Impact of Distributed Generation Integration on Protection Devices: A Case Study in the CIGRE European Medium Voltage Network ^†

Abstract

This study examines the impact of Inverter-Based Distributed Generators (IIDGs) on short-circuit currents detected by the main relay at the head of a radial feeder. It highlights how changes in fault currents induced by these inverter technologies can significantly affect the effectiveness and reliability of network protection systems. Key variables, such as the level of IIDGs penetration and the relative location of faults with respect to the relay, have been identified as influential factors. The significance of these findings lies in their contribution to a deeper understanding of how inverter fault responses and the integration of IIDGs alter fault currents. To mitigate the adverse effects associated with the insertion of IIDGs, a fault-detection and tripping strategy based on the inverse-time overcurrent curve is proposed. The suggested strategies not only improve fault detection accuracy but also ensure an appropriate response to variations in network conditions.

1. Introduction

The increase in the penetration of IIDG in conventional distribution networks responds to the growing energy demand by leveraging their technical and economic benefits. IIDGs significantly contribute to improving energy quality, reliability, and the production of low-cost, carbon-free energy [1]. However, the inclusion of these generating units can alter the sensitivity of protection devices, especially overcurrent relays in feeders, which may suffer from partial to total blindness during faults [2].

To understand how distributed generators (DGs) modify fault characteristics and thereby develop or improve protection schemes, it is crucial to characterize and understand the response of DGs to such faults. This response varies depending on the type of DG and whether they are synchronous generators or inverter-based units. While the fault response of synchronous DGs has been widely studied, with uncontrolled fault currents that can reach between 5 and 10 times the generator’s nominal current [3], inverter-based generators, being relatively new technologies, present a contribution to the fault current that is still under study and depends on the inverter control method. These IIDGs, during a fault, contribute a maximum of between 1.2 and 2 times the inverter’s nominal current to prevent damage to electronic components, with the duration of this current injection varying depending on the severity of the voltage drop at the point of common coupling (PCC) [4].

In this context, a DG unit, regardless of its type, will contribute to the fault current and, no matter how insignificant this contribution may be, it will cause changes in the short-circuit current in other parts of the network, thus altering traditional short-circuit patterns [4]. The main negative effects impacting protections include reverse power flow, sympathetic tripping, and protection blindness, among others. Specifically, this article focuses on protection blindness, a phenomenon in which the fault current perceived by the main relay is reduced due to the connection of the IIDG, thus causing a delay in the operation of the protection or, in more severe cases, completely disabling the relay’s ability to detect faults. The extent of this current reduction is influenced by certain factors, such as the location of the DG, its size, and the relative location of the fault. These factors are analyzed both analytically and through simulations by the authors of [5,6].

The literature has proposed solutions to mitigate the negative effects on protections, including protection blindness by immediately disconnecting DGs during a fault, modifying the protection system through the installation of new switches, changing distance relays, and using directional overcurrent or differential relays. Proposals also include limiting the capacity of the DG, installing fault-current limiters (FCLs), and adaptive protection schemes, among others. While these measures are partially effective, they present certain limitations. Disconnecting DGs can cause severe voltage drops and stability issues if the disconnection is massive. Also, disconnecting DGs during temporary faults is not economically beneficial [7]. Modifying the protection scheme increases costs and complicates coordination among devices. Limiting the capacity of IIDGs clearly does not represent a viable solution, as it contradicts incentive policies for transitioning to a more sustainable energy matrix and underutilizes an economical resource that should be increasingly exploited [8]. On the other hand, implementing FCLs to preserve the original relay settings requires a detailed analysis of the optimal impedance and the appropriate location of the FCLs. However, a major drawback is their high additional cost, which is undesirable for both utility companies and DG owners. These challenges highlight the advantages of another alternative, such as adaptive adjustments in overcurrent protection. The adaptive protection of the overcurrent relay has been extensively researched for its ability to adjust to variations induced by DGs, thus effectively addressing the adverse effects of their inclusion in protection systems, such as protection blindness and loss of coordination among different protection devices. This adaptability allows for managing fluctuations in fault currents without the need to replace existing protection systems, an option that would be economically unfeasible [9]. Based on a review of the existing literature, this document proposes a strategy to mitigate the blindness of relays in the face of the increasing penetration of IIDGs. This article contributes the following proposals:

• An adaptive adjustment of the pickup current in overcurrent relays is proposed in response to changes associated with the connection and disconnection of IIDGs. This adjustment, by increasing the current pickup multiplier above one, ensures that the relay maintains its sensitivity and is capable of detecting even the smallest faults in the system, thus mitigating delays in response time and protection blindness.
• A protection scheme specifically designed to combat protection blindness induced by the integration of IIDGs is introduced. This approach is based on modifying the current pickup multiplier used to calculate the tripping time of the protection. By adjusting this single variable, the variability of the penetration of IIDGs into the network, as well as their location and proximity to faults, is taken into account. This modification significantly improves the applicability of the scheme in digital overcurrent relays in emerging systems.

2. Fundamentals of the Inverse-Time Overcurrent Relay

The inverse-time overcurrent relay (OCR) serves as the primary protection in radial distribution feeders. It operates based on the principle that the relay’s operation time is inversely proportional to the magnitude of the fault current flowing through it. Various families of inverse-time curves have been defined by international standards; their analytical expression and corresponding coefficients for the IEC 60255 and ANSI/IEEE standards are shown in Equation (1) and reference [10], [11] and [12], respectively. Here, $t_{op}$ is the operation time of the relay, and TDS represents the time dial setting. $I_{sc}$ is the fault current measured by the relay, while $I_{pickup}$ is the relay’s setting for fault detection. The constants $A$, $B$, and $\rho$ are specified by international standards for each type of inverse-time curve.

$$t_{op}=\left[{\displaystyle \frac{A}{{\left(\frac{I_{sc}}{I_{pickup}}\right)}^{\rho }-1}}+B\right]\times TDS$$

(1)

Inverse-time overcurrent relays (TOC) are configured with principal settings: (1) $I_{pickup}$, which defines the minimum fault current necessary to activate the relay, and (2) the TDS, which, along with the type of curve, establishes the relay’s response time to a fault based on coordination with other protection devices. In traditional relays, TDS values can range from 0.5 to 10. The $I_{pickup}$ setting is determined based on the maximum fault current and load current, thus ensuring that the protection’s selectivity is maintained under any operational condition. Minimum fault current values are used solely to verify that the relay can detect the smallest fault within the protected zone. Equation (2) mathematically describes $I_{pickup}$, where $I_{load}$ represents the maximum load current and k is a constant that prevents the relay from activating under normal conditions, such as temporary overloads, power transfers, and errors in current transformers (CTs). The value of k ranges between 1.5 and 2.

$$I_{pickup}=k\times I_{load}$$

(2)

The TOC serves as primary protection for its line section and as backup protection for the adjacent section, as illustrated in Figure 1. This implies that the relay’s reach must extend from the minimum fault current at the remote end of the adjacent section to the maximum current at the point of installation of the head relay. However, establishing this range presents challenges because the $I_{pickup}$, calculated as a multiple of the load current, introduces uncertainty into the precise definition of the relay’s reach, especially in modern networks where the renewable resource is variable.

To mitigate the uncertainty in the relay’s reach, the OC is analyzed using the pickup current multiplier ($M$). This approach ensures that the relay adequately responds to both significant and subtler faults, providing comprehensive and effective network protection. From Equation (1), the operation time of the relay can also be expressed in terms of $M$, which is the ratio between $I_{sc }$ and $I_{pickup}$, as specified in Equation (3).

$$t_{op}=\left[{\displaystyle \frac{A}{{\left(M\right)}^{\rho }-1}}+B\right]\times TDS$$

(3)

In analyzing the multiplier $M$, it is considered that a fault is detected when Equation (2) is satisfied, thus defining the threshold that activates the relay, $M_{threshold}$, as shown in Equation (4). It is established that a fault condition exists when the threshold exceeds 1, while the system is considered to be operating normally if the threshold is less than 1. This allows for the graphical representation of the relay’s curve as a function of time and M. Furthermore, a lower limit of 1.5 is set in Equation (4) based on the observation that, as illustrated in Figure 2, operation times for an M between 1 and 1.5 are excessively prolonged and, therefore, ineffective for protection purposes. Consequently, a fault is declared when $M$ is greater than or equal to the threshold $M_{threshold}$ = 1.5 [13].

