A Current Selective Tripping Protection Scheme for the Distribution Network with PV

Abstract

At present, the global energy demand keeps rising due to population growth. Therefore, large numbers of photovoltaics (PV) are being integrated with power systems. Solar PV’s installed power capacity is poised to surpass that of coal by 2027, becoming the largest in the world. The integration of PV has changed the direction of the power flow. Under these circumstances, the changed magnitudes and directions of fault current may result in maloperations and non-operations of conventional relays. In this work, a simple and reliable current selective tripping protection scheme is proposed, which is based on the direct communication between overcurrent protective devices on both sides of the line. Through logical programming of the operation information of each protection, the fault location is detected, and the instantaneous trip is realized. The simulation analysis of PSCAD/EMTDC shows that the protection scheme can reliably detect and isolate faults happening at the feeder and bus under different fault conditions; besides, it has good performance in detecting certain resistance grounding faults. The proposed protection scheme can effectively solve the problems caused by PV systems penetration and improve system safety.

1. Introduction

In recent years, carbon neutrality, or achieving net-zero greenhouse gas emissions, has become a global aim [1,2]. To achieve this goal, it is essential to transition from fossil fuel-based energy systems to low-carbon and renewable energy sources [2,3,4]. This transition is driven by several factors, including concerns about global warming, the demand to reduce greenhouse gas emissions, energy security considerations, and the increasing cost competitiveness of renewable technologies [5,6]. In this trend, solar photovoltaic (PV) technology has experienced remarkable growth and development over the past decades, becoming one of the fastest-growing renewable energy sources globally. The exponential growth of PV power generation, particularly in the distribution networks (DNs), has led to a significant increase in mixed electricity production [7,8]. Various indications suggest a promising future for PV as a major contributor to the global energy transition.

The integration of PV systems has a profound impact on DNs. Distributed PV reduces transmission losses and relieves stress on the DNs, especially during peak load periods [9]. However, the intermittent nature of PV systems poses challenges for stability and management of the grid. The fluctuating output from PV systems can strain voltage regulation and grid balancing [10]. The integration of PV systems into the DNs has a great influence on the fault characteristics of the system. Distributed PV systems can affect fault currents and fault levels in the DNs. Generally, PV systems exhibit limited fault current due to their relatively small size compared to conventional generation sources [11,12]. PV systems bring great challenges to the coordination and operation of relay protection schemes. With the integration of PV systems, the fault current contribution from PV may vary depending on the solar irradiance and system operation conditions. This fluctuation in fault current levels can affect the coordination between protective relays, which affects the accuracy and reliability of conventional protection schemes. Besides, PV systems have their own protective devices, such as anti-islanding relays, which may interfere with the fault detection process of the main protective relays [13,14]. The integration of PV systems can also introduce additional fault current, such as reverse power flow during periods of high solar generation [15]. As a result, the coordination of protective relays and the discrimination of fault signals become more complex.

In recent years, there has been significant research conducted abroad on relay protection for PV distribution networks. Researchers have focused on various aspects of protection, including fault detection, discrimination, and coordination. One area of study is the development of advanced protection algorithms to enhance the reliability and accuracy of fault detection in the presence of PV systems [16,17]. Another area of research involves the coordination of protective relays to improve selectivity and minimize unnecessary tripping [18,19]. Additionally, studies have explored the impact of high penetration levels of PV systems on protection schemes and proposed new protection methods to address the associated challenges. The research described in [20] focuses on an adaptive protection coordination scheme that does not rely on pre-existing communication infrastructures between the relays. Instead, it relies on defining the penetration level of distributed generation (DG), which can be challenging to determine in real-world scenarios and is a quite complex task in practical applications. In [21], a novel approach connects renewable generation sources (RGSs) to the distribution feeder using four-way switches equipped with overcurrent relays. The feeder is divided into multiple protection zones, allowing for localized fault detection and isolation. However, this method has a limitation in that it is not effective in detecting high-impedance faults. In [22], a protection scheme utilizing communication-enabled directional overcurrent relays (DOCRs) was proposed for radial networks with distributed energy resources (DERs). While the protection scheme that relies on communication can offer significant benefits, its practical implementation in real-world scenarios is challenging and heavily dependent on the availability of a highly reliable communication channel. The existing protection schemes mentioned above have complex principles and are challenging to apply in practical scenarios or have poor resistance to high fault resistance.

