Power Management and Power flow control in Utility connected microgrid by using IGBT Switch
Abstract—This paper proposes a method for power flow control between utility and microgrid through back-to-back converterswith the IGBT switch , which facilitates desired real and reactive power flow between utility and microgrid. In the proposed control strategy, the system can run in two different modes depending on the power requirement in the microgrid. In mode-1, specified amount of real and reactive power are shared between the utility and the microgrid through the back-to-back converters. Mode-2 is invoked when the power that can be supplied by the distributed generators (DGs) in the microgrid reaches its maximum limit. In such a case, the rest of the power demand of the microgrid has to be supplied by the utility. An arrangement between DGs in the microgrid is proposed to achieve load sharing in both grid connected and islanded modes. The back-to-back converters also provide total frequency isolation between the utility and the microgrid. It is shown that the voltage or frequency fluctuation in the utility side has no impact on voltage or power in microgrid side. Proper relay-breaker operation coordination is proposed during fault along with IGBT switch and blocking of the back-to-back converters for seamless resynchronization. Both impedance and motor type loads are considered to verify the system stability. The impact of dc side voltage fluctuation of the DGs and DG tripping on power sharing is also investigated. The efficacy of the proposed control arrangement has been validated through simulation for various operating conditions. The model of the microgrid power system is simulated by using MATLAB/Simulink.
Index Terms—Active and reactive power sharing, IGBT switch back-to-back converters, microgrid.
I. INTRODUCTION
since in a real system, the distance between the converters may make an inter-communication impractical. With this in mind ,this paper proposes a configuration that is suitable for supplying electrical power of high quality to the microgrid, specifically when it is being supplied through controlled converters. The real and reactive power sharing can be achieved by controlling two independent quantities—the frequency and the fundamental voltage magnitude. Transient stability of power system with high penetration level of power electronics interfaced (converter connected) distributed generation. While the microgrid testing and control, proposes a single-phase high-frequency ac (HFAC) microgrid as a solution towards integrating renewable energy sources in a distributed generation system. For a better performance of the DGs and more efficient power management system, it is important to achieve a control over the power flow between the grid and the microgrid. With a bidirectional control on the power flow, it is possible not only to specify exact amount of power supplied by the utility but also the fed back power from microgrid to utility during lesser power demand in the microgrid With number of DGs and loads connected . over a wide span of the microgrid over a wide span of the microgrid, isolation between the grid and the microgrid will always ensure a safe operation. Any voltage or frequency fluctuation in the utility side has direct impact on the load voltage and power oscillation in the microgrid side. For a safe operation of any sensitive load, it is not desirable to have any sudden change in the system voltage and frequency.
The isolation between the grid and microgrid not only ensures safe operation of the microgrid load, it also prevents direct impact of microgrid load change or change in DG output voltage on the utility side. Protection of the devices both in utility and microgrid sides during any fault is always a major concern. Proper protection schemes in the distributed generation system ensure a reliable operation. Of the many schemes that have been proposed, explores the effect of high DG penetration on protective device coordination and suggests an adaptive protection scheme as a solution to the problems. In a method has been proposed for determining the coordination of the rate of change of frequency (ROCOF) and under/over-frequency relays for distributed generation protection considering islanding detection and frequency-tripping requirements.
The method is based on the concept of application region, which defines a region in the trigger time versus active power imbalance space where frequency-based relays can be adjusted to satisfy the anti-islanding and frequency-tripping requirements simultaneously.
In general, a microgrid is interfaced to the main power system by a fast semiconductor IGBT switch called the static switch (SS). It is essential to protect a microgrid in both the grid-connected and the islanded modes of operation against all faults. Inverter fault currents are limited by the ratings of the silicon devices to around 2 per unit rated current. Fault currents in islanded inverter based microgrids may not have adequate magnitudes to use traditional overcurrent protection techniques. To overcome this problem, a reliable and fast fault detection method is proposed in IGBT switch.
The aim of this paper is to set up a power electronics interfaced microgrid containing distributed generators. A scheme for controlling parallel connected DGs for proper load sharing is proposed. The microgrid is connected to the utility with back-to-back converters. Bidirectional power flow control between the utility and microgrid is achieved by controlling both the converters.
