Page 1 of 9 2013-PSPC-397

The Influence ofInverter-Based DGs and Their Controllers on Distribution Network Protection

Mohammed A. Haj-ahmed Electrical and Computer Engineering Department

The Ohio State University Columbus, OH 43210

Email: haj-ahmed.I@osu.edu

Abstract-The ever growing penetration of distributed

generation (DG) in a distribution network has a profound

impact on the network protection and stability. Traditional

protection schemes and algorithms need to be extensively

investigated as more and more DGs get introduced into the

network. The current version ofIEEE Std 1547 does not present

a comprehensive solution for fault current detection in the

presence of various kinds of DGs. Power electronic inverter­

based DGs are of special concern in distribution network

protection as they are often incapable of providing sufficient

fault current and their controllers play a principal role in the

DG behavior. In this paper, the effects of voltage and current

controllers for inverter-based DGs on industrial and commercial

power system distribution network protection schemes are

investigated. It is shown that the type of controller and its design

parameters during the fault have a direct impact on fault

current levels and duration. A simplitied distribution network

model with inverter-based DG operating under voltage and

current control modes was tested to verify the effects of these

controllers. This paper also proposes an adaptive relaying

algorithm to detect the faults in the presence of inverter-based

DGs with various types of controllers.

Index Terms- Adaptive relaying, current controllers, fault

characteristics, distributed generation, voltage source inverters,

voltage controllers.

I. INTRODUCTlON

Distributed generation (DG) including renewables like solar/photovoltaic and wind power are being increasingly installed by several industries to meet their environmental footprint and sustainability goals. Many DGs make use power electronic inverters for energy conversion to match the grid voltage and frequency [1]. However, such DGs are known to have a great impact on the stability and protection of distribution network [2]. The inverter-based DGs can affect network protection when an electrical fault occurs on account of fault current detection issues [3]-[7]This is because they do not produce high levels of fault current when a short-circuit occurs. The power electronic inverters consist of semiconductor switches such as thyristors or IGBTs that are susceptible to failure when high fault currents are allowed. Besides, small rated DGs also have inadequate inertia to

Mahesh S. Illindala Electrical and Computer Engineering Department

The Ohio State University Columbus, OH 43210

Email: millindala@ieee.org

continuously feed the fault current unlike the traditional large rotating machine generators [8].

The study of fault current characteristics of the inverter­based DGs requires a comprehensive re-evaluation of various protection design aspects. A voltage source inverter (V SI) typically has a dc-link capacitor that is sized to decouple the prime-mover dynamics from those of network. Accordingly, the effect of prime-mover itself on fault current can be neglected, and only the dynamics of inverter with its associated controIler(s) are considered [9]. Moreover, the inverter-based DGs have their own protection to insure safety of semiconductor devices against large overcurrents flowing through them [10]. Usually, this current is in the range of 1-2 times the rated load current [11], [12]. The effect of such an internat protection needs to be considered in the overall network protection scheme since the inverter cannot respond to fault currents with levels lower than its settings. There are principally two types of control schemes that generally govern inverter-based DGs, viz., voltage control and current control [9]. This paper conducts a detailed investigation of network protection schemes for a typical industrial and commercial power distribution system, shown in Fig.I, containing inverter-based DGs. In addition, it also includes a comprehensive analysis of the fault current contributions of various DGs, as weIl as the impact of changes in inverter control between current control mode and voltage control mode on the associated feeder protection.

Adaptive relaying schemes are capable of resolving the detection problems of inverter-based DGs fault currents. These schemes were proposed in the literature for multiple purposes [13, 14]. Such protection schemes are dependable and trustworthy because they employ reliable communication and online data sharing networks. This paper is organized as follows: Section 11 discusses the effects of DGs on distribution network protection and Section III gives a comprehensive coverage of various types of controllers for inverter based DGs. The effects of these controllers on voltage and current waveforms at the occurrence of faults are discussed in Section IV. In Section V, an adaptive protection algorithm to solve the problems discussed in Section IV is proposed. FinaIly, the conclusions are presented in Section VI.