This work proposes a simple and reliable current selective tripping protection scheme. Fault location is determined through logical programming of the operation information of each overcurrent protection on the line, and the instantaneous trip is realized. The proposed protection scheme can protect the full length of the protected line and provide certain protection for the bus under various fault conditions, which is more reliable than conventional directional overcurrent protection. Besides, it can resist fault resistance and is not affected by PV output fluctuation.

2. Conventional Protection Schemes of DNs

Most DNs operate in the open-loop operation state, which can be understood as a radial network. Its power direction is only from a single source to the load in one direction, so the protection configuration does not need to consider the directional elements. The operation mode of unidirectional power flow is beneficial to simplify the protection scheme and is widely used in DNs.

Three-step current protection is often used in DNs in China. However, in some applications, the DNs use cables for power supply; the power supply distance is very short, only a few hundred meters to several thousand meters. The cable line impedance is much smaller than the system impedance and, therefore, the amplitude of the short circuit current detected by the protection is very small when the fault occurs in different positions, which may make the conventional instantaneous overcurrent protection fail to coordinate with each other. For the DNs mentioned above, the conventional scheme is to adopt overcurrent protection.

2.1. The Overcurrent Protection

Overcurrent protection refers to a protection device whose operating current is set according to the maximum load current. It should not operate during normal system operation, but it can operate according to the increase of current when the system fails. Under normal circumstances, it not only protects the full length of the line, but also protects the full length of adjacent lines, which plays a role in remote backup protection. In order to ensure that the overcurrent protection absolutely does not operate under normal working conditions, the setting value of the operating current of the protection device must be greater than the maximum load current that may occur on the line. The operating current is as follows:

$$I_{op}=\frac{1}{K_{re}}{I}_{re}=\frac{K_{rel}{K}_{Ms}}{K_{re}}{I}_{L.\max }$$

(1)

where K_rel is the reliability coefficient, generally 1.25~1.5; K_Ms is the self-starting coefficient, which represents the ratio of the maximum current of the motor during self-starting to the maximum load current, and the value is greater than 1, should be determined by the specific network connection and load nature; K_re is the return coefficient of the current relay, which represents the ratio of return current to action current, generally 0.85~0.95; I_L.max is the maximum load current that may occur on the line.

The operating time of each protection device is coordinated with each other to ensure the selectivity of relay protection, and it is shown in Figure 1.

In Figure 1, the current only flows from the source to the load in a single power source system, so it is not necessary to install a direction element. Overcurrent relays (OCRs) and circuit breakers (CBs) are installed at the supply side of the feeder. Overcurrent protection depends on the operation time of each relay to cooperate. Its advantage is simple and reliable, but the disadvantage is that the closer the fault is to the power supply, the longer the operating time.

2.2. Applicability Analysis of a Conventional Protection Scheme

The DNs with large-scale distributed photovoltaic (PV) systems penetration adopt an open-loop operation. If the fault is transient, the system will operate normally without disconnecting the load. When the fault is permanent, the circuit breaker nearest to the fault point is disconnected. Conventionally, the flow of currents in various feeders of the DNs is primarily unidirectional, allowing OCRs to provide adequate protection. However, the integration of distributed PV systems into DNs changes the current flow patterns, subsequently impacting protection coordination. In this case, CBs and protective relays should generally be installed on both sides of the feeder. In addition, considering that the direction of the fault current may change, the protection devices should generally have the function of direction determination. Only when the short circuit power flows from the bus to the protected line does the protective device operate; otherwise, it will not operate. Therefore, the operation of relay protection has a certain directionality.