$$M_{threshold}={\displaystyle \frac{I_{sc}}{I_{pickup}}}={\displaystyle \frac{\left(I_{sc} |{ I}_{sc}=k\times I_{load}\right)}{k\times I_{load}}}=1$$

(4)

3. Modeling

To assess the impact of IIDG on the protection at the feeder head, the well-documented CIGRE European MV distribution network was selected. This is a three-phase, symmetrical, and balanced network, whose single-line diagram is shown in Figure 3. The network includes main three-phase feeders with a radial configuration. This model was chosen for its adaptability and relevance to studies related to the integration of IIDGs [14]. In this analysis, IIDGs were incorporated at buses 5, 9, and 7 of the system, with capacities of 0.7, 0.5, and 1.5 MW, respectively, allowing for different levels of IIDG penetration at 16%, 33%, 44%, 50%, and 60% with the different combinations of the IIDGs.

The IIDG was modeled using a three-phase, two-level Voltage Source Converter (VSC) with an LC output filter, which includes a fault response model with injection of negative and positive sequence currents for unbalanced and balanced faults, respectively. The interconnection of the IIDG and the AC network is made through a delta-star step-up transformer, supplying the system with powers of 0.7, 0.5, and 1.5 MW. The IIDG model implemented in MATLAB–Simulink (https://www.mathworks.com/products/matlab.html, accessed on 6 September 2024) is illustrated in Figure 4, and details of its modeling are discussed by the authors in references [5,6].

4. Effects of Inclusion of IIDGs on the Overcurrent Relay

To evaluate the impact of various topological changes, such as the connections and disconnections of distributed generators, on the fault current perceived by the head relay, a sensitivity study was conducted on the CIGRE medium-voltage network with IIDG integration. This study considered three scenarios: pre-fault conditions for each level of IIDG penetration, fault conditions without IIDGs, and fault conditions with various levels of IIDG penetration. The results of this analysis provided the foundation for making adaptive adjustments to the head relay, which is essential for maintaining the effectiveness of the protection system amidst changes in network topology due to the integration of renewable generation sources.

4.1. Pre-Fault Condition

In this initial pre-fault scenario, a reduction in the RMS current magnitudes detected by the head relay is observed as the penetration of IIDGs increases. This trend is evident in

Table 1. Pre-fault current magnitudes for different levels of penetration.

Phases	Penetration Level
	0%	16%	33%	44%	50%	60%
Ia [A]	132.865	114.472	94.9389	82.6763	78.7549	66.5616

, where the highest current is recorded without the connection of IIDGs and the lowest is recorded with 60% penetration. Although this pattern is consistent across all three phases, for illustrative purposes, the variation of phase A is graphically presented in Figure 5.

Given the fluctuation of currents due to the connection or disconnection of IIDGs, it is crucial to adaptively adjust the $I_{pickup}$ based on the current state of the network instead of using a fixed threshold, as is customary in networks without IIDGs. As illustrated in Table 1, if the $I_{pickup}$ is set at twice the pre-fault current—resulting in 265.73 A—a $M_{threshold }$ of 1.5 is obtained. However, maintaining a constant $I_{pickup}$ results in significant deficiencies when faced with variations in IIDG penetration; for example, at a penetration level of 16%, the calculation of $M_{threshold }$ is (1.5 × 2 × 114.472)/(2 × 132.865) ≈ 1.29, which is clearly below the value of 1.5. Similarly, $M_{threshold }$ values for penetration levels of 33%, 44%, 50%, and 60% are 1.07, 0.93, 0.89, and 0.75, respectively. This indicates that a fixed $I_{pickup}$ value for different network states causes relay underreach or blindness, which worsens with increased DG penetration, as shown in Figure 6, where the $M_{threshold }$ for all levels of penetration falls below 1.5.

An effective solution to this challenge involves adapting the $I_{pickup}$ based on the load current corresponding to the current state of the system (connection or disconnection of IIDGs). This ensures that the $M_{threshold }$ consistently remains at 1.5, allowing the protection system to adequately respond to the smallest fault in all topological states of the network. In this way, the overcurrent curve will always operate with an $M_{threshold }$ of 1.5, regardless of the connections or disconnections of the IIDGs. This adaptive adjustment resolves the issue of underreach or blindness of protections, a common consequence of the inclusion of IIDGs, and enhances the reliability and effectiveness of the protection system in the evolving network.

