A novel methodology in optimal setting of directional fault current limiter and protection of the MG

Electrical Power and Energy Systems 116 (2020) 105564

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A novel methodology in optimal setting of directional fault current limiter and protection of the MG Mehdi Farzinfara,b, Mostafa Jazaeria, a b

T

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Electrical and Computer Engineering Faculty, Semnan University, P.O. Box 35131-19111, Semnan, Iran School of Engineering, Damghan University, Damghan, Iran

A R T I C LE I N FO

A B S T R A C T

Keywords: MicroGrid Relay coordination Directional Fault Current Limiter (DFCL) Reliability

Integration of the Distributed Generators (DGs) in the MicroGrid (MG) provides an additional contribution to the fault current causing change of the short circuit current which could lead to the miscoordination problem (in the forms of maloperation and delayed operation) in the existing Over Current Relay (OCR) based protection system. Moreover, contribution of the MG can cause the overall fault current to exceed the designed capability level of distribution components, like Circuit Breakers (CBs). In this case, CBs are subjected to increased stresses and are thus more prone to failure to operate when desired. As a result of the above issues (miscoordination and CB failure) the system reliability degrades. Utilizing a Directional Fault Current Limiter (DFCL) between the MG and upstream network is an effective way to mitigate the above-mentioned issues. Nonetheless, setting of the DFCL parameters is a challenging task and should be done with the aim of restoring coordination among OCRs and also enhancing system reliability. In this paper, a novel methodology for optimal setting of DFCL parameters (R and X) is proposed therein the effect of DFCL on OCRs coordination and system reliability is considered simultaneously. For this purpose, a new objective function in terms of DFCL installation and reliability cost is introduced to minimize the total cost of DFCL utilization. Based on the proposed strategy, which will be evaluated through various scenarios, the optimal coordination between existing relays are restored and the whole MG would be protected without the need to use adaptive protection schemes or new relays.

1. Introduction Microgrid (MG) is a small-scale distribution network that includes both synchronous and inverter based Distributed Generators (DGs) and loads which normally operates connected to the utility grid at the Point of Common Coupling (PCC). However, as a key feature, MG will be disconnected from the utility in the case of utility events (e.g., faults and voltage collapse), and could be also intentionally disconnected under power quality issues. In such a situation, MG would be able to function autonomously in islanded mode. The capability of the MG in operating in both modes of grid-connected and islanded mode can improve the power system service quality and increase the power system reliability. Despite the benefits that MG operation can bring to the power system, it comes with its challenges and technical issues. The presence of DGs within MG as well as different operation modes of MG may impact on the operation, control, protection, and reliability of the existing power network. These issues should be assessed and resolved

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carefully before MG implementation [1,2]. Otherwise, the expected operation of MG is restricted, and the reliability of the system degrades. The area that is critically affected by MG operation is the existing protective system in the distribution network. Distribution networks are usually radial, and their overcurrent based protection scheme is designed and coordinated without considering DGs. However, by installing DGs, particularly synchronous-based ones, an additional contribution to the fault level is provided from MG where the short circuit capacity and the line current amplitude and direction- which are the main factors in designing and coordinating protection relays- could change causing a miscoordination problem in the existing protection scheme [3,4]. On the other hand, the contribution of the MG in the fault, due to DGs reaction, can cause the overall fault current to exceed the designed fault level of distribution equipment, like cables or Circuit Breakers (CBs). In this case, CBs are subjected to increased stresses and are thus more prone to failure to operate when desired. It should be however noted that, this issue occurs more often in MGs involving synchronous-

Corresponding author. E-mail addresses: [email protected] (M. Farzinfar), [email protected] (M. Jazaeri).

https://doi.org/10.1016/j.ijepes.2019.105564 Received 12 April 2019; Received in revised form 14 August 2019; Accepted 20 September 2019 0142-0615/ © 2019 Elsevier Ltd. All rights reserved.

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network equipment are designed but also can restore the coordination between overcurrent relays. Utilizing superconducting FCL with optimized impedances in series with DGs has been proposed in [27] to solve the coordination problem. In [28] an SFCL has been installed in front of DG to enhance fault ride through capability of the DG and also restore the relay coordination. However, demerit of papers [27,28] is that number and cost of FCL increase with more penetration of DGs. Further, utilization of the FCL inside the MG, can reduce the fault level in the event of MG fault. In reference [29], using FCL to limit the fault current simultaneously changing the DG infeed relay settings has been suggested. In this paper size and cost of FCL is reduced compared with reference [27]. In all the above-mentioned references, FCL acts for all faults on both the upstream network and MG side regardless of the direction of the fault current. The operation of the FCL in the case of fault occurrence on the upstream is desirable due to mitigating the negative impact of DGs and MG on a protective system of the utility network. But, for the faults on the MG side, the operation of the FCL considerably reduces the contribution of the main grid and; hence, this issue may lead to loss of coordination between upstream relays and MG relays. It is obvious in such circumstance that the reliability of the system degrades or the reliability cost increases. To overcome this issue, employing a Directional FCL, which has been experimentally designed in [30], hereinafter, called DFCL, is recommended to be installed at PCC. The DFCL is designed to operate for external faults on the upstream network. However, introducing the DFCL at the PCC alters the fault current which could affect the coordination level among relays causing further system reliability degradation. Consequently, setting of the DFCL parameters is a challenging task. In [31] an FCL is used as an interface between the MG and upstream network that could optimally achieve power quality and relay coordination of the MG. Similarly, in reference [32] an optimization algorithm is employed to calculate the optimal setting of overcurrent relays in the MG and to find the optimum value of the FCL at the PCC. However, setting of the DFCL from the relibility point of view has not been addressed in these mentioned papers and also related ones till present time. In this paper, a novel methodology for optimal setting of DFCL parameters (R and X) is proposed therein the effect of DFCL on OCRs coordination and system reliability is considered simultaneously. For this purpose, an objective function in terms of DFCL installation and reliability costs is introduced to minimize the total cost of DFCL utilization. Relying on the proposed strategy, which will be evaluated through various scenarios, the optimal coordination between existing relays are restored and the whole MG would be protected without the need to use adaptive protection schemes or new relays.