In order to ensure reliable power supply and selectivity of protection devices, directional overcurrent protection must be adopted. When the overcurrent protection on the bidirectional source network has directionality, it can be considered as the protection of two unidirectional source networks. The operating time difference of directional overcurrent relays (DOCRs) in the same direction is used for coordination. The more lines are segmented, the more stages the operating time needs to match, and the slower the fault clearing time. The operating time of the directional overcurrent protection is shown in Figure 2.

The main characteristic of directional overcurrent protection is the addition of directional discriminators to the existing overcurrent protection. This ensures that the protection does not misoperate when a reverse fault happens. It meets the selectivity and sensitivity requirements of multi-source lines. The advantages of this scheme are simple, cheap, and reliable, but the operating time of the protection is long. When a fault occurs at a feeder line, considering that the short circuit current provided by the PV systems may be quite small, the reliable operation of the protection of the PV side cannot be guaranteed; the CBs on the PV side of the line may not trip. It also cannot provide protection for the bus; therefore, it is necessary to study a protection scheme suitable for DNs with PV systems penetration.

3. The Proposed Current Selective Tripping Protection Scheme

This work introduces a protection scheme suitable for DNs with distributed PV systems penetration, that is, current selective tripping protection based on direct communication between microcomputer protection devices. Through logic programming, the operation information of the overcurrent protective delays on both sides of the line is compared so that the fault section of the line can be identified. This scheme can realize the selective and rapid removal of fault lines.

3.1. Working Principle of the Current Selective Tripping Protection

Current selective tripping protection involves installing overcurrent protection devices equipped with communication capability at both sides of the feeder. The principle is as follows: the current selective tripping protection at one side of the feeder receives the signals from the adjacent protection and the protection on the opposite side of the feeder through the fiber channel. Then, the protection device programs the received signals logically and identifies the fault location. Then, the instantaneous trip is realized and the fault is removed. It should be noted that the protection scheme also requires action information on the protection of adjacent feeders. The adjacent protection device is crucial for receiving and processing the transmitted information to make an informed decision about protection actions. The specific principle of the protection scheme is illustrated in Figure 3.

Figure 3 shows a single-power source system. The inlet and outlet lines of the bus are equipped with current selective tripping protection. At the same time, multiple load outlets are connected to the bus. Next, according to different fault locations, the protection discrimination scheme is discussed.

3.1.1. A short Circuit Fault at the Feeder Line

When a short circuit fault (F1) occurs at point A, the fault current can be detected at both relays R1 and R2, but there is no fault current at relay R3. In this case, the current selective tripping protection at relay R2 receives both the action information of relays R1 and R2 and the no-action information of R3. It can be determined that the fault point is between circuit breakers 2 and 3. Circuit breakers 2 and 3 can be switched off according to the selective tripping logic. For feeder line faults, the action logic of selective tripping protection is shown in Figure 4.

3.1.2. A Short Circuit Fault at the Bus

When a short circuit fault (F2) occurs at point B, the fault current can be detected at relay R3, while there is no fault current at relay R4. The current selective tripping protection devices at relays R3 and R4 receive both the action information of relay R3 and the no-action information of relay R4. It can be determined that the fault point is between circuit breakers 3 and 4. Circuit breakers 3 and 4 can be switched off according to the selective tripping logic. For the fault of the bus or the load branches, the action logic of the selective tripping protection is shown in Figure 5.

3.2. Protection Scheme for DNs with PV Systems Penetration

The DNs with short lines make it difficult for conventional protection schemes to meet the requirements of selectivity and rapidity at the same time; besides, the penetration of a large number of distributed PV systems also makes the direction of the fault current in the DNs more complicated. When a fault happens at a feeder line, the short circuit current coming from the large system side is very large. In contrast, the short circuit current provided by the distributed PV systems is small, no larger than 1.5 times the load current. Therefore, the current setting value of the proposed protection scheme has a large margin to bypass the short circuit current provided by the distributed PV systems. In the following, the current selective tripping protection configuration scheme suitable for DNs with PV systems penetration is discussed for different fault locations in the Figure 6.