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2013-PSPC-397

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Fig. I: One-line diagram of a typical industrial and commercial power system distribution network with inverter based DG installations

Page 2 of 9

11. INDUSTRIAL AND COMMERCIAL POWER SYSTEM DISTRIBUTION NETWORK PROTECTION

noted that each curve represents both instantaneous (50) and time delay (51) elements.

The feeder protection in industrial and commercial power system distribution networks is generally designed based on two key features, viz, fault current supportability and coordination between protection equipment. It has been customarily designed under the presumption that all energy sources are capable of producing high levels of fault current on the occurrence of a short-circuit fault. That being the case, introducing inverter based DGs that cannot supply a high fault current will necessitate a major revision of such protection schemes. Secondly, the various zones of protection in distribution feeders are defined to facilitate coordination of overcurrent relays, fuses, sectionalizers and auto-reclosers. The zones of protection specify the regions of distribution feeder that each protective device is responsible for protection, and thereby achieve a secure and dependable scheme. Fig.2 illustrates a typical co ordination scenario between various overcurrent relays in a distribution feeder [15]. It is to be

Current

----101+-1 --i0J+1----I0J+1----I� R4 R3 R2 RI

Fig. 2: Overcurrent relay coordination in distribution networks

The presence of DGs affects the protection schemes of the distribution network [16]. Introducing a distributed generator within a distribution feeder will bring disorder to the zones of

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protection within a feeder [17]. A simple scenario is illustrated as shown in Fig. 3 where the introduction of one DG on a distribution feeder led to a change in the protection zone of overcurrent relay. Prior to the installation of a DG on the fee der, the zone of protection of upstream overcurrent relay upstream was defined by the large rectangle in light green color. That is if any fault occurs in the light green shaded area, it must get detected by the relay either instantaneously or with a time delay. However, after the DG installation a portion of the fault current is supplied by it corresponding to its capacity and electrical distance from the fault. This leads to a reduced fraction of fault current drawn from the substation. As a result, the portion of fault current fed from the substation will be small such that the relay upstream does not detect it, especially for the downstream faults that are very close to the DG. Thus, the protection zone of the overcurrent upstream has been reduced to the small rectangle shaded in dark green color. The relay becomes "blind" for faults occurring in the area between the two rectangles.

Coordination of network protection devices is a much more challenging problem when considering a microgrid consisting of several DGs in different operation modes [18]. In order to have adequate coordination between two successive overcurrent devices, the ratio between maximum fault currents seen by each device should be as large as possible. For instance, the ratio of fault current values in a system shown in Fig.4 between point Fl and point F2 is defmed as:

(1)

where IF land IF2 are fault currents at locations F land F 2 respectively, Zs is the source impedance, and ZL is the line impedance between the overcurrent devices.

equivalent circuit

• With DG • WithoutDG

OCR: Over Current Relay DG: Distributed Generator

Fig. 3: Zones of protection change in the presence of DGs

Zs: Source impedance ZL: Line impedance

�""'I,-_

Z_L

:����� _�-+I>I�

Substation equivalent Fl F2

circuit

Fig. 4: Overcurrent devices coordination problem in distribution networks In an isolated microgrid operation mode, the electrical

distance between DGs, loads, and other devices can be very

small. Because of that ZL is very small and the ratio in (1) will become very close to unity. It means that from overcurrent device Rl perspective, the fault currents IF1 and IF2 are almost identical. Consequently, there cannot be a good coordination between Rl and R2.