based DGs, such as the MG under study of this paper, as the fault contribution of the inverter-based DG is generally limited to maximum 2 times of its rated current [5]. Moreover, miscoordination problem due to MG contribution to the faults may cause delayed operation of some relays. In such circumstances, the duration of fault current that passes through CBs may be prolonged and; hence, the probability of exposing hidden CBs failure increases when they are about to isolate the faulty section. The stress-induced failure in the CB is commonly referred to as hidden CB failure which causes maloperation in the protective system [6,7]. Thus, it can be concluded that if the relevant solutions are not taken to mitigate this issue, not only the MG cannot provide its benefits for consumers, such as reliability enhancement, but also CB failure may lead to multiple or cascading outages in the power utility, further degrading system reliability [8]. This issue, which is one of the major aspects of the present paper, has not been addressed in most recent literatures. In order to address the protection challenges associated with DG integration and MG operation, proper protection schemes are required so that could effectively function in both grid-connected and island modes. In this regard, various MG protection schemes and coordination techniques have been recently researched in the literature. The presented protection methodology can generally be divided into novel schemes, based on which the existing protection strategies (usually overcurrent-based) are replaced with new ones or equipment [9,10], and conventional schemes in which the existing schemes are improved to suit MG operation [11]. Adaptive protection is one of the main schemes in the first group which is an online and real-time activity that modifies the protection relay settings based on MG state (topology, generation, and load level) [12]. Using numerical relays and advanced communications architectures and protocols are the technical requirements for the practical implementation of such schemes. In this regards, some other communication-based approaches have been presented in [13–15]. Reference [16] proposes a centralized communication based protection scheme with a localized backup for a MG. The presented scheme is implemented using the percentage differential current approach. Furthermore, in connection with this group, devising some protection strategies based on multifunctional microprocessor-based relays is suggested for the protection of MG [10,17]. Reference [18] proposes a comprehensive protection strategy based on digital relays, which is applicable to both grid connected and islanded modes of operation. Such strategies generally use a combination of overcurrent, over/under voltage, and over/under frequency protection units to ensure reliable functioning of the protective system. Even though utilization of these new schemes can mitigate the problems of MG protection, the cost and complexity of these methods is one of the criticisms leveled against them at present. Another critical issue connected to using new schemes is that utilities usually appear reluctant to change tried-and-tested relay settings to new relays, arguing that new methodologies may cause unforeseen problems. On the other hand, they are not effective in reducing the risk of damage or failure of circuit breakers and other equipment resulting from the increase of fault level due to DG integration and MG operation. Hence, relying on the existing relays, in order to mitigate the protection issues caused by DG integration is more desirable particularly when part of a distribution network is about to transform to an MG. Another main method in solving the protection issues of distribution networks equipped with DGs and MGs is using Fault Current Limiter (FCL). Furthermore, since the replacement of the CBs with greater capacity causes enormous cost and technical limitations, employing FCL to solve the increase of short-circuit current has been noticed as the most promising solution [19,20]. By utilization of FCL the excessive currents in the case of a fault are limited by rapidly increasing FCL impedance, while under normal operation, FCL remains virtually invisible by introducing negligible impedance [21]. Several FCL technologies and applications are reported in [22–26]. Installing FCL not only controls fault currents to levels where the

2. Problem statement 2.1. Relay coordination in passive distribution network Distribution networks are usually radial, and their overcurrent protection system is designed based on characteristic curve given in (1) and coordinated without specifically considering DGs [33]. t

∫ ⎡⎢ ⎛ IFaultIp(t ) ⎜

0

⎣⎝

α

⎞ − 1⎤ dt = k × TSM ⎥ ⎠ ⎦

⎟

(1)

where TSM and Ip are the time setting and pick up current setting of the relay, respectively; and IFault (t ) stands for the short circuit current passing through the relay. α and k determine the shape and steepness of the curve based on IEC60255. These overcurrent relays need to be coordinated such that the nearest relay to the fault, as the primary relay, operates first and fast; and in the case of unsuccessful trip of the primary relay, the backup relay will operate after predetermined Coordination Time Interval (CTI), normally in the range of [0.2–0.5] sec to satisfy the coordination 2