3.2.1. A Short Circuit Fault (F1) at the Feeder Line

When the power supply direction is from terminal m to terminal n, a short circuit fault occurs at point A of the feeder line. Relays R1 and R2 can detect the fault current provided by the large system. Only the fault current provided by the PV systems is detected at the relay R3, and the overcurrent protection cannot be activated. The current selective tripping protection at relay R2 receives both the action information of relays R1 and R2 and the no-action information of relay R3. According to the selective tripping logic in Figure 4, it can be determined that the fault occurred between relays R2 and R3. Circuit breakers 2 and 3 can be switched off to isolate the faulty section while preserving the rest of the system.

On the contrary, when the power supply direction is from terminal n to terminal m, a fault occurs at point A. Relays R3 and R4 can detect the fault current provided by the large system. Only the current provided by the PV systems is detected at relay R2, and the overcurrent protection cannot be activated. The current selective tripping protection at relay R3 receives both the action information of relays R3 and R4 and the no-action information of relay R2. Circuit breakers 2 and 3 can be switched off according to the selective tripping logic.

In order to improve the reliability of current tripping protection, the failure protection can be set based on the current selective tripping logic. When the protection refuses to act, expand the tripping range. The selective tripping logic is shown in Figure 7.

3.2.2. A Short Circuit Fault (F2) at the Bus

When the power supply direction is from terminal m to terminal n, a short circuit fault occurs at point B. Relay R3 detects fault current provided by large systems. Relay R4 only detects the fault current provided by the PV systems, and the overcurrent protection cannot be activated. The current selective tripping protections at relays R3 and R4 receive both the action information of relay R3 and the no-action information of relay R4. Therefore, it can be determined that the fault location is in the bus or load branches according to the selective tripping logic in Figure 5. However, due to the many outgoing lines on the bus, it is difficult to determine the exact location of the fault. The protection device delays the action and relies on the fixed-time overcurrent protections of the load branches to achieve selectivity. After a certain delay (such as t0), if the fault current still exists, it is determined that the fault point is on the bus. Current selective tripping protection trips CB 3 and 4 to isolate the faulty bus while preserving the rest of the system. The delay time should be greater than the maximum time limit of overcurrent protection on all load outlet lines of the ring network cabinet.

On the contrary, when the power supply direction is from terminal n to terminal m, a fault occurs at point B. The current selective tripping protections at relays R3 and R4 receive both the no-action information of relay R3 and the action information of relay R4. After a certain delay, current selective tripping protection trips CB 3 and 4 and relies on the fixed-time overcurrent protection of the load branches to achieve selectivity. After a certain delay, if the fault current still exists, it is determined that the fault point is on the bus. The selective tripping logic is shown in Figure 8.

In summary, the current selective tripping protection scheme can protect the line and the bus. It does not require the addition of voltage transformers, and there are no protection blind spots. It can also cover the full length of the line. Besides, the proposed scheme does not need to consider the coordination of the operating time of each relay on the feeder. Its operating time is faster than the directional overcurrent protection scheme.

4. Case Studies

4.1. Modeling of a DN with Distributed PV Systems Penetration

Based on the topology of an actual DN in a province in northwest China, a simulation model of 10 kV distribution network with the distributed PV systems penetration is built on the PSCAD/EMTDC simulation platform. The topology diagram of the 10 kV power supply system is shown in Figure 9. The red numbers indicate the bus serial number, such as Bus 1.

As is shown in Figure 9, the power grid above the 10 kV substation is treated as a voltage source. The example system has buses 25, 28, and 31 integrated with PV systems with a capacity of 1 MW, and the PV systems are connected to the DN through a 10/0.4 kV package transformer. Now, take the area enclosed by the red dotted line in Figure 9 as an example to verify the proposed selective tripping protection scheme. The main parameters are shown in the following Tables (

Table 1. System side parameters.

Mode of Operation	Rated Capacity (MVA)	Rated Voltage (kV)	System Positive Sequence Impedance (Ω)
Maximum operating mode	50	10	0.797
Minimum mode of operation	50	10	2.686

,

Table 2. Transformer parameters.

