curtailment can be used to avoid the disconnection of inverters due to over-voltage tripping. Active power can be limited to a fixed percentage of the nominal power or voltage-dependent. Active power curtailment can also be used to increase hosting capacity [5]. An example of a voltage dependent curtailment can be seen in Figure 2 where the curtailment starts at U=1.07 p.u. and the generation is completely shut down at U=1.1 p.u.

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Figure 2: Example of active power curtailment

4.4.3 Reactive power control

In this section, the reactive power control of DGs will be explained in more detail. As has already been discussed in Chapter 4.2, the reactive power can be used to control the voltage level. The voltage rise caused by the DG unit can be expressed as follows:

∆U_DG ≈ R · P_DG+ X · Q_DG

U_N (4.5)

Generation units must be able to operate between 0.95 inductive and 0.95 capacitive. The most common ways to control the reactive power are: constant Q, constant PF, cosφ(P ), cosφ(U ) and Q(V). These methods are explained in the following sections.

4.4.3.1 Constant Q

Constant amount of reactive power is consumed or provided by the DG unit independent of the voltage at the bus or the active power generated. This method is rather easy to implement but the disadvantage is that this will unnecessary produce or consume reactive power even when it is not needed.

4.4.3.2 Constant PF

With constant power factor, the DG unit is not consuming or providing reactive power when there is no active power. However, it can still consume or provide reactive power when it is not needed.

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4.4.3.3 cosφ(P )

With this method, the power factor changes according to the active power generation.

This method improves the constant PF method as it can lower the reactive power consumption or provision when the infeed decreases. There are still some cases when the voltage is not at its upper limit but the units are consuming a lot of reactive power, e.g.

when clouds cover only part of the PV plants, causing the voltage to decrease but there are some PVs generating maximum active power. An example of this controller can be seen in Figure 3.

Figure 3: Example of cosφ(P ) control

4.4.3.4 cosφ(U)

This method is very similar as cosφ(P ) as the voltage is very dependent on the active power. This will however partially fix the cloud situation mentioned in Section 4.4.3.3 as the power factor is only controlled by the voltage. An example of cosφ(U) control can be seen in Figure 4.

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Figure 4: Example of cosφ(U) control

4.4.3.5 Q(U)

This methods consumes/provides reactive power as a function of the voltage. Here the reactive power is not a percentage of the active power, as in the cosφ methods. Now it is possible to consume or generate reactive power even when there is no active power production, e.g. at night if the voltage falls down below certain threshold it is possible to inject reactive power to make the voltage rise. This characteristic is shown in Figure 5.

Figure 5: Example of Q(U) control

The red dotted lines represent a certain threshold. So that when the voltage falls below the lower threshold, reactive power is injected to fix that. Also, when the voltage rises above the upper threshold, reactive power is consumed to lower the voltage. In between the two thresholds there is a dead-band, where no reactive power is consumed or provided.

Of course, this is only an example of a Q(U) control. The dead-band could be wider or nothing at all. Also, there could be some constant reactive power consumption or provision within the dead-band.

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5 Model Description

5.1 General introduction

In this thesis, a model was developed to study steady-state problems described in Chap- ter 3. To simulate this model, the power system toolbox PowerFactory 15.2 by DIgSILENT has been used. First version of this model was created by S. Geidel from Energynautics.

The model was improved and expanded by L. Hulsmann in his master thesis from KTH [6]. Now this model has been further studied by me. Only the final version of this model will be described in this thesis.

This model consists of two MV feeders connected to the same primary substation.

These feeders are a part of a German distribution grid. This Chapter will describes the model in detail. First a summary of the German electricity market and then the location and layout of the system.

5.2 German electricity market

Germany is the largest electricity market in Europe, it was opened for competition in 1998. There is not a single system operator like in many other countries. Table 1 summaries the electricity market in Germany.

Table 1: German electricity market Electricity Market

Distribution Distribution Voltage Transmission Transmission Voltage

Grid (km) Level (kV) Grid (km) Voltage Level # DSOs

1780856 <=110 36001 150, 220, 380 817

Customers Electricity Installed Installed

# TSOs (m) Production (TWh) Capacity (GW) Capacity RES (GW)

4 50.3 594.7 204.6 97.9

Source: BNetzA (2016) [7]

The share of RES capacity is 48% of the total installed capacity in the system. Of that, around 97% of the RES are connected to the distribution grid. Wind power and PV have the highest share of DG, and have a share of around 83% of total RES installed capacity.

PV are mostly connected to the distribution system, 65 % of PV generators are connected to LV (230/400 V) and about 35 % to MV (11-60 kV). Only a few are connected to HV (110 kV). 95% of wind DG are connected to MV network. [8]

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5.3 Location

The distribution system is located 50 km south of Frankfurt, Germany as can be seen in Figure 6.

Figure 6: Location of the system

There is one primary substation that connects the 110 kV grid to the 20 kV distribution grid via two 45 MVA transformers. The two distribution feeders are shown in Appendices A and B. They will be explained in more detail in the following sections.

5.4 Feeder 1

5.4.1 General information

There are 47 MV/LV secondary unit substations (SUS) at feeder 1. The furthest is located at a distance of 22 km from the primary substation. A total number of 3700 customers are connected to the LV grids of this feeder and one 7.3 MW PV farm. The PV farm is connected to the MV side and is located in fre08, which is 18 km from the primary substation. A diagram of feeder 1 can be seen in Appendix A.