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for installing FCL, such as in front of the point of integration in the DGs, bus tie, and feeders has been suggested in the literature [5,13,36,37]. FCL in these locations will control the fault contribution of DGs or feeder on which DG is integrated to the fault point. However, this approach for a MG, which may contain several DGs, is not cost effective. Moreover, by installing FCL inside the MG the short circuit level of the MG during islanded mode is reduced drastically so that the overcurrent protection in islanded MG will not be applicable. Regarding aforementioned issues, by installing an FCL in the utility grid interface at Point of Common Coupling (PCC), (Between MG and upstream network) and in case of fault occurrence in the upstream network, the fault current contribution of the whole MG is mitigated; and the coordination between utility and MG relays are maintained. But, in case of a fault inside the MG, e.g., fault on Line 7 in Fig. 1, the operation of the FCL decreases the contribution of the main grid considerably. In this condition, the fault current sensed by upstream relays as backup, for instance relay R4, decreases while the primary relay in the MG, i.e., relay R6 in Fig. 1, may not experience severe reduction in its fault current owing to the contribution of DGs to the fault. Under such circumstances, CTI between downstream and upstream relays is prolonged, thereby resulting in coordination loss between them. In the other hand, in the case of fault on Line 7, if the primary relay, i.e., R6, fails to operate, the fault remains in the network for a longer period of time due to delayed operation of backup relay. This means that the fault current passing through upstream CBs subjects them to stress. From the reliability point of view, in such a condition, if CB receives a trip command from pertinent relays, it may fail to open it due to exposed hidden failures. Consequently, the relays in the adjacent lines or relays in other points of the network should operate, which cause removing operating sections of the system; and the system reliability further decreases as more customers are affected. To overcome this issue, employing a directional FCL, hereafter, called DFCL, is recommended to be installed at PCC. The activation of DFCL for the faults in the upstream network, like FCL, is desirable to reduce the fault contribution of DGs and mitigate the negative impact of MG on coordination. On the contrary, in the case of fault within the MG, DFCL should be blocked to avoid the miscoordination issues. The implementation of DFCL can be realized simply by adding a directional unit to the FCL which already has been designed in [30,31] and is not discussed here for the sake of brevity. It should be noted that practical use of such configuration, setting of the DFCL parameters (R and X), is a challenging task and should be done considering reliability of the system. In this paper, a novel methodology for optimal setting of the DFCL parameters is proposed in which regarding reliability of the system (which varies with miscoordination level), the optimal coordination between existing relays are restored and; therefore, the whole network would be protected without the need to use adaptive protection scheme or new relays

Fig. 1. Single-line diagram of the study system.

criteria for preventing the miscoordination of relays [34]. However, in networks where DGs are integrated, protection pattern is an important issue that needs detailed assessment as the DGs can contribute to the faults and also impact the operation of the protective devices due to the change in fault level. 2.2. Protection issues caused by MG operation By MG operation, which enables DGs to integrate into existing distribution grid, the short circuit levels and the line current amplitude and direction; which are the main factors in designing and coordinating protection schemes, could change and cause a miscoordination problem in the existing protection system [4]. Fig. 1 shows case study of a MG system in which location of the OverCurrent Relays (OCR)-(labeled as R0-R8)- are depicted. Data related to the network and DG units are reported in Appendix. Simply the miscoordination might happen in the form of unnecessary tripping and/or delayed operation of some relays. It is obvious that in such circumstances, the reliability of the system degrades. Moreover, DGs integration in some cases, especially in the case where synchronous-based DGs are allocated within MG, could result in the fault level exceeding the design short-circuit capacity of the equipment, like CB, that increase the risk of damage to, and failure of them. On the other hand, when one of the relays operates with delay due to miscoordination, protection system components, such as CBs, are more subjected to increased stresses and are thus more prone to failure to isolate the faulty section. This stress-induced failure caused by increase in the magnitude and duration of a fault current passing through CB, is commonly referred to as CB hidden failure [35]. In such situations, inevitably the backup protection relays operation causes shutdown of a larger section. Thus, system reliability further decreases as more customers are affected. Therefore, to realize MG implementation and development with the purpose of improving reliability and resiliency of the grid, an effective solution should be proposed to address these issues.

2.4. Stability of MG after islanding As stated earlier, the potential to improve reliable distribution systems is a primary motivation behind the development and deployment of MGs. To achieve this goal, in addition to the importance of the protection strategy, maintaining the stability of the MG after transition to islanded mode is one of the critical issues, which should be addressed. In fact, in the event of faults, when a MG is isolated form the main network, voltage/frequency variation of the MG occurs which might cause DG instability and so of the whole MG. In such condition, the MG is not able to operate continuously in islanded mode. Therefore, looking at the protection issues without taking the stability problem of MG into account, which potentially happens after operation of the protective system, is not effective. In the context of MG protection, this issue, which has rarely been discussed, is overcome by utilization of a Central Stabilization Unit (CSU) in the present study.

2.3. Fault current Limiter (FCL) Utilization of a fast-acting current limiting device, like FCL, with its capability in controlling fault-current levels, is one of the suitable solutions for maintaining the protective coordination on utility distribution equipped with DGs. Furthermore, FCL significantly alleviate power system stress in locations where fault current magnitudes are expected to increase beyond the duty of existing CBs. Hence, different locations 3

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3. Implementation of the proposed protection strategy

IFault = IUP + IMG

(2)

3.1. Protection of MG in grid-connected mode using DFCL- theoretical analysis

IFault =

C·Un 3 ·ZTotal

(3)

where Un and C are the rated voltage and voltage factor, respectively. ZTotal is the equivalent short circuit impedance seen from the fault point and is given by:

As previously discussed, although employing non-directional FCL by reducing the fault current contribution of DGs could restore the optimal coordination of some relays, but its operation in the case of faults on the MG leads to miscoordination between upstream relay and MG relays. The coordination results caused by such a case will be reported in Section 4. In this paper, in order to overcome this issue, instead of using a conventional FCL, utilization of a DFCL at PCC is suggested (See Fig. 1). DFCL is set to be activated for all faults in the upstream network to mitigate the negative impact of the MG on relay miscoordination, while it does not operate when the fault is occurred within the MG. The current limiting capability of DFCL depends on its impedance value. In fact, DFCL presents a low impedance value in normal and MG faults conditions and a high impedance value for all faults in the upstream network. Therefore, only tuning impedance parameters of the DFCL (X and R) is considered in the proposed methodology and other detail of DFCL structure is not discussed here. The placement of the DFCL at the PCC limits the contribution of the MG for upstream faults and so the coordination between OCRs for all various fault condition is preserved. To demonstrate this phenomenon analytically, Fig. 2 illustrates the equivalent diagram of MG under study (Fig. 1) for the short-circuit calculation in the event of a fault at Bus B5, which has been derived on the basis of IEC Standard 60909 [38]. In Fig. 2, E is defined as the voltage of an ideal source applied at the short-circuit location in the positive-sequence system, whereas all other sources (i.e., DGs and upstream network) in the system are ignored and are only replaced by their internal impedances. However, in this diagram the short-circuit current contribution from different sources (synchronous and inverter-based DGs) are considered as (I1, I2 and I3). It should be noted that, the fault contribution from inverter is limited by the maximum current level of the applied inverters in the modelling of PV source during fault conditions. Therefore, for the representation of such sources in the short-circuit study applying a constant value (here I2) instead of their fault current contribution is realistic. ZMG the impedance of MG which includes the equivalent impedances of DGs and distribution feeders (ZL = ZLine). Load currents are neglected, and the equivalent voltage source E is inserted at the fault location. The short-circuit current at the fault location comprises contribution of both upstream and MG sides (Eq. (2)) and can be calculated based on equivalent voltage source method depending on equivalent impedance related to the fault point:

ZTotal =

ZUP ·Zeq (MG) ZUP + Zeq (MG)

+ ZDown

(4)

where ZUP and Zeq (MG) are the equivalent impedance of the upstream network (ZUP = Zs + ZL1 − L2 ), MG-interconnected line (Zeq (MG) = ZMG + ZL5 ) and downstream network (ZDown = ZL3 − L4 ), respectively. In this case, the short-circuit currents contributed by the network (IUP) and MG (IMG) are calculated by applying the following equations:

IUP = IFault ×

IMG = IFault ×

Zeq (MG) ZUP + Zeq (MG)

(5)

ZUP ZUP + Zeq (MG)

(6)

Starting from the fault point, for which the short-circuit current was calculated, towards each relay, the short circuit current passing through relays and CBs can be calculated. In the above expressions, IFault is the current passing through relay R2 and R3, IUP is the current passing through relays R0 and R1, and relay R4 senses the fault current contributed by MG in reverse direction (IMG ). It can be obviously concluded that with contribution of the MG, the current flow of the system is changed and; thus, depending on the fault location, the coordination between different relays is lost. As per Fig. 2, ZUP and Zeq (MG) are connected in parallel at PCC, and it can be concluded that increasing any one of the contributing impedances will increase the total equivalent parallel impedance and its share in the fault current will be decreased. In this case, the best strategy that can reduce the fault current and particularly limit the contribution of the MG is to place a DFCL in series with MG at PCC, as depicted in Fig. 3. In such a case, the fault contribution of the MG, is calculated based on the following equation:

IMG = IFault ×

ZUP ZUP + Zeq (MG) + ZDFCL

(7)

As per above equation, the greatest reduction in the fault current level of the MG will be obtained if a DFCL with maximum impedance, ZDFCL , is installed at PCC. However, as the cost of DFCL is related to its impedance, the impedance value of the DFCL should be chosen optimally. In the proposed approach of this paper, this issue is also considered.

Fig. 3. Equivalent diagram of the studied MG equipped with DFCL (fault occurs at B5).

Fig. 2. The equivalent diagram of studied MG (fault occurs at B5). 4

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On the other hand, and from the reliability point of view, increase in the fault current through protection system components such as CBs may increase the hidden failures in CBs and decrease the reliability of the system. Regarding this issue, another advantage of utilizing DFCL is mitigating the fault current passing through the system components. Therefore, the DFCL parameter should be optimally set in order to restore the coordination between relays and prevent a decrease in reliability level.

FI =

t=2

∑0

IShorTime (2sec ) Δt

(9)