4.2. Fault Current Behaivior Without IIDGs

For this analysis, simulations of various short-circuit fault conditions (1φ, 2φ-g, and 3φ) were conducted along feeder T2. The fault currents recorded by the head relay at each fault location are detailed in

Table 2. Fault currents observed by the header relay [A]—0% DG.

Location			B1	B2	B3	B4	B5	B6	B8	B9	B10	B11	B7
Branch T2-A			X	X	X	X	X	X
Branch T2-B			X	X	X				X	X	X	X
Branch T2-C			X	X	X				X				X
Types of Faults	1φ	B	630.999	572.573	493.159	484.914	477.735	459.736	475.29	471.225	462.066	458.373	456.564
	2φ-g	B	5258.74	2568.59	1406.18	1322.36	1253.91	1098.66	1239.13	1203.97	1127.15	1097.25	1075.72
		C	4456.26	2067.22	1128.54	1064.93	1013.38	897.682	1001.65	975.229	917.937	895.774	880.627
	3φ	A	5635	2677.5	1439.27	1352.58	1282.11	1123.43	1266.55	1230.43	1151.91	1121.47	1100.04

for branches T2-A, T2-B, and T2-C. The results indicate that the fault current decreases as the fault location moves away from the feeder head, a trend consistently observed across all phases affected by the different types of simulated faults. To illustrate this behavior, Figure 7 shows the three-phase currents detected by the head relay for a three-phase fault with a fault resistance of 0.01 Ω at different points along branch T2-C. This phenomenon is attributed to the increased distance between the substation and the fault point, which increases the total impedance of the circuit and, consequently, reduces the magnitude of the fault current.

4.3. Fault Current Behavior with IIDGs

This study examines the influence of the fault location on the current detected by the head relay while maintaining a constant level of IIDG penetration. Branches T2-A, T2-B, and T2-C of the feeder were analyzed, as shown in Figure 3. For each branch, the amplitudes of the fault currents observed by the head relay were measured, revealing that the magnitude of the fault current decreases as the fault point moves away from the feeder head. This phenomenon was consistently manifested across all branches, levels of DG penetration, and types of faults, which is similar to observations in systems without DGs. The current results for branch T2-C, with a 50% DG penetration, and the decreasing trend for three-phase faults are shown in Figure 8, while

Table 3. Fault currents observed by the header relay [A]—50% DG.

Location			B1	B2	B3	B4	B5	B6	B8	B9	B10	B11	B7
Branch T2-A			X	X	X	X	X	X
Branch T2-B			X	X	X				X	X	X	X
Branch T2-C			X	X	X				X				X
Types of Faults	1φ	B	571.457	521.264	460.37	451.874	444.521	423.41	444.201	439.455	428.853	424.559	428.05
	2φ-g	B	4849.18	2473.65	1381.74	1298.96	1231.32	1074.83	1219.27	1183.69	1105.8	1075.53	1059.65
		C	4047.37	1967.81	1096.48	1036.28	987.186	875.458	975.944	950.821	895.669	874.151	859.481
	3φ	A	5157.78	2561.66	1403.93	1318.43	1248.29	1087.3	1235.91	1199.19	1119.55	1088.43	1073.1

presents the current results for feeder T2-C with a 50% IIDG penetration. Additionally, it was noted that short-circuit currents are lower in scenarios with DGs compared to those without DGs. The minimum current detected by relay R1 occurred with the maximum DG penetration, while the maximum fault current was recorded in the absence of DGs, especially near the substation during a three-phase fault.

Considering the calculation of the $I_{pickup}$ multipliers, using Equation (4) and considering the adaptive $I_{pickup}$ depending on each level of DG penetration as detailed in study 1 of this section, results were obtained as shown in

Table 4. $I_{pickup}$ Multiplier—50% DG.