5.4.2 Parameters

The feeder consists mainly of underground cables apart from a few overhead lines interconnecting villages. Information about this feeder is shown in Table 2. R/X ratios along the feeder are given in Table 4.

The MV/LV transformers at the SUS’s are equipped with off-load tap changers. All tap changers have three possible positions with one of the following settings: 20.8/20.0/19.2 kV to 400 V or 20.8/20.4/20.0 kV to 400V

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Table 2: Information about feeder 1

Number of substations 47

Average number of customers per substation 79 Total number of customers 3712 Number of small scale PV plants 278 Capacity of small scale PV plants 4.4 MW

Capacity of large scale PV plant 7.3 MW

Maximum load in 2015 3.7 MW

5.5 Feeder 2

5.5.1 General information

There are 39 MV/LV SUS’s at feeder 2. The furthest is located at a distance of 19.5 km from the primary substation. A total number of 3020 customers are connected to the LV grids of this feeder. There is one 9.6 MW wind farm connected to the MV grid in wah06 (18 km from the primary substation). A diagram of feeder 2 can be seen in Appendix B.

5.5.2 Parameters

The entire MV network consists of underground cables. The LV grids also consists of underground cables with the exception of ofs07 where the LV grid mainly consists of overhead lines. The R/X ratio along the feeder is given in Table 4. More information about this feeder can be seen in Table 3. The transformers at the SUS’s are equipped with off-load tap changers with the same possible tap positions as described in 5.4.2.

Table 3: Information about feeder 2

Number of substations 40

Average number of customers per substation 76 Total number of customers 3020 Number of small scale PV plants 196 Capacity of small scale PV plants 3.3 MW

Capacity of wind farm 9.6 MW

Maximum load in 2015 5.7 MW

Table 4: R/X ratios along the feeders

Feeder 1 & 2 R/X ratio in MV grid very close to the primary substation(0-1 km for feeder 1, 0-8 km for feeder 2) 0.9 R/X ratio in MV grid further away from the primary substation(1-22 km for feeder 1, 8-19.5 km for feeder 2) 1.7

R/X ratio in LV distribution grid 2.6 (mostly) R/X ratio in LV grid - customer connections 8.2

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The secondary substations were modelled in the following way: The LV networks were not modelled in detail. The total load and generation from each substation were aggregated into a single load and a single generating unit as can be seen in Figure 7:

20 kV 400 V

20 kV PPV

PLoad

Figure 7: Aggregation of loads and PV’s

More information about how this aggregation was done is found in Section 5.6.1 for PV’s and Section 5.7.1 for loads.

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5.6 Generation Modelling

5.6.1 Active Power

There is only one large scale PV plant (the 7.3 MW PV plant in fre08). 15 minutes average active power values are available from the DSO. These values are available to directly put in Power Factory. The small scale PV plants do not have smart meters, so the same values are not available for them. The only data available for these plants are: the PV capacity of every installation and the SUS to which it is connected. For the modelling, the capacity of all PV’s connected to the same SUS is summed and one PV generator used to represent all the small scale PV’s. The output of the large scale PV plant is used as a reference, e.g. if the average power output of the large scale PV plant is 30 % of the capacity, the output of the small scale PV plants would also be 30 % of their capacity.

This is a reasonable approximation for PV plants close to fre08. The village Freimersheim is only around 1 km from fre08. The PV’s in feeder 2 are between 10 to 16 km from fre08 but due to lack of measurements, the large scale PV plant was also used as a reference in feeder 2. The active power for the wind farm in wah06 is directly taken from measurements.

5.6.2 Reactive Power

The small scale PV’s should operate at a unity power factor according to the DSO.

However, because some of the LV networks are not included in the model, a unity power factor was not suitable for the small scale PV’s. In order to approximate the final reactive power at the feeding point, a value of 0.9985 inductive (VAr consuming) was chosen for the small scale PV’s in feeder 2. In feeder 1, a power factor value of 0.9992 inductive was found to be a good approximation for all small scale PVs. This is further explained in Chapter 5.

The large scale PV plant in fre08 has a cosφ(U) controller and 15 minute average measurements values for the reactive power are available. The cosφ(U) controller has the same characteristics as in Figure 4.

The wind farm in wah06 operates at a constant power factor of 0.95 inductive (VAr consuming).

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5.7 Load Modelling

5.7.1 Active Power

Three things are known about each customer from the DSO: The total yearly electricity consumption, the SUS to which they are connected and the categorization of the customer.

Each customer is categorized either as a RLM (German: Registrierende Leistungsmessung, English: Recorded power) or as a SLP (Standard Load Profile).

RLM customers are customers that consume more than 100 MWh per year. They are obligated to measure and record their power consumption. For these customers, a 15 minute average value for the active power is available and can be used directly as an input in Power Factory.

SLP customers are further categorized into household and industry customers. Stan- dard load profile is used to model these customers. This is a 15 minute average values over a large sample of customers of a common type. A typical household and industrial SLP for one week is shown in Figure 8. The yearly electrical consumption for each customer connected to the same SUS was summed up and then the SLP used to generate a 15 minute average load profile.