where IShc (t ) is the short circuit current passing through different CBs in the network which is calculated based on Eqs. (1), (4), and (5). IRD and IRU are the rated and interrupting rating current of each CB, which in this research are considered 1.25 and 6 times of the rated current of each CB. Parameters tT and tC stand for the time when the fault current exceeds a predefined values (IRD and IRU ) and the time when the fault is cleared by a relay. Detailed information about different terms of this equation can be found in [39]. Accordingly, it can be concluded that if contribution level of the DGs or MG approaches or exceeds the CB interrupting rating, the probability of CB failure, when it is required to operate in the fault condition, increases due to exposing hidden failure. Therefore, the idea of utilizing DFCL would help mitigating the fault contribution of the MG. In the MCMC technique, the MC simulation is run for each hour to determine behavior of the lines and CBs. Then, ECOST index is calculated at the end of a year. It should be noted that, because the failure rate of components is low -particularly for CBs which their hidden failure is not so frequent and is indeed relatively rare- a large number of years (or replication) equal to 1000 years is used for MC simulation to obtain statistically converged and meaningful results. In other words, this methodology by calculating the reliability index, ECOST representing the reliability cost, demonstrates that coordination level among OCRs impacts on the system reliability directly. On the other hand, as discussed previously, the coordination between relays is altered by integration of DGs, DFCL installation, and its setting. Therefore, in order to obtain the optimal setting of DFCL, calculating the reliability cost of the system considering DFCL setting is essential. Reliability Cost: Different settings of the DFCL parameters lead to different levels of coordination (or miscoordination) among relays and so variable reliability levels. Therefore, in using and proper setting of DFCL for the purpose of MG protection, the reliability of the system, as one of the major factors that is directly interrupted by miscoordination between OCRs, should be considered. Hence, in this paper a new reliability cost function, regarding cost of the system reliability due to miscoordination among the OCRs, is obtained to be utilized as one term of the proposed OF. In this regard, to calculate and estimate the reliability cost, the total amount of miscoordination time between the relays should be initially calculated in several scenarios associated with different levels of miscoordination. It is clear that, the greater number of simulated scenarios is, the more accurate the estimated reliability cost function will be. For this, various scenarios with different levels of miscoordination among OCRs - including base network, DG integration, MG operation, different settings of OCRs, DFCL installation, and different settings of DFCL- are studied. Afterwards, the presented reliability algorithm (MCMC flowchart in Fig. 4) is carried out for these scenarios to obtain the ECOST index, which is equivalent to the cost of the reliability for each scenario. In fact, the functional relationship between calculated ECOSTs and miscoordination level, can indicate the cost of reliability in different conditions of miscoordination. It should be noted that the conventional network (Fig. 1), when no DG is installed is selected as the base and first scenario, in which the best coordinated operation of the relays is existed. In this scenario, the primary and backup relays are optimally set based on a modified Particle Swarm Optimization (PSO) technique. The optimal coordination formulation of relays for optimal selection of TSM and IP of each relay has been presented in detail in [33]. Finally and as per above mentioned procedure, a cost function for evaluation of the reliability cost in terms of the level of miscoordination is fitted as follows:

3.2. New methodology for optimal setting of DFCL parameters Due to impact and important role of DFCL in maintaining relay coordination and so system reliability (from coordination point of view) through changing fault current, proper setting of the DFCL is crucial. In this paper, a novel optimal setting is presented therein considering the effect of DFCL on relay coordination and system reliability cost (which changes indirectly with coordination level(, the optimal parameters of the DFCL (R and X) are calculated. For this purpose, a new objective function is defined to minimize the total cost of DFCL utilization that is composed of two different terms as follows:

OF = Min (βCostReliability + CostDFCL).

t

∑tcT (IShc (t ) − IRD )Δt + ∑tcT (IShc (t ) − IRU )Δt

(8)

The first term of the OF in (8) is introduced to minimize the cost of the system reliability caused by relay miscoordination, and the second term is used to minimize the cost of the DFCL installation. In fact, in the proposed objective function while minimizing the cost of DFCL, the effects of DFCL parameter on the relay coordination has been altered to the reliability cost in the first term, to be optimized simultaneously. In order to evaluate the effect of relay miscoordination due to MG operation on reliability degradation of the system, a Markov Chain Monte Carlo (MCMC) algorithm is presented, which is a modified version of the algorithm used in [39]. This methodology is initially explained and the procedure for calculating reliability cost is defined thereafter. 3.3. Evaluation the impacts of relay coordination on system reliability Unsuccessful and inaccurate operation of protective devices considerably degrades network reliability. For instance, as mentioned earlier, owing to miscoordination among the relays in form of delayed operation or unnecessary trip, in addition to interrupting loads, the probability of hidden failures exposure in protection system components such as CBs may increase. In this part, a methodology based on Monte Carlo (MC) simulation is applied, to assess system reliability indices from protection point of view (In this paper ECOST index is only obtained). The main purpose of using this method is to evaluate how the proposed protection scheme can maintain the reliability provided by the MG operation. The overall flowchart of the algorithm is illustrated in part A of Fig. 4. The detail of this methodology, known as Markov Chain Monte Carlo (MCMC) technique, has been already presented in [39]. MCMC applies Markov Chains to the stochastic process to implement dynamic MC simulation. Two separate Markov Chain models (for lines and CBs) are employed to represent possible states (available and unavailable) of each component during MC simulation. The transition rate between available and unavailable states is considered as per failure rate (λ) and repair rate (µ) of each component. To make the analysis more convenient, the failure rate and repair time of lines within MC simulation is assumed to be constant. These values are considered to be 0.8 failure/ year and 3 h/failure for each line, respectively. Nonetheless, failure rate of CBs is considered variable since the probability of CB failure increases in proportion to the magnitude and duration of fault currents passing through it. This matter becomes more important in condition of the MG operation, which DGs integration changes the flow of shortcircuits current in the network. Hence, a CB Failure Index (FI), as follows, is proposed to construct the reliability Markov model of CBs when applying the MCMC algorithm

CostReliability = 6942.78 × exp (0.00899CTIadditive ). 5

(10)

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Fig. 4. Flowchart of the proposed methodology.

3.4. Protection and control of MG in islanded mode

This function is used as CostReliability in the proposed OF (in Eq. (8)), and during process of optimal setting of the DFCL parameters, the effect of obtained parameters on restoring OCRs coordination from reliability cost point of view is considered in each iteration. In Eq. (10), CTIadditive represents the sum of the coordination times between the OCRs in terms of the time difference between operation of the main relay and backup relay (CTI ). Also, considering the importance of the cost of reliability, relative to the price of the DFCL, a weighting factor (β) is brought up in the presented OF, which is selected 10,000 in this paper. DFCL Installation cost: During optimization process, due to price dependency of the DFCL on its parameter (X, R) settings, the reliability installation cost of the DFCL (CostDFCL ) should be also considered. In order to optimize the cost of protection scheme, the following cost approximation function, based on data for a 20 kV FCL in [40], can be considered to be added to OF.

