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Coordination of dual setting overcurrent relays in microgrid with optimally determined relay characteristics for dual operating modes

Coordination of dual setting overcurrent relays in microgrid with optimally determined relay... Fault current magnitude in a microgrid depends upon its mode of operation, namely, grid-connected mode or islanded mode. Depending on the type of fault in a given mode, separate protection schemes are generally employed. With the change in microgrid operating mode, the protection scheme needs to be modified which is uneconomical and time inefficient. In this paper, a novel optimal protection coordination scheme is proposed, one which enables a common optimal relay setting which is valid in both operating modes of the microgrid. In this con- text, a common optimal protection scheme is introduced for dual setting directional overcurrent relays (DOCRs) using a combination of various standard relay characteristics. Along with the two variables, i.e., time multiplier setting ( TMS) and plug setting (PS) for conventional directional overcurrent relay, dual setting DOCRs are augmented with a third variable of relay characteristics identifier (RCI), which is responsible for selecting optimal relay characteristics from the standard relay characteristics according to the IEC-60255 standard. The relay coordination problem is formulated as a mixed-integer nonlinear programming (MINLP) problem, and the settings of relays are optimally determined using the genetic algorithm (GA) and the grey wolf optimization (GWO) algorithm. To validate the superiority of the pro- posed protection scheme, the distribution parts of the IEEE-14 and IEEE-30 bus benchmark systems are considered. Keywords: Plug setting, Time multiplier setting, Protection coordination, Overcurrent relay, Coordination time interval 1 Introduction as measured coordination time interval (MCT) must be Relay coordination is the operation of protective relays in greater than or equal to CTI to ensure proper coordina- a proper sequence when a fault occurs. Depending upon tion among the relays. the fault location in a network, primary and backup relay A relay coordination scheme has two types of inde- pairs (RP) are identified. For proper relay coordination, pendent variables, namely TMS and PS. Depending on the primary relay must operate before the backup relay, these decision variables, the coordination scheme is for- and there must be a time gap between the primary and mulated as a linear, nonlinear, or MINLP programming backup relay operating times, known as the coordination problems [2]. In linear programming, only TMS is treated time interval (CTI) which depends on the type of relays. as a decision variable, while PS is fixed. Using linear pro - The CTI is within the range of 0.3–0.6  s for electrome- gramming (LP) techniques, the optimal value of TMS is chanical relays, while for microprocessor-based relays it obtained by root tree optimization (RTO) [3], improved ranges between 0.2 and 0.5  s [1]. The existing operating firefly algorithm (IFA) [4], genetic algorithm (GA) [5], time gap between the primary and backup relays, known improved harmony search algorithm (IHSA) [6], etc. In nonlinear programming techniques, TMS and PS are both taken as continuous or discrete decision variables. *Correspondence: raghvendra@mnnit.ac.in For electromechanical relays, TMS is continuous, and Electrical Engineering Department, MNNIT, Allahabad, Payagraj, UP, India © The Author(s) 2022. Open Access This article is licensed under a Creative Commons Attribution 4.0 International License, which permits use, sharing, adaptation, distribution and reproduction in any medium or format, as long as you give appropriate credit to the original author(s) and the source, provide a link to the Creative Commons licence, and indicate if changes were made. The images or other third party material in this article are included in the article’s Creative Commons licence, unless indicated otherwise in a credit line to the material. If material is not included in the article’s Creative Commons licence and your intended use is not permitted by statutory regulation or exceeds the permitted use, you will need to obtain permission directly from the copyright holder. To view a copy of this licence, visit http:// creat iveco mmons. org/ licen ses/ by/4. 