Example: There are 57 household customers connected to substation fre03, their total yearly consumption is 207777 kWh. The standard load profile for household has a yearly consumption of 3700 kWh. Then each 15 minute value is multiplied by ^{207777kW h}_{3700kW h} . The same thing was done for all industrial SLP customers. [6]

Figure 8: Standard Load Profile, residential vs. industrial In feeder 1, there are 12 RLM customers and 3700 SLP customers.

In feeder 2, there are 20 RLM customers and 3000 SLP customers.

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5.7.2 Reactive Power

The loads usually have a unity power factor but they can also be slightly inductive or capacitive.

For the reactive power modelling a power factor of 0.94 inductive (VAr consuming) was found fitting for all loads on feeder 2 and a power factor of 0.975 inductive was found fitting for all loads on feeder 1.

5.8 Reactive power capability

As mentioned in Section 4.3, all generation units must be able to operate with a power factor between 0.95 inductive and 0.95 capacitive. If the generation unit is generating maximum active and reactive power, then the apparent power will be:

P_max Smax

= 0.95 S_max= 1.0526P_max

So the PV inverter or the inverter in the wind turbine must be able to handle the current when the apparent power is roughly 5% more than the maximum active power.

The maximum reactive power at every time is therefore:

Q_max =p

S_max² − P² =p

1.0526P_max² − P²

Here, Qmax is dependent on the instantaneous active power. This is shown in Figure 9 where Smax is shown with bold blue half-circle and Pmax is shown with a red line.

Figure 9: Reactive power capability

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It is however complicated to implement this controller because the active power generation is not known beforehand and therefore Qmax is not known and is always changing.

For a more simpler approach, Qmax could be constant. For example when the generation unit is generating maximum active power, the maximum reactive power is:

Q_max =p

S_max² − P_max² =p

(1.0526P_max)²− P_max² =√

0.108P_max = 0.3287P_max Now Qmax is constant, 32.87 % of Pmax. This maximum limit of the reactive power is shown in Figure 9 with the black lines. In this project, this limit (32.87 % Pmax) was used when reactive power controllers were tested.

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6 DigSilent Implementation

As mentioned in Section 5.6.2, a fitting power factor for small scale PV’s and loads had to be approximated. In this chapter this will be explained further and a base case will be presented.

6.1 Power factors for small scale PV’s and loads

The system was modelled in DigSilent Power Factory and all load flow calculations done there. Reactive power measurements from the local DSO are available at the primary substation. These measurements were used to find a fitting power factor for the loads and generation units by comparing the measured and simulated reactive power flow at the primary substation.

First, all loads and small scale PV’s are modelled with a unity power factor. The large PV farm has the cosφ controller and the wind farm has a power factor of 0.95 VAr consuming. The reactive power from each feeder at the primary substation is shown in Figures 10 and 11 compared to the measured reactive power.

Figure 10: Reactive power from feeder 1, simulated and measured

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Figure 11: Reactive power from feeder 2, simulated and measured

The root mean square error (RMSE) between the measured and simulated values are:

Feeder RMSE

1 0.42 MVAr 2 0.97 MVAr

From these figures it can be seen that a unity power factor for both loads and generation is not a good approximation so there is need to find a fitting power factor to get a more accurate model.

There is too much reactive power generated for both feeders when the power factor for both loads and DG is unity. Reactive power consumption is therefore needed in order to match the simulated values with the measurement data.

This was done with a trial and error method. Power factors were tried out and then the reactive power flow at the primary substation compared to the measurement data.

The best outcome was obtained with the following values:

Feeder p.f. for loads p.f. for PVs 1 0.975 ind. 0.9992 ind.

2 0.94 ind. 0.9985 ind.

The comparison with these values can be seen in Figures 12 and 13.

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Figure 12: Reactive power from feeder 1 whith corrected pf, simulated and measured

Figure 13: Reactive power from feeder 2 with corrected pf, simulated and measured The root mean square error (RMSE) between the measured and simulated values are:

Feeder RMSE

1 0.23 MVAr 2 0.18 MVAr

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The LV networks that are not modelled clearly have an effect on the reactive power flow in the system. In order to model this, a new generator was put on all substations that have LV network not modelled (all SUS except the PV farm and wind farm (fre08, wah06)). This generator models the LV network. Active power is taken from the real generator and the power factor used to calculate Q that is consumed by this generator.

The new generator is added to the substation like shown in Figure 14.

20 kV P PV

P Load

P = 0, Q 6= 0

Figure 14: Modelling of loads and PV units at SUS

This generator is added so that it is easier to try Q controllers. Then this new Q generator does not change and different Q controllers can be implemented on the real generator.

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7 Simulation Results

In this chapter, a few different control methods will be tested on the system in order to conclude how much reactive power support can be delivered from the two feeders.

− No reactive power support

− Constant power factor

These control methods have been tested and then a voltage dependent reactive power method, Q(U), is used to maximize reactive power support.

7.1 Active power flow

The difference between load and generation from both feeders can be seen in Figures 15 and 16. Positive values mean that the generation exceeds the consumption. Two points are marked in these Figures. The black circle marks the time when the generation minus consumption is at minimum and the red circle marks the time when the generation minus consumption is at maximum. These will be the two extreme scenarios used to check the voltage in the system because this is when the voltages are most likely at maximum and minimum in the network. More information about these scenarios can be seen in Table 5.