In addition to the loss of coordination between overcurrent devices, operation und er different microgrid modes will also change short-circuit levels and adversely impact the fault current detection algorithms. If the microgrid is connected to the main grid at the time of a fault, there is sufficient amount of fault current and the overcurrent devices will detect the fault. However, there will be fault current detection problems if the fault occurs in an islanded microgrid. The troubles get further exacerbated if there exist any inverter-based DGs that cannot support adequate fault currents. Under such conditions new fault current detection techniques are required. In [19] and [20], undervoltage based overcurrent schemes were presented to overcome the detection problem. The overcurrent devices in these schemes have low current settings that are triggered by undervoltage elements. However, these schemes may encounter detection problems of different kind when single line-to-ground faults that will not produce sufficient voltage drop occur. Furthermore, they do not consider the effects of inverter internal controls.

Islanding of microgrids containing inverter-based DGs may involve one or more of them transition from operation in current control mode to voltage control mode. This is because in the isolated mode the microgrid should produce its own voltage and frequency. A reverse transition may happen in the grid-connection of the microgrid. Switching from one control mode to another will change fault current contribution of the DGs. It will be shown later that inverter-based DGs operating under voltage control schemes will provide fault currents of greater magnitudes as compared to those under current control schemes. But before that, the key types of controllers for power electronic inverters are elaborated at first.

III. CURRENT AND VOLTAGE CONTROLLED INVERTER B ASED DGs

Many DG systems utilize a three-phase voltage source inverter (VSI) based on pulse-width modulation (PWM) as the utility/load interface. The controls of these inverter based DGs enable them to meet the wide-ranging demands of their integration with the existing distribution network. The advances made in the control of applications like uninterruptible power supplies (UPS) and ac motor drives gave impetus to the design of controllers for inverter based DGs. For all practical purposes, there are chiefly two types of control schemes for regulation of the inverter output [21] - a voltage controller that will enable it to produce a three phase ac voltage matching the utility grid voltage, and a current controller that will force the current supplied to follow a reference control command.

Current controllers for VSIs have become attractive in various power electronic applications including UPS, active power filters, ac motor drives, high power factor ac/dc converters and grid-connected inverters [22]. The current controller type and structure can be precisely tailored for each application as it plays a significant role in the performance of

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the converter as weIl as the power quality of its output. For instance, the ac motor drive requires a wide range of output frequency, whereas in the case of UPS the frequency range is lirnited to a very narrow range. Hence, many types of current controllers were suggested in the literature for various applications [22, 23]. Fig. 5(a) illustrates the current source analogy of an inverter based DG when operating in current control mode. A single-line diagram is indicated in this figure based on three-phase space vector quantities. The current through inverter's outer inductor (i.e. iT), after filter capacitor, is regulated in this mode. Current controlled DGs suffer from the major disadvantage of inability to independently maintain their terminal voltage to the distribution network levels. They rely on the utility grid or other voltage controlled DGs for maintenance of voltage, and in the absence of such a voltage support the current controlIed DG terminal becomes vulnerable to undervoltage faults.

Fig. 5: Analogy of an inverter based DG to (a) current source in the current control mode, and (b) voltage source in the voltage control mode.

On the other hand, voltage controllers have also been applied for VSIs in applications such as parallel connected standalone inverters [24] and plug-and-play operation of microgrids [25]. Fig. 5(b) shows the voltage source analogy of an inverter based DG when functioning in the voltage control mode. In this case, the inverter's filtered output capacitor voltage vector (i.e. vc) is regulated. Inverter-based DGs under voltage control mode have become indispensable as they help in regulating the voltage of microgrid especially during the islanded conditions. Inverter based DGs operating in voltage control mode are unable to precisely regulate their output current, and these are therefore highly susceptible to overcurrent faults upon a short circuit.