Location			B1	B2	B3	B4	B5	B6	B8	B9	B10	B11	B7
Branch T2-A			X	X	X	X	X	X
Branch T2-B			X	X	X				X	X	X	X
Branch T2-C			X	X	X				X				X
Types of Faults	1φ	B	5.44	4.96	4.38	4.30	4.23	4.03	4.23	4.19	4.08	4.04	4.08
	2φ-g	B	46.18	23.56	13.16	12.37	11.73	10.24	11.61	11.27	10.53	10.24	10.09
		C	38.54	18.74	10.44	9.87	9.40	8.34	9.29	9.05	8.53	8.32	8.19
	3φ	A	49.12	24.40	13.37	12.56	11.89	10.35	11.77	11.42	10.66	10.37	10.22

for simulated faults in feeder T2-C at the 50% level of renewable generator penetration. From the results obtained, it can be concluded that regardless of the level of IIDG penetration in the network, the fault current will tend to decrease as it moves away from the feeder head, thereby maintaining the concept of the inverse-time overcurrent curve, as faults further from the substation will have a longer operation time of the relay-associated breaker, while for faults closer to the feeder head, this time decreases. On the other hand, as reflected in

Table 5. $M_{max}$ calculated for each level of DG penetration.

	0% IIDG	16% IIDG	33% IIDG	44% IIDG	50% IIDG	60% IIDG
I pre-fault [A]	132.87	114.47	94.94	82.68	78.75	66.56
I pickup [A]	265.73	228.94	189.88	165.35	157.51	133.12
I fault max [A]	5635.00	5461.90	5309.78	5204.11	5157.78	5030.21
${\mathit{M}}_{\mathit{m}\mathit{a}\mathit{x}}$ [pu]	31.81	35.79	41.95	47.21	49.12	56.7

, the data indicate that the fault current perceived by the head relay significantly decreases as the level of IIDG penetration increases, reaching the lowest value with 60% penetration. This suggests that a higher level of IIDG penetration leads to reduced fault currents, thus extending the operation time on the overcurrent curve and allowing the network to tolerate these currents for an extended period. In contrast, 0% IIDG penetration results in the maximum fault currents, which require a quicker relay response to ensure adequate network protection, as shown in Figure 9.

In this context, the multiplier M, detailed in Table 5, should tend to be lower for higher levels of IIDG penetration, while higher values of M are expected in scenarios without IIDG inclusion. Contrary to expectations, the simulation results show that M is lower when the fault current is at its maximum, implying a delay in the circuit breaker’s operation in the presence of high and severe currents, which should be interrupted almost instantaneously to protect the network. Additionally, M increases as the level of IIDG penetration increases, resulting in faster activation for lower currents. This behavior is contrary to what is desirable according to the logic of a typical overcurrent curve, where faults with high currents are expected to trigger faster actions, while faults with lower currents allow for a longer time interval before the breaker intervenes, as seen in Table 5 and Figure 10.

Therefore, it is evident that merely adjusting the pickup current for each system state—including the various states of connection or disconnection of the IIDGs—while effectively resolving the issues of protection blindness and delay in tripping also introduces a complication, as the M calculated for a level of penetration is greater than for a system without IIDGs, which contradicts the conventional overcurrent protection theory. To address this discrepancy, the M used for fault detection is adjusted. The mathematical expression for this adjustment is based on the premise that the maximum multiplier ($M_{max}$) is established from a simulated three-phase fault at the relay location for the scenario without connected DGs, as shown in Equation (5).

$$M_{max}={\displaystyle \frac{1.5\times I_{fault\_3\phi }^{0\% IIDG\_B1}}{2\times I_{prefault}^{0\% IIDG}}}$$

(5)

From $M_{max}$, it is inferred that the M calculated for variations in IIDG penetration will be lower than this value. Thus, with the increase in IIDG penetration, any fault along the feeder will result in a lower current magnitude compared to $M_{max}$. Consequently, all of the trip multipliers ($M_{trip}$) are calculated based on the maximum pickup current, as per Equation (6).

$$M_{trip}={\displaystyle \frac{I_{fault}}{I_{fault\_3\phi }^{0\% IIDG\_B1}}}{\times M}_{max}+M_{pickup}$$

(6)

Table 6. $M_{trip}$—fault at B1 and B7—Equation (5).