Figure 15: Difference between generation and load, Feeder 1

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Table 5: The scenarios for both feeders

Scenario Feeder 1 Feeder 2

Time Gen [kW] Cons. [kW] Time Gen [kW] Cons. [kW]

Max Gen-Cons. Day 6, 14:15 9620 2248 Day 1, 05:15 9600 2306

Min Gen-Cons. Day 5, 20:45 0 2026 Day 5, 18:45 133 3765

7.2 Base Case

7.2.1 Power flow at the primary substation

The system was simulated without making any changes to it, i.e. the controller at the PV farm was not changed and the constant power factor at the wind farm was not changed.

The data was from 6 days in 2015, from 18.06.2015 to 23.06.2015. The power flow at the primary substation was recorded for these 6 days for both feeders and is shown in Figures 17 - 18, (positive means power going from the feeder towards the primary substation and the HV grid).

Figure 17: Power flow from the primary substation, Feeder 1, Base Case

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Figure 18: Power flow from the primary substation, Feeder 2, Base Case

For feeder 1, when the large PV farm in fre08 starts to generate active power, it is controlled to consume reactive power. During daytime the feeder is taking reactive power from the HV grid.

For feeder 2, the wind farm is consuming reactive power, so most of the time the feeder is taking reactive power from the HV grid.

The average active power losses were calculated for both feeders in the following way:

P_Losses = 1 576

576

X

i=1

(P_G−Lⁱ + P_{P S}ⁱ )

where P_G−Lⁱ is the difference between generation and load at time i, taken from Figures 15 and 16. PP Sⁱ is the active power flow from the primary substation at time i, taken from Figures 17 and 18. There are 576 quarters for these 6 days. The average active power losses in this base case were calculated to be 27 kW for feeder 1 and 113 kW for feeder 2.

7.2.2 Voltage profiles

The voltage at each substation was also recorded for the 6 days. The two scenarios in Table 5 were used for the voltage profiles. The voltage profile for these two scenarios can be seen in Figures 19 - 21. In Figure 19 substation 1 is the primary substation and substation 29 is wal01 which is the substation at the end of the feeder (see Appendix A).

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Figure 19: Voltage profile for two scenarios at feeder 1, Base Case

Two voltage profiles were made for feeder 2. First one that is from the primary substation to the wind farm bus (wah06) and can be seen in Figure 20. The other goes to the end of the feeder (ofs02), it can be seen in Figure 20. Buses one to five are the same for both voltage profiles, bus one is the primary substation and bus five is mon01. See Appendix B where voltage profile A is marked in red and voltage profile B is marked in blue, the common part and other branches are coloured black.

Figure 20: Voltage profile for two scenarios at feeder 2 A, Base Case

In Figure 21 the voltage reaches maximum at mon01 (bus 5), that is because most of the generation is at wah06, and wah06 is at the end of a branch that goes from mon01.

The voltage continues to rise in Figure 20 all the way to the wind farm bus wah06.

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Figure 21: Voltage profile for two scenarios at feeder 2 B, Base Case

A voltage profile with respect to time was made for the most vulnerable bus (the bus that came closest to the voltage limits). In this case it was bus wah06 as can be seen in Figure 21. The voltage profile can be seen in Figure 22.

The maximum voltage at bus wah06 was 1.072 p.u.

Figure 22: Voltage profile with respect to time for wah06, Base Case

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7.3 No reactive power

The system was simulated with no source of reactive power, i.e. all the DGs are not injecting or consuming any reactive power. The only change here from the base case is that the controllers on the PV farm bus fre08 and the wind farm bus wah06 were taken away. The generators added in Section 6.1 are however still consuming reactive power.

The power flow for both feeders for the six days can be seen in Figures 23 - 24.

Figure 23: Power flow from the primary substation, Feeder 1, zero Q

Figure 24: Power flow from the primary substation, Feeder 2, zero Q

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Even when there is no reactive power in the DG’s, there is still reactive power flowing from the feeder to the primary substation, for feeder 1 the average reactive power provision is 700 kVAr. For feeder 2 the average reactive power provision is 167 kVAr. This can be explained by that the distribution network is mostly supplied with underground cables and they work like capacitors, i.e. they provide reactive power. The average reactive power at the primary substation, standard deviation and network losses can be seen in Table 6 and in Table 7, the voltage intervals (Umax and Umin) can be seen for both feeders. The voltage profile was made for the two scenarios in Figures 25 - 27. The red dashed line are scenario 1 from the Base Case and the blue dashed line are scenario 2 from the Base Case.

Figure 25: Voltage profile for two cases at feeder 1, zero Q

Figure 26: Voltage profile for two cases at feeder 2 A, zero Q

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Figure 27: Voltage profile for two cases at feeder 2 B, zero Q

In scenario 2, the voltage profile doesn’t change from the base case. There is very little generation in scenario 2 and therefore there is no reactive power consumption in the base case and the voltage stays the same. In scenario 1 the voltage is higher when there is no consumption of reactive power. Why this happens has been explained in Section 4.2.

A voltage profile with respect to time was made for the most vulnerable bus (the bus that came closest to the voltage limits). In this case it was the wind farm bus wah06 as can be seen in Figure 26. The voltage profile can be seen in Figure 28. The maximum voltage at bus wah06 was 1.088 p.u.