0/. Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 2 of 18 PS is taken as a discrete variable whereas, for micropro- for both operating modes, the fault current magnitude cessor-based relays, both TMS and PS are considered as must be maintained approximately equal in each mode. continuous variables. Using nonlinear programming, To achieve this, a series connected, fault current limiter the optimal values of TMS and PS are obtained by the (FCL) is used for reducing the fault current magnitude modified firefly algorithm (MFA) [7], differential evolu - in the grid-connected mode during the fault period [19]. tion (DE) [8], gravitational search algorithm (GSA) [9], However, with the inclusion of an extra device, the pro- random search technique (RST) [10], teaching learning tection scheme becomes costly and complicated [20]. To based optimization (TLBO) [11], etc. To overcome the overcome this, a common optimum protection scheme problem of trapping in local minima, some hybrid tech- using conventional DOCR for both operating modes of niques consisting of two different optimization tech - microgrid is proposed in [21], where the combination of niques, such as gravitational search algorithm-sequential optimally selected standard relay characteristics is used. quadratic programming (GSA-SQP) [12], DE-LP [13], To further improve the performance in terms of the total biogeography-based optimization-linear program- relay operating time, dual setting DOCR is considered in ming (BBO-LP) [14], etc. have also been implemented place of conventional DOCR in this paper, and the com- to obtain the optimal values of TMS and PS. In contrast, mon setting is optimally determined for both operating for the MINLP technique [15], TMS and PS are consid- modes of the microgrid. The novelty of this work lies in ered continuous and discrete, respectively. To increase identifying common settings for dual setting relays in the flexibility in the coordination scheme, relay charac - both operating modes without using any external ele- teristic coefficients (α and β) have been introduced as ment or communication system. another decision variable. Thus, each relay is associated The protection scheme for the relay coordination prob - with four decision variables, i.e., TMS, PS, α and β, to fur- lem  formulated  in  this  paper  is an  MINLP because of ther reduce the total relay operating time as compared to the involvement of the third decision variable RCI. The fixed relay characteristics [16]. proposed protection scheme is tested on the 7-bus and Using the above-mentioned techniques, several coor- 18-bus microgrid systems. To show the effectiveness of dination schemes have been proposed for conventional dual setting DOCR, its performance is compared with and dual setting DOCR. Conventional DOCR operates the results obtained by conventional DOCRs [21]. The for the forward direction of the fault current, and hence remainder of the paper is divided into five sections as fol - there exists a single setting, used by DOCR for both lows. Section 2 describes problem formulation using dual primary and backup operations. Whereas, dual setting setting DOCRs, and the solution method is defined in DOCR can operate independently for both forward and Sect.  3. Section  4 provides a brief discussion of the test reverse directions, based upon which two different relay system and results, while validation of the proposed pro- settings (TMS , PS , and TMS , PS ), one for each tection scheme on a larger microgrid system is presented fow fow rev rev direction, are identified. For the forward direction, the in Sect. 5. Finally, the conclusion is given in Sect. 6. relay will act as the primary, and for the reverse direction, the same relay acts as backup protection in both operat- ing modes of the microgrid. [17] 2 Relay coordination problem formulation The fault current characteristics of inverter interface in a microgrid distribution generator (IIDGs) are completely different The operating time of overcurrent relay depends on its from those of the conventional rotating synchronous time–current characteristics, classified according to machine-based DGs (SBDGs). The fault current contri - IEC-60255 standard as normal inverse (NI), very inverse bution of SBDGs are 4–5 