Two main issues in operation of MG in islanded mode are: – Control of MG for maintaining stability of MG after transition to stand-alone mode, – Protection of islanded MG. Immediately after disconnection of the MG from the main network, the adopted control routine plays an important role in maintaining stability of the MG, until islanding is successfully achieved. It is a common practice to control the MG based on various control modes of DGs. This procedure maintains voltage/frequency stability of MG while it is disconnected from upstream network. However, relying solely on DGs control strategies have the following drawbacks: – The capacity of DGs might not be enough to compensate the required power in severe variations. Moreover, some DGs may not be available all the time due to their intermittent nature. – Small rotating generators and particularly inverter-based resources, like Photovoltaic (PV) plants, which are connected to the grid through power electronic converters, have low inertia. Hence, they are sensitive to voltage/frequency variation and may disconnect if the range of allowable variation is violated after islanding.

50000.47(3.95 − 3.2377exp (−0.045X )) X ≥ 6.5 Ω CostDFCL = ⎧ ⎨ 18775.99(5.1 − 5.1exp ( −0.25X )) X < 6.5 Ω ⎩ (11) where X stands for the reactance of the DFCL. It should be noted that in the optimal algorithm, because the impact of the reactance of FCL on restoring the coordination is more significant, the cost of the resistive part of FCL is considered two folds more than the reactance part. 6

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Therefore, control of the MG with high penetration level of such DGs is a challenging task as it is more prone to instability during fault and thereafter islanding.

Table 1 Optimal setting of relays in Fig. 1. Relay Name Relay Relay Relay Relay Relay Relay

To overcome these issues, utilizing a Central Stabilization Unit (CSU) is necessary at the PCC (see Fig. 1) to supply dynamically active and reactive need of MG after transition to islanded mode. The CSU is equipped with a rotating synchronous generator to increase the inertia of whole MG which considerably leads to stability enhancement of the MG after transition to the stand alone mode. In this way, the successful and stable operation of the MG in islanded mode can be guaranteed. The control strategy of the CSU undertaken in this paper is simply characterized as follows:

0 1 2 3 4 5

(R0) (R1) (R2) (R3) (R4) (R5)

TMS

Ib (I >) (p.u)

I≫

Characteristic

0.415 0.105 0.085 0.05 0.125 0.13

1.27 1.95 1.51 1.23 1.25 0.73

6*Ib 6*Ib 6*Ib 6*Ib 6*Ib 6*Ib

EI EI EI EI EI VI

TMS: Time multiplier Setting, Ib: pick up current, Line CT RATIO = 300/1. EI: Extremely Inverse (α =80, k = 2) VI: Very Inverse (α =13.5, k = 1).

– Constant Power Factor (PF) mode: This function is intended to provide a simple mechanism through which the power factor of CSU may be set to fixed values, and while the MG is in grid connected state is utilized. – Volt/Var and Power/Frequency mode: This control mode is intended to provide a mechanism through which CSU is configured to manage its own reactive /active power output in response to the voltage /frequency change of the MG. In other words, the control routine of the CSU switch over from (PF) mode to the second one as soon as the MG gets islanded. Protection of MG in islanded mode is another concern of MG development. In islanded mode, the fault level of MG owing to disconnecting from upstream network is considerably reduced. Accordingly, the overcurrent relaying scheme developed for grid-connected mode is no longer reliable and effective. From the protection point of view, CSU will improve the performance of overcurrent relays by enhancing the fault current level of the MG. Furthermore, to guarantee fault detection by OCRs within MG, different setting groups associated with islanded mode is considered. For this purpose, the settings for the OCRs, related to islanded mode, are calculated offline and stored in the relays. Changing different settings is done based on transfer trip scheme so that when the MG is disconnected from upstream grid, PCC CB sends a signal to OCRs in the MG showing its status, then related setting group is activated automatically. It should be mentioned that in islanded mode, the DFCL is separated from the grid and has no impact on protection setting.

Fig. 5. Time-current characteristic of coordinated OCRs. Table 2 Level of Relay coordination in scenario 1. Fault location

Pair relays

B5

Main Backup Main Backup Main Backup Main Backup

B4 B8 B7

4. Simulation and results To verify the effectiveness of the proposed protection scheme, the case study, shown in Fig. 1, is considered, and static and dynamic modeling of system components, the simulation routine, and all different analyses for calculating the reliability indices are carried out using DIgSILENT software. The simulation routine is best accomplished through a step wise process by determining five different scenarios, and although, due to this reason, only implemented on test case of Fig. 1, the proposed methodology is derived in such a way that it can be implemented on any other case study. In the following, these five scenarios, which are brought up from the scenarios that were used for estimation of CostReliability function in Eq. (2), and their relay coordination accuracy are described. Scenario1- Passive network without DGs In the first and base scenario, the passive network when no DG and FCL used, is modeled. In this case, OCRs are set to achieve a high accuracy of coordination. To this end, an modified PSO known as Multiple Embedded Crossovers PSO (MECPSO) [33] is utilized for optimal coordination between OCRs R1-R6 in Fig. 1. The used method is able to select the best characteristic for OCRs to achieve the optimal coordination. The obtained optimal setting of these relays is reported in Table 1, and the time-current characteristic of these relays based on optimal setting are depicted in Fig. 5. The proper coordination between