Figure 28: Voltage profile with respect to time for the wind farm bus wah06, zero Q

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Table 6: Comparison between the base case and no reactive power method

Method

Feeder 1 [11.7 MW] Feeder 2 [12.9 MW]

Average Q St. Deviation of Q Average Losses Average Q St. Deviation of Q Average Losses

[kVAr] [kVAr] [kW] (% of BC) [kVAr] [kVAr] [kW] (% of BC)

Base case -388 581 27 (0%) 887 1044 113 (0%)

No reactive power -700 131 26 (-3.7%) -167 184 100 (-12%)

Table 7: Comparison between voltage intervals, base case and no reactive power method

Method Feeder 1 Feeder 2

U_{M ax} U_{M in} U_{M ax} U_{M in}

[p.u.] [p.u.] [p.u.] [p.u.]

Base Case 1.07 1.02 1.07 1.01

No reactive power 1.08 1.02 1.09 1.01

7.4 Constant power factor

7.4.1 0.95 capacitive p.f.

The system was simulated when all DG’s had a constant power factor of 0.95 capacitive (providing reactive power). The power flow from the primary substation can be seen in Figures 29 - 30.

Figure 29: Power flow from the primary substation, Feeder 1, constant p.f. 0.95 cap.

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Figure 30: Power flow from the primary substation, Feeder 2, constant p.f. 0.95 cap.

The mean values, standard deviations and average losses can be seen in Table 8 and the voltage intervals can be seen in Table 9

Table 8: Comparison between Base Case, No Q and Constant p.f. 0.95 cap.

Method

Base case -388 581 27 (0%) 887 1044 113 (0%)

Constant p.f. 0.95 cap. -1248 597 33 (+22%) -1350 832 113 (0%)

Table 9: Comparison between Base Case, No Q and Constant p.f. 0.95 cap., Voltage interval

[p.u.] [p.u.] [p.u.] [p.u.]

Base Case 1.07 1.02 1.07 1.01

Constant p.f. 0.95 cap. 1.09 1.02 1.11 1.02

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The voltage profiles for the two scenarios in Table 5 can be seen in Figures 31 - 33.

The dashed lines in the Figures are from the base case. There is no generation in scenario 2 for feeder 1 and therefore the voltage profile doesn’t change at all because the reactive power provision is zero on all DG’s as it was in the base case. On feeder 2, the generation in scenario 2 is very small so the voltage profile changes a little bit.

Figure 31: Voltage profile for two scenarios at feeder 1, constant p.f. 0.95 cap.

Figure 32: Voltage profile for two scenarios at feeder 2 A, constant p.f. 0.95 cap.

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Figure 33: Voltage profile for two scenarios at feeder 2 B, constant p.f. 0.95 cap.

In this case, the voltage limit is violated on feeder 2 as can be seen in Figure 32.

A voltage profile with respect to time was made for the most vulnerable bus (the bus that came closest to the voltage limits). In this case it was the wind farm bus (wah06) that exceeded the voltage limits the most as can be seen in Figure 32 (bus 16). The voltage profile can be seen in Figure 34. The maximum voltage at wah06 was 1.106 p.u.

Figure 34: Voltage profile with respect to time for wah06, constant p.f. 0.95 cap.

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7.4.2 0.95 inductive p.f.

The system was simulated when all DG’s had a constant inductive power factor of 0.95.

The power flow can be seen in Figures 35 and 36. The mean values, standard deviation and losses can be seen in Table 10 and the voltage intervals can be seen in Table 19.

Figure 35: Power flow from the primary substation, Feeder 1, constant p.f. 0.95 ind.

Figure 36: Power flow from the primary substation, Feeder 2, constant p.f. 0.95 ind.

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Table 10: Comparison between Base case, No Q and Constant p.f. methods

Method

Base case -388 581 27 (0%) 887 1044 113 (0%)

Constant p.f. 0.95 cap. -1248 597 33 (+22%) -1350 832 113 (0%)

Constant p.f. 0.95 ind. -145 798 28 (+3.7%) 1039 1070 115 (+1.8%)

Table 11: Comparison between Base Case, No Q and Constant p.f. methods, Voltage intervals

UM ax UM in UM ax UM in

[p.u.] [p.u.] [p.u.] [p.u.]

Base Case 1.07 1.02 1.07 1.01

Constant p.f. 0.95 cap. 1.09 1.02 1.11 1.02

Constant p.f. 0.95 ind. 1.07 1.02 1.07 1.01

Voltage profile for both cases and both feeders can be seen in Figures 37 - 39.

Figure 37: Voltage profile for two cases at feeder 1, constant p.f. 0.95 ind.

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Figure 38: Voltage profile for two cases at feeder 2 A, constant p.f. 0.95 ind.

Figure 39: Voltage profile for two cases at feeder 2 B, constant p.f. 0.95 ind.