The simplified block diagrams of both current controlled and voltage controlled inverters in DG applications are illustrated in Fig. 6(a) and Fig. 6(b), respectively. Such a controller can be irnplemented in a digital signal processor (DSP). Please see the DSP Controls block in Fig. 5. The controller senses inverter output filter current and voltage signals, computes the three-phase active and reactive powers, and generates the three-phase inverter commands to regulate the quantity of current or voltage as the need be. The inner current/voltage control loop in Fig. 6 typically consists of PI controllers for regulating at zero steady-state error the three­phase ac vector quantities in the synchronously rotating (dq) reference frame [22]. It is to be noted that there are alternative approaches to the PI controller, for example the P + Resonant controller, where the three-phase sinusoidal ac quantities in the stationary reference frame can be directly regulated to match with their commanded values [23]. Installed at several sites are many commercial inverter based DGs that also transition between current controlled and voltage controlled modes to operate satisfactorily in both grid-connection and islanded conditions.

IV. INVESTTGA TTON OF CURRENT CONTROLLED AND VOLTAGE CONTROLLED DGs ON DISTRIBUTED NETWORK

PROTECTION

In order to examine the effects of current and voltage controlled inverter-based DG on a distribution network, it was modeled in MATLAB®/Sirnulink™ together with a Thevenin's equivalent of the rest of system in Fig. l. Subsequently, a fault was created across the nearby load and contribution of the inverter based DG to fault current was evaluated. The various operation parameters for inverter based DG were as folIows: 3-phase, 50-kW, 60-Hz, 480-Vac (Iine­line), IGBT based VSI - PWM inverter operating at 3.6 kHz switching frequency with a 750-V dc bus.

The voltage controlled inverter based DG was investigated at first under a three-phase short-circuit with a fault irnpedance of 2 n. Such a high irnpedance fault was chosen in order to avoid triggering any internat inverter protections. Fig. 7 shows the inverter filtered output voltage and current waveforms during the fault occurrence. It was observed, as expected, that the output current of the DG increases instantaneously when the fault occurs. The voltage controller regulates the terminal voltage within the acceptable range during the fault event.

Then again, in the case of inverter based DG being current controlled, the inverter response was examined under a short­circuit fault of irnpedance of 1 mn. Fig. 8 illustrates the inverter filtered output voltage and current waveforms during this fault. In contrast to the voltage controlled DG, the DG under current controller had a regulated output current that was not affected by the fault. However, its output voltage dropped to near zero value.

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Inverter Based DG (IBDG)

(a) Current controlled IBDG

(b) Voltage controlled IBDG

Page 5 of 9 2013-PSPC-397

Active & Reactive Power

Controller

Active & Reactive Power

Calculation

Vdc

Vgrid

VSI

�O ABC/

DQ

ABC/ DQ

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Active & Reactive Power

Controller

Active & Reactive Power

Calculation

Vdc

VSI

�O ABC/

DQ

ABC/ DQ

(b) Voltage controlled DG Fig. 6: Block diagrams of principal types of controllers for inverter based DGs

-200 -300 =-----:�-�cc_----:c�---:"c--�----'-------"-�----.l

Q� Q� Q� Q� Q3 Q� Q� Q� Q� Time (sec)

Fig. 7: DG under voltage control mode: output voltage (top) and output current (bottom) for a short-circuit fault at t = 0.3 sec

As seen in Fig. 7 and Fig. 8, use of purely undervoltage based overcurrent detection algorithms, presented in [19] and [20], will be to the detriment of those DG systems that transition from the current control to a voltage control mode during the islanding of microgrid. An undervoltage controlled overcurrent scheme has lower overcurrent inverse curve setting that is triggered by an undervoltage element. Since the voltage controlled DGs regulate the terminal voltage, they do

not result in an undervoltage fault. And as the current controlled DGs regulate their output current, they do not detect the overcurrent fault.

0.24 0.26 0.28 0.3

Time (sec)

0.32 o.� o.� 0.38

0.32 o.� o.� 0.38

Fig. 8: DG under current control mode: output voltage (top) and output current (bottom) for a short-circuit fault at t = 0.3 sec

In the earlier tests, the load connected near inverter based DG was assumed to be purely resistive. For the current controlled inverter, the transient overshoot of output current waveform in Fig. 8 vanished rapidly that it could be ignored.