The back-to-back converters provide the much needed frequency and power quality isolation between the utility and the microgrid. A proper relay breaker co-ordination is proposed for protection during faults. The scheme not only ensures a quick and safe islanding at inception of the fault, but also a seamless resynchronization once the fault is cleared. The application of back-to-back converters in distributed generation would facilitate:
• controlled power flow between the microgrid and utility
which can be used in case of any contractual arrangement;
• reliable power quality due to the isolation of the microgrid system from utility.
II. SYSTEM STRUCTURE AND OPERATION
A simple power system model with back to back converters, one microgrid load and two DG sources is shown in Fig. 1. A more complex case is considered in Section VIII. In Fig. 1, the real and reactive power drawn/supplied are denoted by and , respectively. The back to back converters are connected to the microgrid at the point of common coupling (PCC) and to the utility grid at point A as shown in Fig. 1. Both the converters (VSC-1 and VSC-2) are supplied by a common dc bus capacitor with voltage of Vc . The converters can be blocked with their corresponding signal input BLK1and BLK2 . DG-1 and DG-2 are connected through voltage source converters to the microgrid.
The output inductances of the DGs are indicated by inductanceL1 and ,L2 respectively. The real and reactive powers supplied by the DGs are denoted by Pl and Ql . While the real and reactive power demand from the load is denoted by . It is assumed that the microgrid is in distribution level with mostly resistive lines, whose resistances are denoted by RD1and RD2 .
The utility supply is denoted by Vs and the feeder resistance and inductance are denoted, respectively, by and . The utility supplies and to the back-to-back converters and the balance amounts and are supplied to the utility load. The breakers CB-1 and CB-2 can isolate the microgrid from the utility supply. The power supplied from the utility side to microgrid at PCC is denoted by , where the differences and represent the loss and reactive power requirement of the back-to-back converter and their dc side capacitor.
The system can run in two different modes depending on the power requirement in the microgrid. In mode-1, a specified amount of real and reactive power can be supplied from the utility to the microgrid through the back-to-back converters. Rest of the load demand is supplied by the DGs. The power requirements are shared proportionally among the DGs based on their ratings. When the total power generation by the DGs is more than the load requirement, the excess power is fed back to the utility. This mode provides a smooth operation in a contractual arrangement, where the amount of power consumed from or delivered to the utility is pre-specified.
When the power requirement in the microgrid is more than the combined maximum available generation capacity of the DGs (e.g., when cloud reduces generation from PV), a pre-specified power flow from the utility to the microgrid may not be viable. The utility will then supply the remaining power requirement in the microgrid under mode-2 control, while the DGs are operated at maximum power mode. Once all the DGs reach their available power limits, the operation of the microgrid is changed from mode-1 to mode-2. While mode-1 provides a safe contractual agreement with the utility, mode-2 provides more reliable power supply and can handle large load and generation uncertainty. The rating requirement of the back to back converters will depend on the maximum power flowing through them. The
Fig. 2. Converter structure.
• the load demand in the microgrid is maximum and minimum power is generated by the DGs (power flow from utility to microgrid);
• maximum power is generated by DGs, while the load demand in the microgrid is minimum (power flow from microgrid to utility).
The rating issue has to be determined a priori. The microgrid cannot supply/absorb more power than the pre-specified maximum limit
III. CONVERTER STRUCTURE AND CONTROL
The converter structure for VSC-3 is shown in Fig. 2. DG-1 is assumed to be an ideal dc voltage source supplying a voltage of to the VSC. The converter contains three H-bridges. The outputs of the H-bridges are connected to three single-phase transformers that are connected in wye for required isolation and voltage boosting [14]. The resistance represents the switching and transformer losses. In this paper, an LCL filter structure is chosen to suppress the switching harmonics. This filter constitute of the leakage reactance of the transformers, the filter capacitor is connected to the output of the transformers and . Please note that also represents the output inductance of the DG source. The converter structure of DG-2 (VSC-4) is same as DG-1. The converters of the back-to-back converters have same structure but they are supplied by the common capacitor voltage as shown in Fig. 1. It is to be noted that, while VSC-2 has an output inductance (shown in Fig. 1), VSC-1 is directly connected to the point A without an output inductance. This implies that the voltage across the filter-capacitor ( in Fig. 2) of VSC-1 is the voltage of point A on the utility side. It is to be noted that the MAT/ Simlink simulations reported in this paper, all the converter are modeled in detail and no average linear model have been used.
