Impact of Distributed Generation on Power System Protection

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protection schemes used in the distribution system need to be re-evaluated with the ... automatic reclosing and manual switching operations and cause safety ... damage protective system like instrument transformers, surge arresters as well as ...
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Impact of Distributed Generation on Power System Protection Shah Arifur Rahman, Member, IEEE, and Byomakesh Das, Member,IEEE

Abstract—This paper presents the impacts of distributed generation (DG) on power system protection. With the increase in DG penetration to the power system network, it has become necessary to evaluate the potential impacts of DG on the existing protection schemes through detailed simulation and protection studies to ensure reliability and security of the system. A radial feeder model with existing protection system and DG are modeled in PSCAD/EMTDC software. Common protection issues such as false tripping, nuisance tripping, unintentional islanding, neutral shifting, resonance and blinding protection are discussed and simulated. Relay co-ordination characteristics are analyzed before and after addition of DGs. Possible mitigation methods are demonstrated with simulation results and relay coordination curves. Index Terms— Circuit breakers, distributed generation (DG), power system, protection, PSCAD, relays, resonance.

I. INTRODUCTION

T

HE incorporation of distributed generation (DG) into distribution systems can offer several advantages. However, besides providing many benefits, DGs may introduce several interfacing issues. Hence, impacts of DGs on existing distribution system must be evaluated thoroughly in order to ensure reliability of the system. Among all the issues, protection issues are considered a major concern as it directly relates to safety and reliability of the system. Conventional distribution system is radial in nature where a single source feeds a network of downstream feeders. Proper coordination among different protective devices are designed in order to ensure the protection of the entire network [1]. After the connection of DGs, distribution network no longer is radial and DG may result in bidirectional power flow and may affect network parameters such as voltage, current etc. This may lead to lack of coordination among the different protective devices in the system [2], [3]. Thus, traditional protection schemes used in the distribution system need to be re-evaluated with the integration of DG. The main issues related to power system protection due to integration of DGs are blinding of protection, false tripping of feeders, nuisance tripping of production units, unintentional islanding, fault level, neutral shifting, resonance, automatic recloser out of synchronism [2]-[5]. Different papers have demonstrated these issues with simulations and examples. Shah Arifur Rahman is with the University of Western Ontario, London, ON, N6A 5B9, Canada (e-mail: [email protected]). Byomakesh Das is with the University of Western Ontario, London, ON, N6A 5B9, Canada (e-mail: [email protected]).

In [2]-[5], effects of DG on protective device coordination such as fuse-fuse, relay-relay, and fuse-recloser are demonstrated with proper coordination graphs and it has shown that DGs can affect the coordination between protective devices. False tripping of feeders due to contribution of short circuit currents from DGs to the fault on the adjacent feeder is shown on [2]-[6]. Similarly blinding of protection due to connection of DG adjacent to the primary substation and Nuisance tripping of production units along with methods of mitigation are demonstrated in [4]-[9]. Unintended islanding issue and its detection methods are demonstrated with various scenarios in [10]-[13]. Increased /decreased fault level and overvoltage due to neutral shifting and resonance, ferro-resonance along with the recommendation for addressing these issues are demonstrated in [5]. Similarly automatic recloser synchronism issues with different modes of operations of DGs and different fault conditions are demonstrated in [14]-[15]. This paper presents a detailed simulation of most common issues such as false tripping of feeders, nuisance tripping of DGs, unintentional islanding, neutral shifting, short circuit level, resonance and blinding of protection with a radial feeder network in PSCAD/EMTDC software for both three phase and single phase fault scenarios. Relay coordination graphs are drawn to analyze the coordination between different relays with and without addition of DGs. Probable mitigation methods are simulated and discussed to address different issues. The remainder of section is organized as follows. Section-II describes all the protection issues with the integration of DGs into distribution system. Section-III describes the study system along with modeling of the protection system and presents the relay-coordination graph of the existing distribution system. Section-IV describes the demonstration of all the issues with integration of DGs through simulation results and relay coordination curves. Section-V presents the mitigation of some of the issues through relay coordination, DG resizing and relocation. This paper is concluded in section-VI. II. PROTECTION ISSUES INCORPORATING DGS In the following section most common issues related to integration of distributed generation to distribution system protection are discussed along with possible mitigation methods. A. False Tripping of Feeders Interconnection of DGs to a distribution feeder may result