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2013-PSPC-397 Page 6 of 9

Interestingly however, the same transient overshoot has skyrocketed and could not be neglected when the fault occurred in the presence of an inductance in parallel with the 50-kW load, as shown in Fig. 9 for three decreasing values of power factor. Such transient overshoots are not unusual and in fact have been observed in the output of current controlled photovoltaic (PV) inverters during tests on commercial units, as reported in [8, 26]. Fig. 10 displays the voltage and current waveforms for a PV unit with a short circuit at its terminal. As seen in this figure, there is a large overshoot at instant of the fault. Special care needs to be taken under such circwnstances because it increases the Iikelihood of triggering the inverter protection and/or the instantaneous overcurrent settings of the feeder protective relays. From Figs. 9 and 10, it can be seen that the transient overshoots may reach very high values compared to the rated current, and its duration may extend up to a few milliseconds depending on the power factor. Fig. 11 illustrates a proportionately increasing trend between the transient overshoot of fault current contribution from inverter based DG and inductive kV ARs of the load.

0.22 0.24 0.26 0.28

0.22 0.24 0.26 0.28

0.22 0.24 0.26 0.28

0.3

0.3

0.3

Time (sec)

0.32 0.34 0.36 0.38

0.32 0.34 0.36 0.38

0.32 0.34 0.36 0.38

Fig. 9: Output current of DG under current control mode with different load reactive power with a fault at t = 0.3 sec. Top (0 kV AR), middle (3 kV AR),

bottom (10 kVAR)

The influence of changing PWM inverter switching frequency on its fault current contribution of has also been tested. A lower switching frequency tends to increase the fault current contribution from inverter because of its lirnited current controller bandwidth; this is illustrated in Fig. 12 for three different values of PWM carrier frequencies.

Finally, the effect of a changing fault occurrence time was investigated. Faults were chosen to occur at peak, half of peak, and zero-crossing time instants of the load terminal voltage. The results in this case are presented in Fig. 13. It was observed that the transient overshoot of fault current contribution from inverter, increased considerably when the fault occurred at the instant of peak voltage as compared to that during half of peak voltage or voltage zero crossing. Therefore, when considering instantaneous overcurrent settings for faults, the time of occurrence of peak terminal voltage must be considered.

Based on all the above observations, a novel adaptive relaying algorithm for the inverter-based DGs is proposed in the following section.

"'0 1- Inverter Voltage - Inverter Currenl

'00

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Fig. 10: PV inverter's current and voltage waveforms for short circuit faults at the terminal. From NREL Technical Report [8].

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Fig. 11: Transient overshoot of fault current contribution of a current controlled inverter based DG as the load inductive kV ARs are increased

Fig. 12: Output current response of current controlled DG with different PWM switching frequencies for a fault at t = 0.3 sec. Top (1500 Hz), middle

(6000 Hz), bottom (10000 Hz).

978-1-4673-5202-4/12/$31.00 © 2013 IEEE

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Page 7 of 9 2013-PSPC-397

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Fig. 13: Output current of current controlled DG with different fault starting times. Fault at the instant of peak voltage (top), - at half of peak voltage

(middle), - at voltage zero-crossing (bottom)

V. PROPOSED ADAPTIVE RELA YTNG ALGORITHM

In the recent past, many fault detection algorithms and techniques were suggested in the literature [S], [11], [27]. However, they did not address adequately the new-found conditions of greater significance of inverter control methods on the fault current contributions. Even the IEEE Std IS47 does not present a comprehensive solution for fault current detection in the presence of inverter-based DGs [28]. It was c1early identified in the previous section to have a major influence on the distribution network protection. Proceeding on that ground, a novel algorithm that considers the impact of inverter-based DG controllers is proposed in this section. This algorithm also adapts to any changes in microgrid mode of operation as weIl as to transition of inverter based DG operation between current control and voltage control modes. Furthermore, it takes into consideration the effects of load power factor, PWM switching frequency and fault timing. Fig. 14 presents a flow diagram of a generalized adaptive relaying algorithm. It is applicable for fault current detection among grid-connected and islanded microgrids in the presence of inverter-based DGs with diverse types of controllers.