All the converters are controlled in a similar way. The equivalent circuit of one phase of the converter is shown in Fig. 3. In this, u. Vdc1 represents the converter output voltage, where is the switching function that can take on values 1. The main aim of the converter control is to generate u.
From the circuit of Fig. 3, the state space description of the system can be given as
Where uc is the continuous time control input, based on which the switching function is determined. The discrete-time equivalentof (2) is
Let the output of the system given in (2) be vcf . The reference for this voltage is given in terms of the magnitude of the rms voltage V1* and its angle δ1* From these quantities, the instantaneous voltage references for the three phases are generated. Neglecting the PCC voltage assuming it to be a disturbance input, the input-output relationship of the system in (2) can be written as
All the four VSCs are controlled using the above control strategy. Hence, all these controllers require their instantaneous reference voltages.
These are discussed in the next two sections
All the four VSCs are controlled using the above control strategy. Hence, all these controllers require their instantaneous reference voltages. These are discussed in the next two sections.
IV. BACK-TO-BACK CONVERTER REFERENCE GENERATION
This section describe the reference generation for the back-toback VSCs. Both the VSCs are supplied from a common capacitor of voltage as shown in Fig. 1. Depending on the power requirement in the microgrid, there are two modes of operation as discussed in Section II. However the reference generation for VSC-1 derived from them
- VSC-1 Reference Generation
Reference angle for VSC-1 is generated as shown in Fig. 4. First the measured capacitor voltage is passed through a low pass filter to obtain Vcav . This is then compared with the reference capacitor voltage Vcref . The error is fed to a PI controller to generate the reference angleδref. VSC-1 reference voltage magnitude is kept constant, while angle is the output of the PI controller. The instantaneous voltages of the three phases are
derived from them.
The two modes of VSC-2 reference generation are discussed next.
- VSC-2 Reference Generation in Mode-1
VSC-2, which is connected with PCC through an output inductance LG , controls the real and reactive power flow between the utility and the microgrid. Fig. 5 shows the schematic diagram of this part of the circuit, where the voltages and current are shown by their phasor values.
Let us assume that, in mode-1 the references for the real and reactive power be and , respectively, and the VSC-2 output voltage be denoted by and the PCC voltage by . Then the reference VSC-2 voltage magnitude and its can be calculated as
Depending on the real and reactive power demand, these references are calculated, based on which the instantaneous reference VSC-2 voltages for the three phases are computed. It is to be noted that, sign of the active and reactive power references are taken as negative when it is desired to supply the power from the microgrid to the utility side.
- VSC-2 Reference Generation in Mode-2
In mode-2, the utility supplies any deficit in the power requirement through back-to-back converters while the DGs supply their maximum available power. Let the maximum rating of the back-to-back converters be given by and. Then the voltage magnitude and angle reference of VSC-2 is generated as
where and are the voltage magnitude and angle,
respectively, when it is supplying the maximum load. The VSC-2 droop coefficient and are chosen such that the voltage regulation is within acceptable limit from maximum to minimum power supply.
V. REFERENCE GENERATION FOR DG SOURCES
In this section, the reference generation for the DGs is presented.It is to be noted that the reference generations of the DGs are different from reference generation of the back-to-back converters. The control strategy for both the DGs is the same and hence only DG-1 reference generation is discussed here.
A. Mode-1
It is assumed that in mode-1 the utility supplies a part of the load demand through the back-to-back converters and rest of the power demand in the microgrid is supplied and regulated by the DGs. The output voltages of the converters are controlled to share this load proportional to therating of the DGs. As the output impedance of the DG sources is inductive, the real and reactive power injection from the source to microgrid can be controlled by changing voltage magnitude and its angle.