times that of the rated current, (VI), and extremely inverse (EI), as shown in Fig. 1. Each whereas, due to the limitation of inverter thermal over- relay characteristic is identified considering the respec - load capability, the fault current contribution of IIDGs is tive characteristic coefficients as shown in Table  1. From limited typically to about 1.2–2 times the rated current Fig.  1, it can be seen that, for a fixed fault current value, [18]. Therefore, overcurrent protection schemes may not the relay operating time is reduced as the relay charac- be significant in the islanded mode of operation consist - teristics change from NI to EI. The relay characteristics ing of only IIDGs. However, in the presence of multi- shown in Fig.  1 can be derived for different values of ple highly penetrated IIDGs along with SBDG, the total TMS and PS using (2) and (3). The objective of the pro - fault current contribution can still be significant for the posed work is to find optimum relay settings and reduce implementation of the overcurrent protection schemes. the overall operating time of dual setting DOCR for both Because of the fault current variation in grid-connected operating modes of the microgrid. and islanded modes of the microgrid, two different relay The objective function (OF) for relay coordination is for - settings are assigned. To obtain a common relay setting mulated as the summation of all primary relay operating T iwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 3 of 18 2.0 PS ≤ PS , PS ≤ PS min rev max fow (7) EI VI NI In (1), t is the operating time of the ith relay in the op_fow forward direction, and n is the number of primary relays 1.5 Reverse Direction Forward Direction for different fault locations. The relay operating times for TMS , PS . TMS , PS . rev rev fow fow forward and reverse directions of fault current are t op_fow and t respectively, as given in (2) and (3). The relay 1.0 op_rev, characteristic coefficients α and β are selected as per IEC- 60255 standard. TMS and TMS are the time multiplier fow rev 0.5 setting and PS and PS are the plug setting of relays fow rev operating in forward and reverse directions respectively. In (4), CTI is the coordination time interval, and its minimum -20-10 -5 05 10 20 value is 0.2 s. The maximum and minimum operating time Multiple of pickup current of relays (t and t ) are 4.0  s and 0.1  s, respec- op_max op_min Fig. 1 Time–current characteristics of a dual setting DOCR tively. Different kind of transients may exist in the power system for a time period of less than one microsecond to several milliseconds. In order to tackle all the transients in the system, the minimum relay operating time (0.1 s) is Table 1 Overcurrent relay characteristics coefficient, according also considered as a constraint to establish the overcurrent to IEC-60255 std relay coordination. Therefore, all transients vanish before Characteristic curve of relay α β Relay the operation of the primary relay. The lower and upper characteristics bound of TMS (TMS and TMS ) and PS (PS and min max min identifier (RCI) PS ) are 0.1, 1.1, 0.5, 2.0 respectively. max Very inverse ( VI) 13.5 1 1 Extremely inverse (EI) 80 2 2 3 Solution method for the relay coordination Normal inverse (NI) 0.14 0.02 3 problem The optimal coordination among the dual setting DOCRs can be achieved by obtaining the optimum values of relay settings, i.e., TMS , TMS , PS and PS , along with times for different fault locations shown in (1) and the fow rev fow, rev the optimal selection of relay characteristics RCI. The required constraints to fulfill the objective of the relay optimal values of all decision variables must be selected coordination problem are given from (4) to (7). to reduce the total relay operating time without any viola- tion of constraints. Thus, each relay is associated with twice OF = min t (1) op_fow the number of variables used in conventional DOCR. For i=1 the forward direction of fault current, the relay is associ- where ated with the forward settings (TMS , PS , and RCI) fow fow and for the reverse direction the same relay is associated α ∗ TMS fow with reverse settings (TMS , PS , and RCI). In this paper t = rev rev op_fow I (2) GA and GWO are used to obtain the values of all decision − 1 PS ∗CTR fow variables. The structure of the chromosome