Voltage Level (kV)	Rated Capacity (MVA)	Percentage of Reactance (%)	Reference Capacity (MVA)	Equivalent Reactance (Per Unit)
10/0.4	1.2	6	1.2	0.06

,

Table 3. 10 kV line parameters.

Starting Point	End Point	Length (m)
Bus 1	Bus 3	450
Bus3	Bus 7	547
Bus 7	Bus 11	847
Bus 11	Bus 25	1788
Bus 11	Bus 18	1147
Bus 18	Bus 26	147
Bus 18	Bus 27	500
Bus 26	Bus 32	2006
Bus 32	Bus 33	760

and

Table 4. Load parameters.

Position	Active Power Calculation Load (kW)	Reactive Power Calculation Load (kVar)
Bus 7	420	0.001
Bus 18	5950	0.001
Bus 26	1190	0.001
Bus 27	3115	0.001
Bus 32	140	0.001
Bus 33	1070	0.001

).

According to the control strategy of the grid-connected PV generation systems, the model of PV system is built. The simulation parameters of PV generation systems are shown in

Table 5. The simulation parameters of the PV generation system.

System Parameter	Numerical Value	PI Parameter	Numerical Value
DC voltage	0.7 kV	kpod/kiod	2.0/100.0
Line voltage (rms)	0.4 kV	kpoq/kioq	0.1/2.0
Rated active/reactive power	1000 kW/0 kVar	kpid(1)/kiid(1)	5.0/0.1
System-side filter inductor	0.2 mH	kpiq(1)/kiiq(1)	10.0/1.0
Inverter filter inductance	0.2 mH	kpid(2)/kiid(2)	8.0/1.0
Filter capacitance	30 μF	kpiq(2)/kiiq(2)	8.0/1.0

.

Where k_pod and k_iod are, respectively, the proportional control coefficients and integral control coefficients of the outer loop of the d-axis; k_poq and k_ioq are, respectively, the proportional control coefficients and integral control coefficients of the outer loop of the q-axis; k_pid(1) and k_iid(1) are, respectively, the proportional control coefficient and integral adjustment coefficient of the inner loop of the positive sequence d-axis current. k_piq(1) and k_iiq(1) are, respectively, the proportional control coefficient and integral adjustment coefficient of the inner loop of the positive sequence q-axis current. k_pid(2) and k_iid(2) are, respectively, the proportional control coefficient and integral adjustment coefficient of the inner loop of the negative sequence d-axis current. k_piq(2) and k_iiq(2) are, respectively, the proportional control coefficient and integral adjustment coefficient of the inner loop of the negative sequence q-axis current.

4.2. The Performance of the Proposed Selective Tripping Protection Scheme

Figure 10 represents the simplified model of the enclosed area in Figure 9. The current on the grid side is recorded as I_g. The current on the PV side is recorded as I_p.

Considering distributed PV penetration, the setting value of the operating current of each protection is shown in

Table 6. Operating current setting values.

Relay Name	Operating Current Setting Value (kA)
1	1.0413
2	1.0028
3	1.0106
4	1.0118

. K_rel = 1.3, K_Ms = 1.15 and K_re = 0.9.

4.2.1. The Performance under the Phase-to-Phase Fault

(1)

A short circuit fault in the line 7–11 (F1 fault)

The distributed PV system is assumed to operate at rated power. It provides reactive support during line faults. The relay operation for the phase-to-phase fault occurring at 15%, 50%, and 95% of line 7–11 through different fault resistance is shown in

Table 7. Relay operation status of line 7–11 under the phase-to-phase fault.

Fault Resistance/Ω	Fault Location/%	Relay Name	Fault Current/kA	Whether the Operating Current Is Reached
1	15	R1	5.782	Y
		R2	5.766	Y
		R3	0.422	N
	50	R1	5.283	Y
		R2	5.266	Y
		R3	0.415	N
	95	R1	4.722	Y
		R2	4.704	Y
		R3	0.403	N
10	15	R1	1.391	Y
		R2	1.370	Y
		R3	0.535	N
	50	R1	1.378	Y
		R2	1.356	Y
		R3	0.534	N
	95	R1	1.361	Y
		R2	1.339	Y
		R3	0.533	N

. “Y” indicates that the actual fault current is greater than the operating current of the relay, and the relay can operate. “N” indicates that the relay cannot operate.