R3 R2 R2 R1 R6 R4 R5 R4

Fault current (A)

Trip time (sec)

CTI (sec)

4279.92 4342.19 4711.29 4873.49 4467.12 4526.05 4667.45 4525.27

0.066 0.30 0.251 0.577 0.050 0.306 0.050 0.306

0.233 0.325 0.256 0.256

CTI: obtained Coordination Time Interval between main and backup relays.

relays can be seen in this figure; however, to show the quality of coordination, the operation of relays in response to four different fault locations, B5, B4, B7, B8 as depicted in Fig. 1, and the level of coordination among pair relays are tabulated in Table 2. Scenario2- network with DGs: In the next step, by installing DGs in the grid, the amount of miscoordination between relays, which are optimally coordinated in the first scenario, is investigated. The quality of coordination in this scenario is reported for the same fault conditions in Table 3. As shown in Table 3, with integration of the DGs, the coordination among OCRs is lost in the case of fault occurrence on the B4 and B5 busbars. This miscoordination, which occurs in the form of decreasing and increasing of the CTI between the main and backup relays, is highlighted in the orange color in this tables. Scenario3- network with DGs-MG operation Unlike scenario 2, the network in this scenario can be operated as MG. However, for the studied fault locations and from the coordination point of view, the level of coordination in scenario 3 is the same as scenario 2, as reported in Table 3. 7

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Table 3 Level of Relay coordination in scenario 2 and 3.

Table 5 Level of Relay coordination in scenario 4.

CTI: obtained Coordination Time Interval between main and backup relays.

CTI: obtained Coordination Time Interval between main and backup relays.

Scenario4- OCRs coordination restoration using non-directional FCL As per result of Table 3, the coordination among OCRs is affected by inserting DGs and so for reliable operation of the MG, a solution should be introduced to overcome impacts of the DGs and to avoid the miscoordination problem. In this paper, utilizing FCL, as a proper solution for restoring OCRs coordination, is recommended at the PCC and its optimal setting is calculated based on the proposed OF in Eq. (8). Due to the fact that the settings of the protective equipment remain unchanged, by changing impedance of the FCL in the optimization process (as per proposed flowchart in Fig. 4), if there still exist miscoordination, the cost of reliability (CostReliability ) is increased due to miscoordination. In this way, a large number is added to the OF, in order to eliminate these iterations by the MECPSO algorithm. Finally, the small and optimal values for the FCL parameters are determined, while the coordination will also be maintained, and the reliability will be at the best possible level. The calculated values for the FCL by the proposed algorithm is reported in Table 4. However, in order to ensure that the used MECPSO is perfectly capable of dealing with the optimization process, an improved GA algorithm is also applied to the proposed algorithm. The calculated optimal parameters of the FCL in the latter case is also reported in Table 4 for the sake of comparison. Proximity of results of two solvers to each other proves that the values obtained through MECPSO is optimal solution and may be the global, hence, these values are applied to simulations hereafter. Table 5 shows the impact of FCL installation and its optimal setting on restoration of OCRs coordination. According to the results, although the non-directional FCL restores miscoordination in the previous scenario, it significantly degrades the coordination between upstream and downstream relays under the faults occur in the MG (as highlighted in orange color). In other words, the operation of the non-directional FCL in the case of fault occurrence on the upstream is desirable, since it mitigates the negative impact of DGs (and so MG) on protective system of the utility network. However, for the faults on the MG side, operation of the FCL considerably reduces the contribution of the main grid and hence this issue has led to loss of coordination between upstream relays and MG relays and so degrading reliability of the system (as highlighted in Table 5). To overcome this issue utilization of a Directional FCL (DFCL) is suggested and studied in scenario 5. Scenario5- OCRs coordination restoration using DFCL Table 6 shows the coordination level among OCRs when DFCL with the same optimal setting of Table 6 is utilized at the PCC. In fact, although the optimal impedance of the FCL (obtained based on the proposed methodology) in the case of upstream faults leads to accurate coordination between relays, a considerable miscoordination among

Table 6 Level of Relay coordination in scenario 5. Fault location

Pair relays

B5

Main Backup Main Backup Main Backup Main Backup

B4 B8 B7

R3 R2 R2 R1 R6 R4 R5 R4

Fault current (A)

Trip time (sec)

CTI (sec)

4575.20 4641.19 5060.15 4486.97 4981.21 3939.24 4754.32 3938.06

0.057 0.259 0.215 0.702 0.050 0.409 0.050 0.410

0.201 0.486 0.359 0.360

CTI: obtained Coordination Time Interval between main and backup relays.