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in false tripping of a healthy feeder. When a fault occurs in an adjacent feeder, DG installed in healthy feeder may also contribute to the fault current. If the DG contribution to the fault exceeds the pick-up level of over current protective devices connected to healthy feeder, then protective devices may trip causing healthy feeder out of service before actual fault is cleared in faulted feeder. B. Nuisance Tripping of DG Nuisance tripping is termed as disconnection of DG or any of the utility breakers for faults beyond its protective zones. Nuisance tripping may happen due to power surges in the DG facility or due to fault outside DG facility [8], [9]. Power Surges in a distribution network occur due to loss of large load such as motors in the presence of a DG. Loss of large load may lead to export of excessive power to the grid causing relay to trip. Similarly fault outside the protective zone may cause nuisance tripping of production units. This can lead to a sudden loss of generation from DGs. C. Unintentional Islanding The occurrences of unintentional islanding in a distribution network in the presence of DGs are due to tripping of utility breakers or de-energization of utility feeder for maintenance purpose. Due to the tripping of feeder breaker some portions of power system are disconnected from the grid and are fed by DG. This Islanded operations of DGs are avoided as it may lead to unacceptable limits of operating voltage and frequency, other power quality parameters, may complicate both automatic reclosing and manual switching operations and cause safety hazards to the working personnel. D. Neutral Shifting Neutral shifting occurs when distribution system becomes ungrounded after the isolation of the feeder breaker due to a single-line to ground fault. This is primarily due to the interconnection transformer. If the transformer used to interface DG with the utility has a delta or ungrounded Wye connection on the utility side, then this neutral shifting can cause overvoltage on the other un-faulted phases. This overvoltage on the other healthy phases could be 1.73p.u. This is a serious consequence which can damage customer equipments and may cause some safety hazards. Hence, to protect the customers normally surge arresters are placed in selected location [5]. E. Increase in Short Circuit Levels Impacts of different types of DGs to the short circuit level of a distribution network depend on size and location of DGs. Typically short circuit contribution from an Inverter based DGs are compared to other DG types. As consequences of increased fault current, it may cause Fuse-Fuse, Fuse-Recloser, and Relay-Relay coordination failure which can lead to malfunction of protection operation [3]. Fault contribution from DGs also depends on the transformer connection between DG and Utility. If DG transformer is Wye grounded on utility side it can contribute to the zero sequence current for any fault on the utility side. So any fault on the utility side or

on the DG side must be correctly identified by the corresponding protective devices and coordination must be taken to ensure proper operation of protective devices. F. Blinding of Protection Blinding of protection refers to desensitization of feeder relay in a faulted condition due to interconnection of DG to a distribution feeder. When a fault occurs in a feeder with DG connected to it, there would be a contribution of fault current from DG as well as grid. Fault contribution depends on network configuration, grid impedances, size and location of the DG. Interconnection of DGs close to the primary substation may result in decrease of fault current contribution from grid and may increase in total fault current. Due to reduction in fault current; it may happen that fault current seen by the relay never reaches pick-up current. So, the protection system based on over current relay principles may not operate because of reduced grid contribution until the DG unit trips. Thus DG with a relevant contribution to fault current can affect the sensitivity of protection system which can lead to serious consequences on power system. To mitigate this type of operational conflicts with addition of DGs, relay settings of the feeder relay need to be reduced upon addition of the DGs to the same feeder. G. Resonance DGs are connected to the network after extensive study of network resonance by system operators. So during normal operations, resonance may not occur in the system. However due to unwanted islanding or intentional islanding, resonance may occur in a distribution network in presence of DG due to interaction between system impedances and DG terminal capacitor and any capacitor present in the network. This may cause overvoltage in the system causing damage to network and customer equipments. Two types of resonance can occur in distribution network in presence of DG which is described as follows. i) Linear Resonance During intentional islanding conditions, interaction between generator reactance with system impedance can cause resonance with the existing compensating capacitors. Similarly, during asymmetrical fault condition, the total reactance changes as the sequence reactances becomes connected in different order (e.g, series and/or parallel combination). This may cause resonance with existing compensation capacitor of the system and is taken care of by changing the system reactances with switching capacitors or DGs. ii) Ferro-resonance Ferro-resonance occurs due to interaction of system capacitance and variable inductance offered by transformer due to core saturation in ungrounded system. This core saturation occurs mainly due to DC offset caused by switching, energization of equipments in presence of DG etc.. Ferro-resonance causes overvoltage in the system which can damage protective system like instrument transformers, surge arresters as well as DG transformers. Hence, the common practice to mitigate this issue to damp out the overvoltage as