During grid-connected mode of operation of the microgrid, there are no fault detection problems. This is because the main grid provides sufficient amount of fault current. Hence, overcurrent relays (SO, SI) on the grid side function properly at the time of a fault and they can send a tele-protection signal to the DG side relays. However, during the islanded mode of operation of the microgrid, further analysis of inverter control methods is required. For islanded microgrids dominated by inverter-based DGs under voltage control mode, overcurrent relays (SO, SI) with low settings and neutral earth fault current (SON, Sl N) relays are generally sufficient to detect the faults. Fig. 14 illustrates a general procedure to lower the overcurrent relay settings. The process of making changes to the settings has become simple and easy to implement in the commercial relays sold nowadays. For instance, the setting modification procedure, shown in Fig. IS, in using Schweitzer Engineering Laboratories overcurrent relay (SEL-3S1) requires adjusting (minimizing) the instantaneous overcurrent element: SOPIP or SOP6P, and adjusting the time overcurrent elements: SIPl T or SlP2T that

also include the pick-up settings: SIP IP/SIP2P, the curve type settings: SIPl C/SIP2C, and the time dial settings: SIPl TD/SIP2TD. On the other hand, when the inverter-based DGs in islanded mode of operation of microgrid are under current control mode, faults will cause a drop in voltage that can be detected either by undervoltage relays (27), or else for faults with high impedance earth fault devices (SON, SlN) must be employed. Likewise, a similar procedure can be easily implemented for products from other manufacturers as weIl.

Grid Connected

Overcurrent Protection

50/51 or via tele-

protection

Apply Low Settings

Voltage Mode

Overcurrent Protection

50/51150N/51 N

Compare Measured Values with Settings

Current Mode

Undervoltage Protection

27

Consider Load and Fault Parameters

Fig. 14: Flow diagram of the proposed adaptive relaying algorithm

The recommendations for settings of SEL-3S1 in different operation modes for the industrial and commercial power system in Fig. 1 are shown in Table 1. It is to be noted that transferring from a grid connected operation mode to an islanded mode will move the relay settings from group 1 to group 2, and in this case the overcurrent and earth fault settings are more sensitive. The word bit SIPTD is responsible to move the overcurrent curve from an upper curve to a lower one as shown in Fig. IS. Changing the controller of the DG from voltage controlled mode to the current controlled mode will make the relay switch from

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2013-PSPC-397 Page 8 of 9

setting group 2 to setting group 3, where the undervoltage Setting Group Selection Equations settings have two steps and each one has its own tripping time.

Current

Group I settings: High

Group 2 settings: Low

Si: 5lPl T

: .. 1 50: 50PIP

\" " / L �

Fig. 15: SEL-351 overcurrent relays settings modification process

Table I: Recommended settings of SEL-35I for the industrial and commercial power system in Fig. I

Setting Group Number I 2 3

Grid Mode of Operation Connected Islanded Islanded

Controller Type N/A Voltage Current

Relay Inputs Grid CB DG Controller DG Controller Position & CB Position & CB Position

Inst. 50PIP 5 3 N/A

Over- 51PP I I N/A current Time Settings Settings

51PC U2 U2 N/A

51PTD 3 I N/A

Inst. 50NIP 0.5 0.3 0.3

Earth 50NP 0.1 0.1 0.1 Fault Time

Settings Settings 51NC U2 U2 U2

51NTD 3 I I

Under Voltage 27PIP 250 N/A 250

Settings 27P2P 220 N/A 220

Over Voltage 59PIP 300 300 300 Settings

The proposed adaptive scheme for SEL relay requires specific input configuration, where two opto-isolated inputs (INI0l and IN 102) will be necessary. The first input represents the main grid breaker or static switch status (i. e. OPEN or CLOSE) and the second input represents the mode of operation that controls the DG (i.e. voltage controlIed or current controlled). The reception of these inputs will switch the relay from one group to another one as shown in Fig. 16. A general connection diagram of the relay inputs wiring is illustrated in Fig. 17.