used in GA for dual setting DOCR is shown in Fig. 2. α ∗ TMS rev The proposed protection method using dual setting t = op_rev I (3) f DOCR for both operating modes of the microgrid is shown − 1 PS ∗CTR rev in Fig. 3. In the proposed protection scheme, the first step is to identify the operating mode of the microgrid, and then t − t ≥ CTI the three-phase midpoint fault current is measured at each op_rev op_fow (4) line using short circuit analysis. The relay pairs (primary t ≤ t ≤ t op_ min op_fow op_ max (5) Chromosome TMSfow1 ……. TMSfowm PSfow1 ……. PSfowm TMSrev1 ……. TMSrevn PSrev1 ……. PSrevn RCIfow1 ……. RCIfowm RCIrev1 ……. RCIrevn TMS ≤ TMS , TMS ≤ TMS min rev max fow (6) Fig. 2 Structure of chromosome in GA technique T( ime s) Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 4 of 18 Start Read the test system data Identify the operating mode of test system Grid-Connected or Islanded? Islanded Mode Grid-Connected Mode Modify the test system data according to Modify the test system data according islanded mode of operation to grid-connected mode of operation Identifying the P/B relay pairs for dual setting DOCR Formulation of objective function &Constraints for dual DOCR with different fault locations using NI,VI, EI and mix characterstics Define GA/GWO parameters and set an initial solution Apply GA/GWO to obtain optimum setting using dual setting DOCR All the Constraints are validated? NO YES Obtain the optimum relay setting with least total relay operating time End Fig. 3 Proposed protection method to determine optimal relay setting in grid connected and islanded operating mode and backup) for the different fault locations are identified in part of the IEEE-14 bus system (7-bus microgrid system), both operating modes. Furthermore, the summation of the as shown in Fig.  4, has two inverter-based DGs (IBDGs) operating times of all primary relays is taken as an objective each rated at 20 MVA, connected at buses B2 and B7, and function, and all the constraints related to CTI as well as one synchronous generator (SG) of 50 MVA at bus B1. minimum and maximum relay operating times are formu- The 7-bus microgrid system is connected with the sub- lated. After the determination of GA/GWO parameters, transmission network through buses B3 and B6 each hav- the optimum settings of relays are obtained. If the obtained ing 60 MVA generation capacity. Buses B1, B2, B3, and values satisfy all the constraints for both operating modes, B6 have a maximum short circuit capacity of 250 MVA, they are considered as the final optimal relay settings. 80 MVA, 300 MVA, and 300 MVA, respectively. All other However, in the case where there is any violation of con- specifications of the test system can be obtained from straints, the values of GA/GWO parameters are updated [22]. The 7-bus microgrid test system consists of 8 lines, and the process continues until the final optimal relay set - which are protected by 16 dual setting DOCRs placed ting is obtained without any violation of relay constraints. at both ends of the lines. The CT ratios (CTR) used for dual setting DOCRs are given in Table  2. The fault cur - 4 Test system description and results rent magnitudes through each relay coil for different fault In this paper, for both test systems considered (distri- locations in both operating modes of the microgrid are bution parts of the IEEE-14 and IEEE-30 bus test sys- shown in Table  3. For eight different fault locations (L1, tems), multiple IIDGs are used along with one SBDG L2, L8), there are twenty-two relay pairs (RP1-RP22). and a utility grid. Therefore, the total fault current in For relay pair RP1, R1 and R3 will act as the primary and grid connected mode is shared by all the considered backup dual setting DOCR, respectively. The fault cur - active sources of IIDGs, SBDG and the utility grid. In rent via the primary and backup relay coils in grid-con- the islanded mode of operation, the total fault current is nected and islanded operating modes are 12.075A (R1), shared by multiple IIDGs and the SBDG. The distribution 3.19A (R3), 9.03A (R1), and 0.64A (R3), respectively. T iwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 5 of 18 direction is higher than the reverse direction, which justi- IBDG SG IBDG fies the need of dual setting relays. B1 B2 B7 R16 R5 R2 R6 R1 R7 L3 L1 R3 4.1 Optimum