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fast as possible from instrumentation transformer which operates relay to isolate the DG from the system. Normally, to damp out this kind of high level overvoltage a damping resistor is used at the secondary of instrumentation transformer with an auxiliary winding in open delta configuration [19]. H. Automatic Reclosing Interconnection of DG may affect the operation of auto reclosing devices during the fault. When a DG unit continues to operate during the open interval of the re-closer, fault arc may not be extinguished. This might lead a temporary fault to become permanent. Another potential problem could be connecting two asynchronously operating power systems. This can be happened when re-closer connects an islanded part which is operating at a different frequency due to active power imbalance to another network operating at power frequency. Hence, in order to make a safe operation of power system, DG unit must be disconnected before re-closer. I. Fuse Saving Operation Fuse Saving schemes normally employed in urban/rural areas to make longevity of fuse lifespan. Normally, fuse operation is coordinated with feeder breaker or re-closer so that during the fault feeder breakers or re-closers are operated quickly than the fuses. This is accomplished by setting breaker or re-closer curves well below the fuse curves for first 2 to 3 cycles for faster operations followed by 2 to 3 times

delayed operations. The faster operation is designed so that fuse would not melt for a temporary fault and temporary fault would be cleared without blowing the fuse. As DG contributes fault current, hence fuse saving operation might not be possible. III. STUDY SYSTEM AND MODELING The study system [16] is comprised of three feeders, feeding a number of residential, commercial and industrial loads in a simple radial distribution system. The detail parameters of the study system are given in Appendix. In Fig. 1, the study system is incorporated with non directional over current relays to protect respective feeders. The transformer is protected by using a fuse placing on grid side or High Voltage (HV) side of the substation transformer. This study is done with transient simulation software PSCAD/EMTDC. In PSCAD/EMTDC standard library, the inverse time over current protection relay module is available but the fuse characteristic module is unavailable. As a result, the fuse characteristic curves can’t be plotted or examined in PSCAD/EMTDC. So, for simplicity of analysis and demonstration, it is assumed that the fuse at HV side is always coordinated with LV side relay settings. And hence only the co-ordination of LV side relay is demonstrated in this project paper.

Fig. 1. One line diagram of the study system including the protection system.

Before adding any DGs in the system, the co-ordination of the relay time settings are done by using the following formulae as given in [17]: ‫ݐ‬௢௣

‫ܣ‬ = ܶ‫ ܦ‬൤ ௣ + ‫ܤ‬൨ ‫ ܯ‬−1

(1)

‫=ܯ‬

‫ܫ‬௜௡௣௨௧ ‫ܫ‬௉௜௖௞௨௣

1.1 × ‫ܫ‬௙௔௨௟௧ × ‫ܨܣ‬ ‫ = ܶܫ‬൤ ൨ ‫ܶܥ‬௥ × ܰ

(2) (3)

Where, ′‫ݐ‬௢௣ ′ is the relay operating time in sec, ′ܶ‫ܦ‬′ is the time dial setting of the relay, ′‫ܯ‬′ is plug multiplier setting,

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TABLE I RELAY CHARACTERISTIC CONSTANTS AND EXPONENTS POWER

Characteristics

A

B

p

Moderately Inverse Very Inverse Extremely Inverse

0.0515 19.61 28.2

0.114 0.491 0.1217

0.02 2.0 2.0

With equations (1) and (2), the settings of the relays are selected and tabulated in Table II. The breaker ‘BRK_S’ act as back up protection devices for the feeder breakers (BRK_F1, BRK_F2 and BRK_F3) as well as the primary protection devices for main bus. The fastest operating time for the feeder breakers are considered as 0.15 sec whereas for ‘BRK_S’ it is considered as 0.55 sec [17]. The fault levels are determined at each breaker point by applying the Thevenin’s theorem in conventional way. From Table II it can be seen that the BRK_S is using moderately inverse characteristic of relay instead of extremely inverse characteristics to response the BRK_S within the specified fault duration of 5 sec for a failure of primary protection of feeders.