As shown in Table 7, for faults at line 7–11, the fault current detected by relays R1 and R2 comes from the large system and is greater than the operating current of each relay. Relay R3 on the opposite side of the line only detects the fault current provided by the distributed PV systems, and the overcurrent protection cannot be activated. The current selective tripping protection at relay R2 receives both the action information of relays R1 and R2 and the no-action information of relay R3. According to the selective tripping logic in Figure 7, the fault location is in line 7–11. Circuit breakers 2 and 3 can be tripped to isolate the faulty section while preserving the rest of the system.

The protection scheme proposed in this work is compared with the directional overcurrent protection when the above faults occur, and the operation of each relay is shown in

Table 8. The performance of different protection schemes.

Different Protection Schemes	Fault Resistance/Ω	Fault Location/%	Relay Operation Condition
			R2	R3
The proposed selective tripping protection	1	15	True	True
		50	True	True
		95	True	True
	10	15	True	True
		50	True	True
		95	True	True
Directional overcurrent protection	1	15	True	False
		50	True	False
		95	True	False
	10	15	True	False
		50	True	False
		95	True	False

. “True” indicates the correct operation of the relays, and “False” indicates the incorrect operation of the relays.

As is shown in Table 8, the protection scheme presented in this work can operate correctly under various fault conditions. At the same time, according to the relay operation status, the proposed protection scheme can protect the full length of the protected line and has a certain ability to resist the fault resistance. Since the short circuit current provided by the distributed PV systems is small, the relay R3 does not operate in the directional overcurrent protection. Therefore, directional overcurrent protection cannot isolate faulty lines.

(2)

A short circuit fault in the bus 11 (F2 fault)

The relay operation for the phase-to-phase fault occurring at bus 11 through different fault resistance is shown in

Table 9. Relay operation status of bus 11 under the phase-to-phase fault.

Fault Resistance/Ω	Relay Name	Fault Current/kA	Whether the Operating Current Is Reached
1	R2	3.758	Y
	R3	3.758	Y
	R4	0.446	N
10	R2	1.318	Y
	R3	1.318	Y
	R4	0.593	N

.

For a fault in bus 11, known by Table 9, relay R3 detects the fault current provided by the large system. Relay R4 only detects the fault current provided by the distributed PV systems and the overcurrent protection cannot be activated. Based on the operation information of relay R3 and the non-operation information of relay R4, it can be determined that the fault occurs at bus 11 or its load branches. After a certain delay, if the fault current is still detected, the fault is in bus 11. Therefore, the circuit breakers of all incoming and outgoing lines on the bus can be tripped.

The protection scheme proposed in this work is compared with the directional overcurrent protection when the above faults occur, and the operation of each relay is shown in

Table 10. The performance of different protection schemes.

Different Protection Schemes	Fault Resistance/Ω	Relay Operation Condition
		R3	R4
The proposed selective tripping protection	1	True	True
	10	True	True
Directional overcurrent protection	1	False	False
	10	False	False

.

As is shown in Table 10, for the faults in the bus, the protection scheme proposed in this work can accurately determine the fault location, and the relays can operate correctly. However, relay R3 detects that power flows from the line to the bus, so it does not trip. Relay R4 detects the fault current, which is smaller than its operating current setting value, and it does not trip. Therefore, the conventional directional overcurrent protection cannot protect the bus.

4.2.2. The Performance under the Single-Phase Ground Fault

(1)

A short circuit fault in the line 7–11 (F1 fault)

The distributed PV system is assumed to operate at rated power. It provides reactive support during line faults. A single-phase ground fault occurs at 15%, 50%, and 95% of line 7–11 through different fault resistance. The protection scheme proposed in this work is compared with the directional overcurrent protection when the above faults occur, and the operation of each relay is shown in

Table 11. The performance of different protection schemes.