relay setting in grid‑connected mode The settings of the optimal dual setting DOCR obtained L2 by GA in the grid-connected mode of operation, using L8 L4 NI, VI, EI and mixed relay characteristics, are shown in Table  4. The total operating times of all dual setting L7 L6 L5 DOCRs with NI and VI characteristics are found to be R4 3.3877  s and 1.6825  s, respectively. From the results, R15 R13 R12 R11 R10 R9 R8 R14 it can be seen that by using VI characteristics the over- B6 B4 B3 B5 all relay operating time can be reduced by up to 50.33% when compared to NI characteristics. From the obtained optimal settings, it can be seen that for NI characteris- tics, the operating time of R1 in RP1 is 0.2146  s for the forward direction, whereas for the reverse direction the Fig. 4 Distribution part of IEEE-14 bus test system with dual setting operating time of R1 in RP4 is 2.049  s. Thus, the relay DOCR operating time for the forward direction of fault cur- rent is lower than the reverse direction. This statement is valid for all the dual setting DOCRs with NI, VI, EI, and Table 2 CT ratios of DOCR for 7-bus microgrid system mixed characteristics in grid-connected mode. Similarly, the results obtained using EI relay characteristics and a Relay CT ratio combination of optimally selected relay characteristics 1 2000/5 (mixed-characteristics) in grid-connected mode show 2 1000/5 that the total operating times of dual setting DOCRs with 3 3000/5 EI and mixed characteristics are 1.6124  s and 1.6065  s, 4 2000/5 respectively. Thus, there is a reduction of 0.36% in total 5 1600/5 relay operating time using mixed characteristics as com- 6 1000/5 pared to EI characteristics. In addition, it can be seen that 7 2500/5 by using mixed characteristics the total relay operating 8 1600/5 time is reduced by 52.57% and 4.51% as compared to NI 9 2500/5 and VI characteristics, respectively. From the results, it 10 1200/5 can be concluded that by using optimally selected relay 11 1200/5 characteristics the total relay operating time is the least 12 2500/5 when compared to NI, VI, EI characteristics. Also only 13 800/5 VI and EI characteristics are optimally selected in mixed 14 3000/5 characteristics. A graphical representation of the primary 15 1600/5 relay operating times obtained by GA with NI, VI, EI, and 16 1600/5 mixed characteristics in grid-connected mode using dual setting DOCR is shown in Fig.  5. The MCT and backup relay operating times for dual setting DOCR obtained It can be seen from the short circuit analysis that the by GA in grid-connected mode of the 7-bus microgrid fault current magnitude in grid-connected mode is higher system are presented in Figs.  6 and 7, respectively. Here than in the islanded mode of operation. Consequently, MCT can be defined as the actual operating time differ - it is possible that DOCRs with NI relay characteristics ence between the primary and backup relays using opti- may take a long time to operate. This is not desirable as mal values of TMS and PS. In all cases, the value of MCT it may lead to mis-coordination of relay pairs, potentially is always greater than CTI. This indicates the required resulting in a larger portion of the system being isolated. time gap between primary and backup relays for each RP. To avoid this situation, relay characteristic curves have The optimal results satisfy all the considered constraints been optimally selected by including a third optimization while formulating the relay coordination problem. variable known as a relay characteristics identifier (RCI). Besides this, the fault current magnitude in the forward Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 6 of 18 Table 3 Current through relay coils in grid-connected and islanded operating modes for 7-bus microgrid system Faulty line Relay pair Primary relay Backup relay Fault current through relay coils (dual) Grid‑ connected (A) Islanded mode (A) Primary Backup Primary Backup L1 RP1 R1 R3 12.075 3.19 9.03 0.64 RP2 R1 R5 12.075 2.53 9.03 1.76 RP3 R2 R7 17.175 4.13 11.52 1.45 L2 RP4 R3 R1 9.561 4.10 8.07 2.39 RP5 R3 R5 9.561 2.16 8.07 1.04 RP6 R4 R14 16.075 2.64 5.35 1.59 RP7 R4 R15 16.075 1.69 5.35 3.30 L3 RP8 R5 R1 17.196 3.27 12.4 2.32 RP9 R5 R3 17.196 2.67 12.4 0.538 RP10 R6 R16 16.785 6.18 11.72 2.60 L4 RP11 R7 R2 7.038 9.94 6.174 7.34 RP12 R8 R9 16.793 2.34 6.134 