impedances. For a fault on any feeder the secondary breaker ‘BRK_S’ operates only when any of the primary protection fails to operate. For instance, refer to Table III, for a fault at N-1 of feeder-1, the primary feeder breaker ‘BRK_F1’ operates within 0.15 sec; if in case it does not operate at all then substation breaker ‘BRK_S’ will operate at 0.54 sec. It is also observed that once primary breaker of any feeder operates, the secondary feeder breaker (BRK_S) does not operate at all. However, it can be observed from relay coordination chart and Table III, that the study system without having any DGs is well coordinated for fault at anywhere on the feeders and protect the system by operating the corresponding circuit breaker within specified time period. Hence, the system is ready to demonstrate the aforementioned protection issues which are illustrated in the subsequent chapters. 2

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X: 3100 Y: 91.1

Operating time (sec)

′‫ܶܫ‬′ is instant tripping settings in ampere refer to relay side, ′‫ܨܣ‬′ is the asymmetrical factor which can be chosen between 1.15 to 1.45, ′‫ܶܥ‬௥ ′ is the current transformer turn ratio and can be selected based on maximum load, ′ܰ′ is the turns ratio of the transformer for the relay settings at HV side of substation transformer (if any), ′‫ܫ‬௙௔௨௟௧ ′ is the fault current at the point of corresponding relay-breaker location, ′‫ܫ‬௜௡௣௨௧ ′ is the current seen by relay, ′‫ܫ‬௉௜௖௞௨௣ ′ is the pickup current setting for the relay which is equal to the number of tap chosen based on maximum load current with a safety factor of 1.5. In equation (1), ‫ܣ‬, ‫ ݌ ݀݊ܽ ܤ‬are the standard constants defined in [18] based on relay characteristics as follows:

BRK-F1 BRK-F2 BRK-F3 BRK-S Min-IF

X: 1.21e+004 Y: 91.1

1

10

Max-IF

0

10

-1

10

2

10

3

10

4

10

5

10

Relay Current (amp)

Fig. 2. Co-ordination curves for all the breakers in the system before adding DGs.

TABLE II RELAY SETTING PARAMETERS FOR BREAKERS

BRK_F3 BRK_S

500/5

Tap Set Pt. 3.0

TD Set Pt. 1.09

Max. Fault Level 18.1kA

Min. Fault Level 3.08kA

TABLE III BREAKER OPERATING TIME AND LOCATION OF FAULT WITHOUT ADDING DGS IN THE SYSTEM

Fault Location Feeder

700/5

4.0

0.82

17.1kA

4.58kA

600/5

4.0

0.93

18.1kA

3.11kA

1800/5

4.0

0.43

26.7kA

-

To analyze the co-ordinations between relays equations (1) to (3) are used to plot coordination curves using MATLAB/Simulink and is presented in Fig. 2. It is shown that all the relays are covering the operating current ranges between the feeder end fault current (3.1kA) denoted by first vertical axis ‘Min-IF’ and the breaker point fault current (12.1 kA) denoted by second vertical axis ‘Max-IF’ that is occurring at the beginning of feeders. Table III shows the operating time of the relays for faults at different nodes on the feeders. It is seen that, the operating time varies with the location of fault as the fault level varies node to node due to line

Operating Time From Fault Instance (sec.)

Node BRK_F1 BRK_F2 BRK_F3 BRK_S* N-1 0.15 0.54 N-2 0.176 0.647 N-3 0.208 0.75 N-4 0.25 0.855 N-5 0.301 0.959 N-6 0.36 1.063 N-7 0.43 1.168 N-1 0.15 0.555 N-2 0.217 0.68 N-3 0.315 0.8 N-4 0.44 0.92 N-1 0.156 0.54 N-2 0.20 0.65 N-3 0.275 0.755 N-4 0.365 0.864 N-5 0.487 0.968 N-6 0.608 1.078 N-7 0.758 1.19 * when primary breakers (BRK_F1, BRK_F2, BRK_F3) do not operate.