OCRs occurs for MG faults (e.g., at B7 and B8 as per Table 5) due to the non-directionality of the FCL. To deal with this issue, a DFCL with the same impedance setting of Table 4 is utilized at the PCC. Results of Table 6 clearly show the efficiency of using DFCL in restoring OCRs coordination in grid-connected mode, in comparison to the condition that FCL is used. In other words, the proposed methodology can protect the MG selectively and prevent reliability loss. As shown in Table 6, with the optimum size of the DFCL obtained by the proposed algorithm, in all cases, the coordination of equipment is maintained in an acceptable range in addition to reducing the negative effect of integration DGs on the performance of the protective system. Therefore, the proposed scheme of the paper, is technically able to protect the upstream network and MG. moreover, from the economic point of view, the proposed scheme is also justifiable, as in implementation of it there is no need to use new relays or protective schemes. Evaluation of the MG reliability in different scenarios At last, the MCMC algorithm presented in Fig. 4 is separately implemented for different scenarios to verify the effectiveness of the proposed method, in addition to test the effect of DGs installation on the performance of the protection system from the reliability point of view. For this purpose, reliability index of ECOST in the five described scenarios are reported in Table 7. In this table, ECOST for the upstream network and the MG are also calculated individually. Comparison of the results in scenarios 1 and 2 shows that with the installation of DGs in the network, the reliability level of the system decreases (or reliability cost increases); which this is due to increase in the magnitude of the fault current and also the occurrence of miscoordination between OCRs as a result of the DGs integration. It is necessary to note that in scenarios 1 and 2 the MG is not able to operate in islanded mode; while as per description of scenarios, in stark contrast, the MG in the scenario 3 is separated from the PCC when a fault is Table 7 ECOST ($/Year) calculated for 5 scenarios.

Table 4 Optimal FCL parameters. Solver

X (Ω )

R (Ω )

MECPSO GA

2.97 2.54

0.694 0.773

Upstream MG Total

8

Scenario 1

Scenario 2

Scenario 3

Scenario 4

Scenario 5

2678.237 1607.319 4285.556

2791.507 1625.1 4416.607

2792.287 231.4651 3023.752

2739.88 244.692 2984.572

2737.41 230.787 2968.197

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scenario 5.

occurred within the upstream network and continues to operate as an island. Therefore, the reliability of the MG side (and consequently total reliability of the system) in scenario 3 is considerably improved compared to scenario 2 (and also scenario 1). Table 6 shows that in scenario 4, the miscoordination appeared in scenario 3 is eliminated and the reliability cost decreases. However, in this case, a new form of miscoordination arises which has been highlighted in Table 5. Accordingly, it is clear from Table 7 that the reliability cost (ECOST) of MG in scenario 4 is deteriorated more than that in the third scenario. This is because of the existence of miscoordination in scenario 4 in form of delayed operation of the backup relay R4. In other words, as the relay R4 takes longer to clear the fault, the probability of hidden CB failure is increased and; thus, further degrades the reliability of the MG side as more customers are interrupted. It is also clear from the results of Table 7 that the upstream reliability in scenario 4 is declined in comparison with scenario 3 owing to the reduced fault current in the use of the FCL. It can be concluded from the results summarized in Tables 6 and 7 that the utilization of the DFCL is well-suited for restoring the optimal coordination between the relays and improving the system reliability compared to other scenarios. It can be seen from Table 7 that the overall interruption cost of the studied system (The total upstream network ECOST and MG ECOST) is calculated equal to 2984.572 $/Year when a non-directional FCL is used. While this cost is reduced to 2968.197 $/Year when a DFCL is replaced and the proposed methodology is employed. It should be also noted that although the obtained indices for the upstream side are almost the same for scenarios 4 and 5, the results are completely different for the reliability cost of the MG. A possible reason is that both FCL and DFCL have the same performance for the upstream fault and thus the same upstream ECOST in these two scenarios are expected to be achieved. However, as discussed earlier, existence of miscoordination in scenario 4 because of delayed operation of the OCRs, leads to higher MG ECOST in this scenario compared to

5. Conclusion Contribution of the MG in fault condition (due to the presence of DGs) leads to fault current change that has two consequences. First, causing miscoordination problem (in the forms of maloperation and delayed operation) in the existing protection system and; second, the probability of exposing hidden CBs failure as the magnitude and duration of a fault current passing through CB increase. Both issues lead to degradation of the system reliability. In this paper, a Directional FCL (DFCL) was used as the interface between the upstream network and the MG, which is only activated in the case of faults on upstream network and limits the fault contribution of the MG. Also, due to the impact of DFCL impedance value on miscoordination and reliability level, a new methodology based on MCMC algorithm was proposed for optimal setting of DFCL parameters (R and X). In the proposed method, while reducing the installation cost of the DFCL, the DFCL impedance is optimally adjusted in such a way so as to reduce the reliability cost and miscoordination level simultaneously. The results obtained in different scenarios confirm the effectiveness of DFCL utilization, optimization of its parameters in reducing the cost of system reliability, and restoring optimal coordination between OCRs. In fact, relying on the proposed methodology can significantly restore the optimal coordination between existing relays and properly protect the MG at the same time. Declaration of Competing Interest The authors confirm that there are no known conflicts of interest associated with this publication and there has been no significant financial support for this work that could have influenced its outcome.

Appendix Study system data

System Element

Data

Upstream Network T1 (YNd) T2, T3 (Dyn) T4 (Dyn) T5 (Dyn) CSU Gen. SG Gen. PV Gen. Line 1–5 Line 6–9 Loads (L1–L3) Loads (L5–L8)

V = 63 kV, S = 350 MVA S = 40 MVA, Uk% = 13.5 S = 1.5 MVA, Uk% = 6 S = 2 MVA, Uk% = 4% S = 8 MVA, Uk% = 10.3% S = 7 MVA, V = 6.3 kV, x″d = 0.168 pu S = 1.5 MVA, V = 6.3 kV, x″d = 0.18 pu S = 2 MVA, V = 0.4 kV R = 1.356 Ω, X = 1.232 Ω R = 0.8136 Ω, X = 0.7396 Ω S = 4 MVA, PF = 0.95 Lag S = 2 MVA, PF = 0.95 Lag

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