IIDG	Fault B1				Fault B7
	1φ	2φ-g		3φ	1φ	2φ-g		3φ
	b	b	c	a	b	b	c	a
0%	3.56	29.68	25.15	15.11	2.58	6.07	4.97	6.21
16%	4.01	33.48	28.22	17.28	2.90	6.99	5.72	7.12
33%	4.66	39.34	33.00	20.54	3.47	8.44	6.85	8.58
44%	5.23	44.33	37.05	23.34	3.93	9.65	7.82	9.78
50%	5.44	46.18	38.54	24.40	4.08	10.09	8.19	10.22
60%	6.29	53.37	44.35	28.48	4.75	11.87	9.61	11.99

and

Table 7. $M_{trip}$—fault at B1 and B7—Equation (6).

IIDG	Fault B1				Fault B7
	1φ	2φ-g		3φ	1φ	2φ-g		3φ
	b	b	c	a	b	b	c	a
0%	5.06	31.18	26.65	33.31	4.08	7.57	6.47	7.71
16%	4.95	30.35	25.82	32.33	4.00	7.52	6.43	7.64
33%	4.83	29.61	25.08	31.47	3.98	7.53	6.39	7.63
44%	4.76	29.08	24.56	30.88	3.94	7.50	6.37	7.59
50%	4.73	28.87	24.35	30.61	3.92	7.48	6.35	7.56
60%	4.65	28.23	23.72	29.89	3.88	7.45	6.32	7.51

present the results of the $M_{trip}$ calculations obtained from Equations (5) and (6), respectively. These calculations were performed for two fault locations on the T2-C branch: the fault at B1, which is closest to the substation, and the fault at B7, which is the furthest away. The purpose of these calculations is to verify the proper functionality of the proposed current multiplier, thus ensuring that the calculated values exceed 1.5. This guarantees that regardless of the type and location of the fault, the relay is sufficiently sensitive to detect faults under variations in the DGs.

As observed in Table 6, the multipliers calculated from Equation (5), which only considers the adjustment of the adaptive pickup current without the proposed modification, were found to be greater than 1.5. However, an erroneous trend is identified in these values, as the multiplier increases in a way that is directly proportional to the increase in the DG penetration level. This is conceptually incorrect, as a higher multiplier value implies a reduced operation time theoretically for higher currents. However, as demonstrated throughout this article, the higher the level of DG penetration, the lower the current perceived by the relay, suggesting that the multiplier should decrease as the level of penetration increases, a trend not observed in Table 6.

On the other hand, incorporating the proposed variation in Equation (6), $M_{trip}$ is determined for faults at bars B2 and B7 for different levels of penetration, as indicated in Table 7. The results clearly show that the pickup multiplier decreases as the level of penetration increases, corroborating the premise that faults occurring under an increasing level of penetration produce lower fault currents and, therefore, require a longer operation time. Analyzing the two fault locations—the one closest to the substation at bar B2 and the farthest at B7—it is observed that the $M_{trip}$ calculated are lower for the fault farther from the head, while they increase for the fault closer to the substation. This confirms that the adjustment of the multiplier adequately considers the dynamic variation in the magnitude of the feeder current, which is influenced by various factors, such as different levels of IIDG penetration and the location of the fault.

5. Discussion and Conclusions

This study explores the impact of integrating IIDGs on the short-circuit currents detected by the main relay at the head of a radial feeder. An adaptive fault detection and tripping strategy based on the inverse-time overcurrent curve is proposed, which not only improves the accuracy of fault detection but also ensures an appropriate response to the connection and disconnection variations of the IIDGs.

The results indicate that regardless of the level of IIDG penetration, the fault current decreases as it moves away from the feeder head, maintaining the principle of the overcurrent curve, which stipulates longer operation times for distant faults and reduced times for closer faults. Additionally, it was observed that as the level of IIDG penetration increases, the fault current perceived by the relay significantly decreases, which was reflected in lower values of the pickup current multiplier when the fault current was at its maximum, causing a delay in the operation of the protection system. Conversely, an increase in IIDG penetration resulted in faster activation for lower currents.

In response to this behavior, the calculation of the pickup current multiplier was adjusted to ensure that regardless of the network state, the adjusted overcurrent curve maintains a threshold of 1.5, thus facilitating effective fault detection. Once a fault is detected, the $M_{trip}$ parameter is calculated to determine the operating time of the breaker associated with the relay. This ensures that the protection system acts correctly, thus providing a rapid response in the presence of high currents and allowing for a longer interval before breaker intervention for lower currents.