The voltage profiles are almost identical to the base case. The reactive power flow on feeder 2 is almost the same for this case and the base case because in both scenario 1 and 2 there is almost no PV generation and therefore almost no reactive power consumption by the PVs, the wind farm has a power factor of 0.95 inductive in the base case and therefore the reactive power flow is almost the same in feeder 2 for this case and the base case. On feeder 1 in the base case, the PV farm has a cosφ(U) controller like shown in Figure 4 and in scenario 1, the voltage on the PV farm bus is 1.07 p.u. which means the power factor from the PV farm is around 0.92 inductive. The PV farm is consuming more reactive power in the base case than in this case but the rest of the PVs are consuming with a power factor of 0.95 inductive in this case and nothing in the base case and therefore the reactive power flow on feeder 1 is similar in this case and the base case. For scenario 2 on feeder 1, there is no generation and therefore this case is identical to the base case on that time.

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A voltage profile with respect to time was made for the most vulnerable bus.

Again, it was the wind farm bus wah06 as can be seen in Figure 37. The voltage profile can be seen in Figure 40. The maximum voltage was 1.072 p.u.

Figure 40: Voltage profile with respect to time for wah06, constant p.f. 0.95 ind.

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7.5 Maximizing reactive power support

In this section, a Q(U) control will be used to maximize the reactive power support.

In Figure 41, two examples of Q(U) control and the limits of the control can be seen.

Figure 41: Two examples of Q(U) control

The reactive power capability is from -32.87 %Pmax to 32.87 %Pmax represented by the red lines. The blue line in Figure 41 is an example of a Q(U) control. If this control is implemented in a DG unit, it will provide reactive power ( 30% of active power capacity) until the voltage at the bus where the unit is connected reaches 0.96 p.u., then the reactive power provision starts to decrease and when the voltage reaches 1.01 p.u. the reactive provision is 20% of active power capacity. The pink line is another example of a Q(U) control. This control is providing reactive power (20 % of active power capacity) until the voltage reaches 0.91, then the reactive power provision starts to decrease and decreases linearly and reaches 0 when the voltage reaches 1.1 p.u. This control method will first be used to maximize the reactive power provision from both feeders and then to maximize the reactive power consumption to both feeders.

A sensitivity analysis was made in order to decide from which DG unit the reactive power support should come from. This analysis is explained in section 7.6.

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7.6 Sensitivity Analysis

By controlling the reactive power in the DGs, the voltage profile changes. In order to be able select which DG should contribute to the reactive power support the most, we need to find out which DG has the least effect on the voltage. Therefore, a sensitivity analysis was made in order to decide where the reactive power should come from, i.e. which DG is the most sensitive to a change in reactive power consumption/provision. The analysis goes like this:

− Set all DG power factors to 1, so there is no reactive power provision or consumption.

− Run a power flow and record the voltage at each substation.

− Put a constant 10 kVAr generation of reactive power at the first substation and repeat step 2.

− Repeat step 3 for all the substation, one at a time.

The voltage change can be seen in Table 12 for feeder 1 and Table 13 for feeder 2.

From these results, the obvious conclusion is that the distance from the primary substation has the most affect on the sensitivity of the substations.

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Table 12: Sensitivity, analysis Feeder 1 Name Distance from SS [m] ∆V [p.u.]∗10⁻⁵

wal01 22047 3.10

wal03 21664 3.04

wal02 21175 2.97

fre07 20290 2.85

fre02 20032 2.81

fre03 19475 2.73

fre06 19124 2.68

fre08 18422 2.58

fre05 17650 2.47

ket04 16734 2.35

ket02 16468 2.32

ket01 16011 2.25

ket06 15849 2.23

ket03 15622 2.19

ket05 15068 2.11

esl01 14632 2.05

esl03 14300 2.00

epp07 13078 1.91

epp06 13029 1.91

epp02 12714 1.86

epp03 12713 1.86

epp01 12372 1.81

din01 12562 1.76

flo02 11461 1.60

flo01 10601 1.55

flo05 11033 1.54

flo04 11783 1.48

ofl01 9086 1.33

ofl02 8759 1.29

ofl07 6884 1.02

ofl06 6307 0.93

ofl04 5985 0.89

ofl05 5371 0.80

ofl03 5067 0.76

ghm02 2802 0.45

ghm09 2420 0.39

ghm13 2462 0.38

ghm03 1412 0.31

ghm07 1671 0.26

ghm06 1643 0.25

ghm04 1360 0.21

ghm05 1200 0.19

ghm01 931 0.15

ghm11 380 0.06

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Table 13: Sensitivity analysis, Feeder 2 Name Distance from SS [m] ∆V [p.u.]∗10⁻⁵

ofs04 18939 2.90

ofs08 18656 2.86

ofs01 18608 2.85

wah06 18193 2.76

wah04 18110 2.75

ofs11 17788 2.73

ofs10 17625 2.71

ofs05 17451 2.68

ofs03 17218 2.65

wah03 17360 2.65

ofs09 16966 2.61

wah05 17031 2.60

ofs07 18118 2.57

wah02 16463 2.52

hos04 15739 2.43

hos02 15536 2.40

wah01 15559 2.39

hos03 15122 2.34

hos01 14655 2.27

mon14 13404 2.09

mon05 13196 2.05

mon02 12609 1.97

mon13 12322 1.93

mon08 11852 1.86

mon07 11531 1.81

mon12 11462 1.81

mon06 11252 1.77

mon21 11252 1.77

mon09 11899 1.76

mon03 11110 1.75

mon01 10601 1.68

These results will now be used to maximize the reactive power support with a Q(U) controller.

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7.7 Maximizing reactive power provision

In this section, a Q(U) control will be used to maximize the reactive power provision.