Fig. 6 shows the power flow from DG-1 to microgrid where the voltages and current are shown in rms values and the output impedance is denoted by jX1 . The real and reactive power flow from DG to microgrid can be calculated as
It is to be note that VSC-3 does not have any direct control over. The output inductances of the DGs decouple the real and reactive power at the DG output. Hence from (10), it is clear that if the angle difference is small, the real power can be controlled by controlling , while the reactive power can be controlled by controlling .
Thus the power requirement can be distributed among the DGs, similar to a conventional droop by dropping the voltage magnitude and angle as
where and are the rated voltage magnitude and
angle, respectively, of DG-1, when it is supplying the load to its rated power levels of and . The coefficients and respectively indicate the voltage angle drop vis-à-vis the real power output and the magnitude drop vis-à-vis the reactive power output. These values are chosen to meet the voltage regulation requirement in the microgrid. It is assumed that all the DGs are all converter based and so the output voltage angle can be changed instantaneously. The angle droop will be able to share the load without any drop in system frequency. In a microgrid with frequency droop, the variation of with normal load changes tends to be much higher than system grid frequency variation. In trying to correct this using low droop coefficient may lead to large variations in the frequency. Angle droop avoids this variation in frequency to some extent. A comparison of performance between angle and frequency droop is discussed in Appendix A.
To show the power sharing with angle droop, two DGs with a load is considered as shown in Fig. 7. The voltages and the It is to be noted that the value of and are very small compared to the value of and ( is ten times of in the example where ). Moreover since the microgrid line is considered to be mainly resistive with low line inductance and the DG output inductance is much larger,
VI. RELAY AND CIRCUIT BREAKER COORDINATION DURING ISLANDING AND RESYNCHRONIZATION
The reference generations described in Section IV for DGs and back-to-back converters are totally independent of each other. In mode-1, once the desired value of real and reactive power flow through the back-to-back converters is set,
the rest of the required power will automatically be shared amongst the DGs. In mode-2, the DGs supply their maximum available power while the extra the power requirement from utility is supplied through the back-to-back converter. When a DG reaches its maximum available power, it broadcasts it to VSC-2 control center. initiates the tripping of CB-2 (Fig. 1) and the signal blocks VSC-1.
The same logic is also used for the tripping CB-1 the DGs, even during islanding and resynchronization. But proper relay breaker coordination, along with converter blocking, will Fig. 8 shows the logic diagram used for this and the blocking of VSC-2. The rate of rise of current is monitored by the protection scheme. When it exceeds a threshold value in response to a fault in the utility grid, the output of the Protection Scheme (Fig. 8) becomes high. reach their available limits.
The mode change is initiated when all the DGs broadcast signals, no other communication is needed between the back-to-back converters and be required to maintain the voltage of the dc capacitor during islanding and resynchronizationpurpose, where Trip_Signal
VII. SIMULATION STUDIES
Simulation studies are carried out in MAT Simlink (version 7.2). Different configurations of load and its sharing are considered. The DGs are considered as inertia-less dc source supplied through a VSC. The system data are given in Table I. The droop coefficients are chosen such that both active and reactive powers of the load are divided in a ratio of 1:1.25 between DG-1 and DG-2. Some of the simulation results to indicate the accuracy of the proposed control are listed in Table II, given in Appendix B.
- Case-1: Load Sharing of the DGs With Utility
If the power requirement of the load in microgrid is more than the power generated by the DGs, the balance power is supplied by the utility through the back-to-back converters. The desired power flow the utility to the microgrid is controlled by (7) and (8), while droop (10) controls the sharing of the remaining power. It is desired that 50% of the load is supplied by the
utility and rest of the load is shared by DG-1 and DG-2. The impedance load of Table I is considered for this case. Fig. 10 shows the real and reactive power sharing between utility and the DGs. Fig. 11(a) shows the phase-a reference and output voltage, whereas three-phase voltage tracking error is shown
B. Case-2: Change in Power SupplyFromUtility
If the power flow from the utility to the microgrid is changed by changing the power flow references for VSC-2, the extra power requirement is automatically picked up by the DGs. Fig. 13 shows the real and reactive power sharing, where at 0.1 s the power flow from the utility is changed to 20% of the total load from the initial value of 50% as considered in Case-1.