Different Protection Schemes	Fault Resistance/Ω	Fault Location/%	Relay Operation Condition
			R2	R3
The proposed selective tripping protection	1	15	True	True
		50	True	True
		95	True	True
	10	15	True	True
		50	True	True
		95	True	True
Directional overcurrent protection	1	15	True	False
		50	True	False
		95	True	False
	10	15	True	False
		50	True	False
		95	True	False

.

(2)

A short circuit fault in the bus 11 (F2 fault)

A single-phase ground fault occurs in bus 11 through different fault resistance. The protection scheme proposed in this work is compared with the directional overcurrent protection when the above faults occur, and the operation of each relay is shown in

Table 12. The performance of different protection schemes.

Different Protection Schemes	Fault Resistance/Ω	Relay Operation Condition
		R3	R4
The proposed selective tripping protection	1	True	True
	10	True	True
Directional overcurrent protection	1	False	False
	10	False	False

.

It can be seen from Table 11 and Table 12 that the proposed protection can operate correctly under single-phase ground faults and has certain resistance to fault resistance. The directional overcurrent protection cannot isolate faulty lines.

4.2.3. The Performance under the Three-Phase Ground Fault

(1)

A short circuit fault in the line 7–11 (F1 fault)

A three-phase ground fault occurs at 15%, 50%, and 95% of line 7–11 through different fault resistance. The protection scheme proposed in this work is compared with the directional overcurrent protection when the above faults occur, and the operation of each relay is shown in

Table 13. The performance of different protection schemes.

Different Protection Schemes	Fault Resistance/Ω	Fault Location/%	Relay Operation Condition
			R2	R3
The proposed selective tripping protection	1	15	True	True
		50	True	True
		95	True	True
	10	15	True	True
		50	True	True
		95	True	True
Directional overcurrent protection	1	15	True	False
		50	True	False
		95	True	False
	10	15	True	False
		50	True	False
		95	True	False

.

(2)

A short circuit fault in the bus 11 (F2 fault)

A three-phase ground fault occurs in bus 11 through different fault resistance. The protection scheme proposed in this work is compared with the directional overcurrent protection when the above faults occur, and the operation of each relay is shown in

Table 14. The performance of different protection schemes.

Different Protection Schemes	Fault Resistance/Ω	Relay Operation Condition
		R3	R4
The proposed selective tripping protection	1	True	True
	10	True	True
Directional overcurrent protection	1	False	False
	10	False	False

.

It can be seen from Table 13 and Table 14 that the proposed protection can operate correctly under three-phase ground faults and has certain resistance to fault resistance. The directional overcurrent protection cannot isolate faulty lines.

4.3. Effect of Distributed PV Output Timing on Protection

There is great volatility in the PV system output. The output of the day and night is very different, and even the PV systems will exit operation. The weak feed characteristics of distributed PV systems under various output conditions are different. The operation mode of the distributed PV systems from exit operation to maximum output (rated power state) and the fault current flowing through each relay are also different. Distributed PV system output is set to 0 MW and 0.5 MW. When asymmetric faults occur at different positions of the 1 Ω fault resistance in line 7–11, the operation of the proposed protection scheme is shown in

Table 15. Relay operation under different PV output conditions.