The sensitivity analysis performed in section 7.6 is used to determine the Q parameter for U = 1.1 p.u.. This was done to determine how much reactive power can be provided for the worst case scenario (when the voltages are at maximum). The procedure goes like this: First the reactive power provision was raised on the strongest bus (ghm11 on feeder 1 and mon01 on feeder 2) until either the reactive power limits of the unit or the voltage limits were met. Then the same was done for the next strongest bus (ghm01 on feeder 1 and mon03 on feeder 2) until either limits were met. This was done for all buses with DG capacity. The results from this can be seen in Table 14.

Table 14: Q parameters for U=1.1 p.u.

Substation Q [% Pmax] for U=1.1 p.u. Feeder

All PV’s on F1 32.87 1

Wind farm bus wah06 12 2

ofs01, ofs08, ofs01 0 2

Rest of SUS on F2 32.87 2

On feeder 1, all PV units can provide maximum reactive power when the voltage is at maximum. On feeder 2, the PV units connected to the strongest 27 buses can provide maximum reactive power. Then the wind farm bus reached the voltage limits when the wind farm was providing reactive power of 12 % of its active power capacity. Then the three remaining buses (ofs01, ofs08 and ofs04) could not provide any reactive power without violating the voltage limits. Now we have Q parameters for one point in the Q(U) control (when U=1.1 p.u.). Because all PV units can provide maximum reactive power when the voltage is at maximum, it can be concluded that these units can provide maximum reactive power for all voltages. So all PV units on feeder 1 can have a constant Q control and all units can provide maximum reactive power all the time without violating the voltage limits. On feeder 2 this is not the case. In order to find how the control for the units on feeder 2 changes for different voltage values, Q parameters were defined for U = 0.9 p.u..

This was done with the same method, only now scenario 2 was used to determine the parameters because in scenario 2 the voltage is at minimum. In Table 15 the Q parameter for U = 0.9 p.u. can be seen for feeder 2.

Table 15: Q parameters for U=0.9 p.u. on feeder 2 Substation Q [% Pmax] for U=0.9 p.u.

Wind farm bus wah06 32.87

ofs01, ofs08, ofs01 32.87

Rest of SUS on F2 32.87

For U = 0.9 p.u., all DG units on feeder 2 can provide maximum reactive power. Now it can be estimated that the DG units connected to the first 47 buses can have a constant Q control providing maximum reactive power at all times. The control for the wind farm bus wah06 and the other three buses ofs01, ofs08 and ofs04 need to decrease the reactive power provision at some voltage value so that the voltage limits are not violated.

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Now the Q parameters were found for these controllers at other voltage values (first for U=1.0 p.u., then for U=1.01 p.u. and so on). The resulting controllers can be seen in Figure 42 and in Tables 16 and 17 the resulting controllers can be seen.

Figure 42: Controllers for maximizing reactive power provision

The controller for the wind farm on wah06 is in red. The wind farm is providing 32.87

% of active power capacity until the voltage reaches 1.09 p.u. and then it decreases linearly and reaches 12 % of active power capacity at U = 1.1 p.u..

Table 16: Controller for the wind farm bus wah06 Q @ U=0.9 - 1.09 p.u. Q @ U=1.1 p.u.

32.87 12

The controller for the PV units connected to ofs01, ofs08 and ofs04 is shown in green in Figure 42. The units are providing 32.87 % of active power capacity until the voltage reaches 1.03 then the Q provision decreases linearly and reaches 0 when U = 1.1 p.u..

Table 17: Controller for ofs01, ofs08 and ofs04 Q @ U=0.9 - 1.03 p.u. Q @ U=1.1 p.u.

32.87 0

The blue line in Figure 42 represents the controller for all PV units in feeder 1 and the PV units connected to the strongest 47 buses in feeder 2. These units provide 32.87 % of active power capacity all the time regardless of the voltage. The power flow and voltage profiles can be seen in Figures 43 - 54.

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Figure 43: Power flow from the primary substation, Feeder 1, maximizing reactive power provision

Figure 44: Power flow from the primary substation, Feeder 2, maximizing reactive power provision

The average Q values, standard deviation and active power losses can be seen in Table 18.

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Voltage profiles were made for the same two scenarios for both feeders. On feeder 1, the voltage reaches 1.099 p.u. for scenario 1 on the PV farm bus fre08 (bus 22 in Figure 45). On feeder 2, the voltage reaches 1.099 on the wind farm bus wah06 (bus 16 in Figure 46). The voltage intervals for both feeders can be seen in Table 19.

Figure 45: Voltage profile feeder 1, Maximizing reactive power provision

Figure 46: Voltage profile feeder 2 A, Maximizing reactive power provision

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Figure 47: Voltage profile feeder 2 B, Maximizing reactive power provision

A voltage profile with respect to time was made for the bus that came closest to the voltage limits. In this case it was bus wal01 on feeder 1. The maximum voltage was 1.099 p.u. However, the voltage didn’t go over 1.09 p.u. often (less than 2% of the time).