It can be seen that the DGs pick up the balance load demand and share it proportionally as desired. The unchanged real and reactive load power during the change over proves the efficacy of the controller for smooth transition. Fig. 14 shows the PCC voltage and change in current injection at PCC fromutility. It can be seen that the PCC voltage remained balanced and transient-free, while the injected currents reach steady state within four cycles.
C. Case-3: Power Supply From Microgrid to Utility When the power generation of the DGs is more than the power requirement of the load, excess power can be fed back to the utility through the back-to-back converters. It is desired that the utility supplies 50% of the microgrid load initially. At 0.1 s, however, the same amount of power is fed back to the utility by changing the sign of the power flow reference for the back-to-back converters. The DG output increases automatically to supply the total load power and power to the utility, as evident from Fig. 15.
IX. CONCLUSIONS
In this paper, a load sharing and power flow control techniqueis proposed for a utility connected microgrid. The utility distribution system is connected to the microgrid through a set of back-to-back converters. In mode-1, the real and reactive power flow between utility and microgrid can be controlled by setting the specified reference power flow for back-to-backconverters module. Rest of the power requirement in the microgrids shared by the DGs proportional to their rating. In case of high power demand in the microgrid, the DGs supply their maximum power, while rest of the power demand is supplied by utility through back-to-back converters (mode-2).
A broad castsignal can be used by the DGs to indicate their mode change. However only locally measured data are used by the DGs and no communication is needed for the load sharing. The utility and microgrid are totally isolated, and hence, the voltage or frequency
fluctuations in the utility side do not affect the microgrid loads. Proper switching of the breaker and other power electronics switches has been proposed during islanding and resynchronization
process. The efficacy of the controller and system stability is investigated in different operating situation with various types of loads.
APPENDIX A
To show the relative differences between the angle and frequency droop controllers, we have chosen a simple system as shown in Fig. 7. The frequency droop controller is given by[1]–[4] (A1) The output impedances of the two sources are chosen in a ratio of 1:1.33 and the powers are also chosen in the ratio of 1.33:1.No reactive power droop has been used and the voltage magnitudes are held constant. Both frequency and angle droop controller gains are chosen at 50% of their respective marginal stability points. The VSCs and DGs ratings for both cases are assumed to be identical.
The load in Fig. 7 is assumed to be resistive. To represent random changes of customer load, the conductance is chosen as the integral of a Gaussian white noise source with zero meanand standard deviation of 0.01 Mho. The output inductances of the two converters are 25 mH and 18.8 mH. The impedance ofline 1 is while impedance of line 2 is .frequency variation and power output of DG-2 with frequency droop controller, while those with angle droop controller are shown in Fig. 29. It can be seen that with the frequency droop controller, the relation between frequency deviation and power output obeys (A1). A similar relationship also exists between angle and output power with angle droop control (11), which is not shown here. The variation in frequency with the frequency droop controller is significantly higher than that with the angle droop controller. The standard deviation for the window shown is 0.153 rad/s with the frequency droop controller, while it is 0.0011 rad/s with the angle droop controller. It can also be seen that the mean frequency deviation is much larger in case of frequency droop than in angle droop. This demonstrates that the angle droop controller generates a substantially smaller frequency variation than the conventional frequency droop controller
. The output power and current of DG-1 is shown in Fig. 30 for both frequency and angle droop controllers. Since the outputcurrents in this figure are essentially the same and the DGs are operated at same constant voltage of 1000 V in both cases, the required power of the VSCs is also the same.
As the load is not modeled as frequency dependant, the total power being supplied under both control schemes is also closely matched, as evident from Fig. 30. The switching frequency in both the cases is the same. Thus the converter requirements are the same in both the control schemes. For a given frequency error, there will be a finite (proportional) response from the frequency droop controller. In the same situation, the angle droop controller output will continue to ramp until the frequency error is corrected. In normal operation, this will give a superior transient correction term in the angle droop control output, while the steady state power matches the load demand in both control schemes.
APPENDIX B
Some of the simulation results to indicate the accuracy of the proposed control are listed in Table II.
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