Photovoltaic Output/MW	Fault Type	Fault Location/%	Relay Name	Fault Current/kA	Whether the Operating Current Is Reached	Fault Determination
0	AB	15	R1	5.818	Y	a fault in line 7–11
			R2	5.802	Y
			R3	0.479	N
			R4	0.489	N
		50	R1	5.318	Y	a fault in line 7–11
			R2	5.301	Y
			R3	0.469	N
			R4	0.481	N
		95	R1	4.767	Y	a fault in line 7–11
			R2	4.749	Y
			R3	0.455	N
			R4	0.470	N
	ABG	15	R1	3.739	Y	a fault in line 7–11
			R2	3.724	Y
			R3	0.394	N
			R4	0.394	N
		50	R1	3.461	Y	a fault in line 7–11
			R2	3.445	Y
			R3	0.369	N
			R4	0.369	N
		95	R1	3.207	Y	a fault in line 7–11
			R2	3.190	Y
			R3	0.343	N
			R4	0.342	N
	AG	15	R1	4.061	Y	a fault in line 7–11
			R2	4.045	Y
			R3	0.374	N
			R4	0.374	N
		50	R1	3.621	Y	a fault in line 7–11
			R2	3.606	Y
			R3	0.317	N
			R4	0.331	N
		95	R1	3.163	Y	a fault in line 7–11
			R2	3.148	Y
			R3	0.282	N
			R4	0.289	N
0.5	AB	15	R1	5.792	Y	a fault in line 7–11
			R2	5.776	Y
			R3	0.455	N
			R4	0.489	N
		50	R1	5.292	Y	a fault in line 7–11
			R2	5.275	Y
			R3	0.447	N
			R4	0.482	N
		95	R1	4.741	Y	a fault in line 7–11
			R2	4.723	Y
			R3	0.436	N
			R4	0.471	N
	ABG	15	R1	3.713	Y	a fault in line 7–11
			R2	3.698	Y
			R3	0.362	N
			R4	0.395	N
		50	R1	3.435	Y	a fault in line 7–11
			R2	3.419	Y
			R3	0.337	N
			R4	0.369	N
		95	R1	3.182	Y	a fault in line 7–11
			R2	3.165	Y
			R3	0.312	N
			R4	0.343	N
	AG	15	R1	4.040	Y	a fault in line 7–11
			R2	4.024	Y
			R3	0.345	N
			R4	0.375	N
		50	R1	3.609	Y	a fault in line 7–11
			R2	3.594	Y
			R3	0.302	N
			R4	0.332	N
		95	R1	3.144	Y	a fault in line 7–11
			R2	3.130	Y
			R3	0.256	N
			R4	0.290	N

. “Y” indicates that the actual fault current is greater than the operating current of the relay, and the relay can operate. “N” indicates that the relay cannot operate. “AB” represents the phase-to-phase fault. “ABG” represents the phase-to-phase ground fault. “AG” represents the single-phase ground fault.

As shown in Table 13, the fault current detected by relays R1 and R2 comes from the large system, and relay R3 only detects the fault current provided by the distributed PV systems, which is smaller than its operating current setting value. According to the selective tripping logic, the fault location is in line 7–11. With the change of PV output power, the proposed protection scheme can correctly determine the fault location when different types of faults occur at different locations on the line. In such fault conditions, the proposed protection scheme can operate reliably. In summary, the timing change of distributed PV systems does not affect the operation of the protection scheme proposed in this work, and the protection proposed is not affected by the weak feed characteristics of PV sites.

5. Conclusions

The integration of distributed PV systems has changed the original topology of DNs. Under these circumstances, the magnitude and direction of the fault current will change correspondingly, which has negative impacts on conventional relay protection. This work analyzes the influence of distributed PV integration on conventional directional overcurrent protection. To solve this problem in a DN with high penetration of PV, a simple and reliable current selective tripping protection scheme is proposed. Through logical programming of the operation information of each overcurrent protection on the line, the fault location is determined, and the instantaneous trip is realized, which is effective in detecting fault in a DN with high penetration of PV.

The proposed current selective tripping protection scheme has been verified on an actual DN in China. The simulation results under various fault locations, different fault types and various fault resistance shows the effectiveness of the proposed scheme. The proposed protection scheme can not only protect the full length of the protected line, but also provide certain protection for the bus, which is much better than the directional overcurrent protection scheme. Besides, it has a good performance to resist the fault resistance and is not affected by the PV output fluctuation. As there is no requirement to consider the coordination of relay operating time, the fault removal time of the proposed protection scheme is shorter than the directional overcurrent protection in principle. In the future, the applicability of the proposed protection scheme under higher penetration of PV systems will continue to be studied.