Feeder-1

BRK_F2

CT Ratio

Feeder-2

BRK_F1

Relay Characteristics Extremely Inverse Extremely Inverse Extremely Inverse Moderately Inverse

Feeder - 3

Breaker Name

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IV. SIMULATION OF PROTECTION ISSUES WITH DGS The following are the demonstration of protection issues with the presence of DGs. A. False Tripping Table IV, depicts the scenario for the analysis of false tripping in the presence of DGs. TABLE IV FALSE TRIPPING SIMULATION RESULTS DG Size and location Size-22.5 MW Feeder- 1 Node-1

Fault location

Operating Time (sec.) BRK_F1 0.32

Feeder – 2 Node-4

BRK_F2 0.44

BRK_F3 No operation

C. Neutral Shifting A single line to ground fault is occurred in phase ‘A’ of feeder-1 having a DG of 8MW at node-5, feeder breaker ‘BRK_F1’ operates within 0.4 sec from the fault instant and makes the feeder isolated from the grid. In this condition, the isolated feeder is fed from the DG alone through an ungrounded transformer (delta or ungrounded wye on utility side). As a result of isolation of feeder-1 from grid DG causes over-voltage to its other two healthy phases (phase B and Phase C) during the fault within 5.4 to 7 sec due to shifting of neutral on those two phases as depicted in Fig. 3. Once, the fault is cleared at 7 sec, the system voltage becomes restored to its nominal value.

The undesired tripping is occurring at feeder-1 breaker ‘BRK_F1’ for fault at feeder-2 which should be cleared only by operating the feeder breaker ‘BRK_F2’. Hence, false tripping is occurred at feeder breaker ‘BRK_1’. B. Nuisance Tripping The simulation results for the ‘Nuisance Tripping’ scenario is tabulated in Table V and the relay co-ordination curves are presented in Fig. 3 by coordinating between feeder 3 breaker and DG breaker only. TABLE V NUISANCE TRIPPING SIMULATION RESULTS DG Size and location Size-13.5 MW Feeder- 2 Node-2

Fault location

Operating Time (sec.)

Feeder – 3 Node-2

BRK_F2 No operation

BRK_DG 1.05

BRK_F3 1.2

From the table it can be observed that although the DG is connected on feeder-2, the DG breaker is operating for a fault at feeder-3 which demonstrates the nuisance tripping of the generation unit. From the coordination graph in Fig. 3, it can be seen that within the fault level of the system (as indicated within ‘Min-IF’ and ‘Max-IF’), the DG breaker operates before breaker ‘BRK_F3’ because some part of the DG relay curve lies below the ‘BRK_F3 curve. 2

Operating time (sec)

10

BRK-F1 BRK-F2 BRK-F3 BRK-S BRK-DG Min-IF

1

10

Max-IF

0

10

X: 4085 Y: 0.5373

-1

10

2

10

3

10

4

10

5

10

Relay Current (amp)

Fig. 3. Co-ordination curves for all the breakers in the system after adding DG on feeder-2, node-2.

Fig. 4. Overvoltage due to single line to ground fault.

D. Resonance Fig.5 shows the impedance diagram of the network. It can be seen that network impedances vary according to the different operating conditions of the network. When there is no islanding condition or there is no fault, the system impedance diagram shows that there is only one peak occurring at 11th harmonics. When network is operating in islanded mode due to DG or if there is a fault on the system, network impedances changes and it is observed that peak is occurring at lower order frequency .If there is any lower order harmonics already present in the system, it can cause overvoltage due to large impedance seen by the lower order harmonics current.

6 600 System WIth DG With Islanding Mode With Assymetrical Fault

X: 620 Y: 578.4

500 X: 340 Y: 423

Impedance (ohm)

400

300 X: 340 Y: 217.4 X: 1200 Y: 178.3

200

100

0

Now a DG of 10 MW is connected to the feeder-1 at node 2 on the downstream of relay. It can be seen from Fig. 8, that the current seen by relay before and after the occurrence of fault has reduced. In this scenario, relay current before the fault is 200 A and after the fault it is 2.07 kA which demonstrates the reduction of fault level seen by the feeder relay.