551 Select Setting Group 1

IN101

552 Select Setting Group 2

(!IN 10 l)*(IN 102)

553 Select Setting Group 3 (!lN 101)"'(!lN 102)

554 Select Setting Group 4

o

555 Select Setting Group 5

o

556 Select Setting Group 6

o

FIG. 16: SCREEN SHOT OF AcSELERATOR (SEL RELAY

INTERFACE SOFTWARE) SHOWS HOW TO PROGRAM THE

SETTINGS GROUPS WTTH THE RELA YS INPUTS.

t PCc. Point of Common Couphng Main grid '" OCR' Over-Current Relay

INIOI

PCC � --

Inverter based DG

Voltage controller

contact

DG controller

INI02

Current controller

contact

Fig. 17: lIIustration of SEL-351 inputs to achieve the proposed scheme.

VI. CONCLUSTONS

In this paper, the fault current contributions from inverter­based DGs in a distribution network of an industrial and commercial power system were examined in greater detail. In particular, the impact of inverter-based DGs and their controllers on distribution network protection was thoroughly investigated. Voltage and current controllers for inverter based DGs were analyzed and test results demonstrated that they have a major influence on the distribution network protection. This makes unsuitable recently published fault current detection algorithms based on undervoltage­controlIed overcurrent scheme especially for islanded mode operation of the DGs. Even the IEEE Std. 1547 does not present a comprehensive solution for fault current detection in the presence of inverter-based DGs. Based on the new­found conditions for protection of the distribution network, a

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novel algorithm that considers the impact of inverter-based DG controllers has been proposed. This algorithm even adapts to any changes in microgrid mode of operation as weH as to transition of inverter based DG operation between current control and voltage control modes. Furthermore, it takes into consideration the effects of load power factor, PWM switching frequency and fault timing.

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[2] C.J. Mozina, "Impact of Green Power Distributed Generation," IEEE

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[3] A Abdel-Khalik, A. Eiserougi, A. Massoud, S. Ahmed, "Fault current contribution of medium voltage inverter and doubly-fed induction­machine-based flywheel energy storage system," IEEE Trans. Sustainable Energy, vol. 4, no. I, pp. 58-67, Jan. 2013.

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VII. BIOGRAPHIES

Mohammed Haj-ahmed (S'12) received B.S. and M.Sc. degrees from the University of Jordan, Amman, Jordan in 2006 and 2009, respectively; all in electrical engineering. From 2006 to 2009, he worked at National Electric Power Company (NEPCO), Transmission Company of Jordan, as a power system

protection engineer. He is currently working toward the Ph.D. degree in the Department of Electrical and Computer Engineering at The Ohio State University. His research interests incJude power system protection and stability, microgrids, and multi-agent systems.

Mahesh lIlindala (S'OI, M'06, SM' 11) received B.Tech. in 1995 from National Institute of Technology, Calicut; M.Sc.(Engg.) in 1999 from the Indian Institute of Science, Bangalore; and M.S.E.E. and Ph.D. in 2005 from the University of Wisconsin-Madison; all in Electrical Engineering. From 2005 to 2011, he worked at Caterpillar as a senior engineer and team lead on electric drivetrain systems, variable speed gensets and

uninterruptible power supplies. Since 2011, he has been an Assistant Professor in the Department of Electrical and Computer Engineering at The Ohio State University. His research interests include microgrids, distributed energy resources, electrical energy conversion and storage, power system applications of multiagent systems, protective relaying and advanced electric drive transportation systems.

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