Figure 48: Voltage profile with respect to time for wal01, Maximizing reactive power provision

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Table 18: Comparison between maximizing Q provision to other control methods

Method

Base case -388 581 27 (0%) 887 1044 113 (0%)

Constant p.f. 0.95 cap. -1248 597 33 (+22%) -1350 832 113 (0%)

Constant p.f. 0.95 ind. -145 798 28 (+3.7%) 1039 1070 115 (+1.8%)

Max Q prov. -4512 128 129 (+378%) -4471 526 210 (+86%)

Table 19: Comparison between maximizing Q provision to other control methods, Voltage interval

[p.u.] [p.u.] [p.u.] [p.u.]

Base Case 1.07 1.02 1.07 1.01

Constant p.f. 0.95 cap. 1.09 1.02 1.11 1.02

Max Q prov. 1.099 1.03 1.099 1.03

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7.8 Maximizing reactive power consumption

In this section, a Q(U) controller will be used to maximize the reactive power consumption to both feeders. First, the reactive power consumption from each DG unit was found for when U=0.9 p.u. and then the possible reactive power consumption was found for when U=1.1 p.u. for each DG unit. All the DG units can consume maximum reactive power (32.87 % of active power capacity) so they all have a constant Q controller consuming maximum Q all the time, regardless of the voltage.

Figure 49: Power flow from the primary substation, Feeder 1, maximizing reactive power consumption

Figure 50: Power flow from the primary substation, Feeder 2, maximizing reactive power consumption

The average Q values, standard deviation and active power losses can be seen in Table 20.

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Voltage profiles were made for the same two scenarios for both feeders. On both feeders, the voltage decreases compared to the base case. The voltage intervals for both feeders can be seen in Table 21.

Figure 51: Voltage profile feeder 1, Maximizing reactive power consumption

Figure 52: Voltage profile feeder 2 A, Maximizing reactive power consumption

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Figure 53: Voltage profile feeder 2 B, Maximizing reactive power consumption A voltage profile with respect to time was made for the bus that came closest to the voltage limits. In this case it was bus wal01 on feeder 1. The maximum voltage was 1.07 p.u.

Figure 54: Voltage profile with respect to time for wal01, Maximizing reactive power consumption

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Method

Base case -388 581 27 (0%) 887 1044 113 (0%)

Constant p.f. 0.95 cap. -1248 597 33 (+22%) -1350 832 113 (0%)

Constant p.f. 0.95 ind. -145 798 28 (+3.7%) 1039 1070 115 (+1.8%)

Max Q prov. -4512 128 129 (+378%) -4471 526 210 (+86%)

Max Q cons. 3216 133 88 (+226%) 4493 190 219 (+94%)

[p.u.] [p.u.] [p.u.] [p.u.]

Base Case 1.07 1.02 1.07 1.01

Constant p.f. 0.95 cap. 1.09 1.02 1.11 1.02

Max Q prov. 1.099 1.03 1.099 1.03

Max Q cons. 1.07 1.00 1.07 0.99

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8 Comparison

In this section, the different methods will be compared. In Table 22 is the average Q, standard deviation of Q and average losses for each method. In Table 23, the voltage intervals for each method can be seen.

Method

Base case -388 581 27 (0%) 887 1044 113 (0%)

Constant p.f. 0.95 cap. -1248 597 33 (+22%) -1350 832 113 (0%)

Constant p.f. 0.95 ind. -145 798 28 (+3.7%) 1039 1070 115 (+1.8%)

Max Q prov. -4512 128 129 (+378%) -4471 526 210 (+86%)

Max Q cons. 3216 133 88 (+226%) 4493 190 219 (+94%)

[p.u.] [p.u.] [p.u.] [p.u.]

Base Case 1.07 1.02 1.07 1.01

Constant p.f. 0.95 cap. 1.09 1.02 1.11 1.02

Max Q prov. 1.099 1.03 1.099 1.03

Max Q cons. 1.07 1.00 1.07 0.99

In the no reactive power method, all the DG units have a unity power factor. There is however a small reactive power provision from the distribution grid (700 kVAr from feeder 1 and 167 kVAr from feeder 2). This is because of the cables in the network that have a capacitive effect and are providing reactive power. This can also explain why the maximum consumption is lower than the maximum provision on feeder 1 although all DG units are providing/consuming maximum Q in both cases. When all the DG units are consuming reactive power, they first need to consume the reactive power provided by the network and then they can consume reactive power from the HV transmission grid.

Distribution grid capacity for reactive power support

Distribution grid capacity for reactive power support

EYSTEINN EIRÍKSSON

Distribution grid capability for reactive power support

Eysteinn Eiríksson

Abstract

1 Sammanfattning

2 Acknowledgement

Contents

Abbreviations and Symbols

3 Introduction

3.1 Overview of the report

4 Background and literature review

4.1 Reactive power

4.2 DG effect on distribution grid

4.3 Regulations

4.4 Voltage control in distributed networks

5 Model Description

5.1 General introduction

5.2 German electricity market

5.3 Location

5.4 Feeder 1

5.5 Feeder 2

5.6 Generation Modelling

5.7 Load Modelling

5.8 Reactive power capability

6 DigSilent Implementation

6.1 Power factors for small scale PV’s and loads

7 Simulation Results

7.1 Active power flow

7.2 Base Case

7.3 No reactive power

7.4 Constant power factor

7.5 Maximizing reactive power support

7.6 Sensitivity Analysis

7.7 Maximizing reactive power provision

7.8 Maximizing reactive power consumption

8 Comparison