X: 230 Y: 55.6

0

200

400

600

800 1000 1200 Frequency (Hz)

1400

1600

1800

2000

Fig. 5. Effect of DG on system resonance for feeder-1.

E. Unwanted Islanding Fig.6 depicts the overvoltage condition due to islanding mode operation of feeder-1. At t=3 sec, feeder-1 breaker opens causing an island condition in the feeder-1. It can be seen from the figure that system voltage changes from 0.97 p.u to 1.15 p.u causing overvoltage condition in the Island formed by DG of 10 MW for a total feeder load of 8 MW.

Fig. 8. Feeder -1 relay current after addition of DG

G. Blinding of Protection As seen in Fig. 7 and Fig. 8 that the fault level seen by the relay is reduced. This reduction of fault level varies upon the grid strength, the DG contribution to the fault and DG reactance. If the contribution from the DG is too high in a weak strength of feeder-1 then the fault level seen by the feeder relay will be so low such that the feeder-1 relay will no longer operate within specified fault duration until the DG breaker operates. However, as the strength of the system is high in this study model it may not be possible to demonstrate here. V. MITIGATION OF PROTECTION ISSUES AND DISCUSSION

Fig. 6. Overvoltage on all three phases due to islanding of feeder-1.

F. Fault Level Impact of DG on system fault level has been demonstrated in fig .7 and fig.8 respectively. Fig.7 shows the current seen by relay in the feeder-1 before addition of DG. It is shown that before the fault, current seen by the relay in the feeder is 250 A. At t=5 sec, a three phase to ground fault has occurred at the end of the feeder. Hence fault current of 2.18 kA is seen by the relay in feeder-1.

Fig. 7. Feeder-1 relay current before addition of DG

Mitigation of different protection issues are system dependent. The issues causing over voltages like resonance, neutral shifting could do harm to the system which requires extensive study prior to DG integration and careful monitoring of the system. There are several ways like recoordination of relay, re-locating the DG, resizing the DG etc. to improve most of the fault level or over current related issues of the protection system. As DGs, like wind, solar etc. which uses renewable energy resources, are non predictable in nature which might not generate power at all the time. Hence, re-coordination of the feeder breaker relay might create an un-reliable situation. Thus relocation and resizing of DG should be done in order to avoid protection coordination failure. To resolve ‘False Tripping’ issue in this study system, it is observed that by relocating the DG of 22.5 MW to other nodes on feeder-1 did not resolve the issue because of a large amount of reverse power flow to the grid. Hence, the DG is resized to 8.5MW and relocated at node-7 on feeder-1 which resolved the false tripping problem. To resolve the ‘Nuisance Tripping’ problem the pick-up value of relay settings is changed from 3 to 6 for the DG breaker connected at node-2 on feeder 2 and the study results

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are tabulated in Table VI, which shows that there is no ‘Nuisance Tripping’. After changing the pickup settings of the relay, DG breaker only operates for a fault on feeder-2. It can be seen from the corresponding relay coordination curve that the DG relay curve shifts up for the above relay setting and the other feeder breaker (BRK_F1 and BRK_F3) curves lie below the DG relay curve within the operating boundary denoted by two vertical lines, ‘Min-IF’ and ‘Max-IF’, as represented by Fig. 9. TABLE VI BREAKER STATUS FOR THE CHANGE IN PICKUP CURRENT OF DG ON FEEDER-2, NODE-2.

Fault Location

Operating Time From Fault Instance (sec.)

Feeder

BRK_F1 0.15 0.174 0.208 0.25 0.30 0.36 0.428 -

Feeder - 3

Feeder-2

Feeder-1

Node N-1 N-2 N-3 N-4 N-5 N-6 N-7 N-1 N-2 N-3 N-4 N-1 N-2 N-3 N-4 N-5 N-6 N-7

Operating time (sec)

10

10

BRK_F2 0.153 0.224 0.318 0.404 -

BRK_F3 0.154 0.20 0.275 0.37 0.481 0.607 0.756

BRK_DG 0.13 0.1 0.145 0.19 -

Detail data for the study system is given below in tabular form: TABLE VII RADIAL DISTRIBUTION SYSTEM PEAK LOADING

Feeder No.

Feeder Length

No of Nodes

Node Characteristics Node Peak Load

Feeder-1 Feeder-2

12.5 km 8 km

7 4

Feeder-3

12.5 km

7

1 to 7 1 to 4 1,4,7 2,5 3,6

0.012 p.u ,0.9 p.f lagging 0.045 p.u ,0.9 p.f lagging 0.01 p.u ,0.9 p.f lagging 0.015 p.u ,0.9 p.f lagging 0.03 p.u ,0.9 p.f lagging

2

BRK-F1 BRK-F2 BRK-F3 BRK-S BRK-DG Min-IF

1

TABLE VIII BASE PARAMETER

Parameters SBase VBase LG XT

-1

10

Value 100 MVA 22.9kV 0.006H 7% at 60MVA base

TABLE IX DISTRIBUTION SYSTEM NODE MODEL IMPEDANCES

0 X: 3017 Y: 0.8414

10

In this paper a critical literature survey has been presented regarding the protection issues due to adding DGs on radial distribution system (DS) and is demonstrated by modeling in PSCAD/EMTDC. Before demonstrating the issues, non directional inverse time over current relay characteristic has been chosen for analysis and the parameters of the relay settings have been done as per IEEE standard. The relay settings have been verified with simulation results and coordination curves with fault study. To demonstrate the issues, DGs are added to DS. Simulations of different issues have been done for different scenarios and mitigation methods for different issues are discussed and presented with relay coordination curves. This demonstration of DG penetration impact on DS protection and its methods of mitigation are specific to this system and can be used as reference for further studies in this area. VII. APPENDIX

Max-IF

10

VI. CONCLUSION

2

10

3

4

10 Relay Current (amp)

10

5

Fig. 9. Co-ordination curves for all the breakers in the system after changing relay settings of DG on feeder-2, node-2.

It is also evident from Table VI, that the DG on feeder-2 becomes isolated for a fault at anywhere on feeder-2. As a result, the DG does not operate on islanding mode. Hence, the co-ordination of DG breaker with the feeder breaker helps to prevent islanding mode of operation for this case. Islanding detection techniques are not demonstrated in this project which is beyond the scope of this work.

Feeder No.

Load per node

Feeder-1

0.012 p.u

Feeder-2

0.045 p.u

Feeder-3

0.01 p.u for nodes 1,4,7 0.015 p.u for nodes 2,5 0.03 p.u for nodes 3,6

Line Impedance R= 0.3249Ω L=0.001853 H R= 0.3639Ω L=0.002075 H R= 0.3249Ω L=0.001853 H R= 0.3249Ω L=0.001853 H R= 0.3249Ω L=0.001853 H

Load Impedance R= 393.31Ω L=0.505 H R= 104.88Ω L=0.135 H R=471.98 Ω L=0.606 H R=315.81 Ω L=0.398 H R=157.32 Ω L=0.202 H

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VIII. REFERENCES [1]

[2]

[3]

[4]

[5]

[6]

[7]

[8] [9]

[10]

[11]

[12]

[13]

[14]

[15]

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[17] [18] [19]

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IX. BIOGRAPHIES Shah Arifur Rahman (Student Member) received the B.Sc. degree from the Bangladesh Institute of Technology, Chittagong, Bangladesh. He is currently working towards his PhD. degree in Electrical Power Engineering at the University of Western Ontario. His research interests include Grid Integration of photovoltaic solar plants, implementation of FACTS devices and their coordination.

Byomakesh Das was born in India. He graduated from the Biju Pattanaik University of Technology (BPUT),Orissa ,India in 2005.Currently He is pursuing his Master in Engineering Science in the University of Western Ontario, Canada. His employment experience included the Kyocera Corporation, SoftDEL systems pvt Ltd. He has got more than 3 years of experience in Embedded System and SCADA Software. His main area of interests includes grid integration of renewable energy, power system stability studies, distribution system automation and protection.