2.80 L5 RP13 R9 R8 16.038 6.08 5.356 6.52 RP14 R10 R11 11.634 10.86 8.65 7.85 L6 RP15 R11 R10 19.90 19.37 9.154 8.36 RP16 R12 R13 7.18 22.15 4.94 15.11 L7 RP17 R13 R12 18.28 5.75 9.675 2.97 RP18 R14 R4 11.04 5.51 6.43 6.37 RP19 R14 R15 11.04 3.012 6.43 3.66 L8 RP20 R15 R4 17.728 3.047 9.52 5.22 RP21 R15 R14 17.728 2.075 9.52 1.435 RP22 R16 R6 9.734 9.145 8.14 6.165 4.2 O ptimum relay setting in islanded mode by GA is reduced by 59% and 7.99% compared to NI and The optimal settings obtained by GA in islanded mode VI characteristics, respectively. It can be concluded that using dual setting DOCR, with NI, VI, EI and mixed relay by using optimally selected relay characteristics the relay characteristics are shown in Table  5. It is found that the operating time is lower than all the other (NI, VI, and EI) total operating times of relays obtained by GA using NI characteristics. In the islanded mode of operation, only and VI characteristics are 3.9882  s and 1.7765  s, respec- VI and EI type relay characteristics are optimally selected tively. It can be seen that using VI characteristics, the in the case of mixed characteristics. The primary dual total relay operating time obtained by GA can be mini- setting DOCR operating times obtained by GA using NI, mized by 55.45% when compared to NI characteristics. VI, EI and mixed characteristics in islanded operating Also, the operating time for relay R1 in RP1 is 0.2350  s mode are shown in Fig. 8. for the forward direction whereas for the reverse direc- tion of fault current the operating time of relay R1 in 4.3 Comparative analysis of results in dual operating RP4 is 1.6779  s (with NI characteristics). Thus the relay mode operating time for the forward direction is lower than The performance of dual setting DOCR in terms of the that of the reverse direction. Similarly, from the results total relay operating time is compared with conven- obtained by GA using EI and mixed relay characteristics tional DOCR [20], in Table  6. It can be seen that, as in islanded mode, the total dual setting DOCR operat- the relay characteristics change from NI to optimally ing times obtained by GA using EI and mixed charac- selected mixed characteristics, there is a significant teristics are 1.6928  s and 1.6345  s respectively. By using reduction in the relay operating time in both operating mixed characteristics, the relay operating time obtained modes of the microgrid. To validate the effectiveness of T iwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 7 of 18 Table 4 Optimal relay setting with NI, VI, EI and mixed relay characteristics for dual setting DOCR in grid-connected mode Relay NI relay characteristics VI relay characteristics EI relay characteristics Mixed relay characteristics RCI Forward Reverse Forward Reverse Forward Reverse Forward Reverse TMS PS TMS PS TMS PS TMS PS TMS PS TMS PS TMS PS TMS PS R1 0.1 0.5121 0.9624 0.5 0.1664 0.5127 1.1 0.6921 0.1631 1.0575 1.1 1.980 0.7210 0.5 0.1156 1.7939 2 R2 0.1 0.5 0.9838 1.8298 0.1014 1.1690 1.1 2 1.1 0.5848 1.1 1.9954 0.1579 1.5166 1.1 1.9999 2 R3 0.1 0.5 0.7723 0.7037 0.1289 0.5145 0.4245 1.097 0.4819 0.5 1.1 1.9986 0.3517 0.5673 0.4377 0.6875 2 R4 0.1002 0.5 0.3553 1.6428 0.1 1.1015 1.0171 0.5 1.0843 0.5433 1.0965 2 1.0824 0.5433 0.1539 1.3230 2 R5 0.1 0.5 0.6815 0.5001 0.1736 0.6995 0.1156 1.5592 0.5740 0.8006 1.1 2 0.4359 0.9163 0.5404 0.5011 2 R6 0.1 0.5 0.8508 0.8232 0.1572 0.7579 1.0591 1.9992 1.0277 0.5821 1.1 2 0.5267 0.8171 1.1 1.9065 2 R7 0.1 0.5 1.1 0.6261 0.1040 0.5 1.1 0.8780 0.2207 0.5402 1.1 2 0.2347 0.5107 1.1 0.8577 2 R8 0.1 0.8808 1.1 0.9211 0.1948 0.6102 1.1 1.2910 0.2753 1.1354 1.1 1.9940 1.0746 0.5699 1.1 1.2693 2 R9 0.1 0.5 0.2334 1.5578 0.2293 0.5 0.1625 1.5080 0.975 0.5766 1.1 2 0.1 1.7735 0.1 1.0914 2 R10 0.1 0.5644 1.1 2 0.1073 0.7490 1.1 1.9999 0.6700 0.5 1.1 1.9846 0.6703 0.5 1.0999 1.9966 2 R11 0.1 0.5 1.1 1.6436 0.1874 0.75 1.0945 1.3768 0.2089 1.5295 0.9944 1.9579 1.0363 0.6902 1.0999 2 2 R12 0.1 0.5 1.1 0.8664 0.1064 0.5 0.3895 1.6736 0.1124 0.75 1.0245 2 0.1006 0.7924 0.8604 1.0015 2 R13 0.1 0.5 1.1 2 0.2679 0.5 1.1 2 0.2875 1.2163 1.0849 1.9933 0.9133 0.6726 1.1 1.9999 2 R14 0.1 0.5082 0.1483 0.5 0.2666 0.5 0.1046 1.5332 0.6012 0.5028 1.0994 1.9357 0.3895 0.6214 0.1014 0.5063 2 R15 0.1 0.5 0.108 0.5136 0.2533 0.5 0.3810 0.5 0.1604 1.5536 1.1 1.6875 0.1720 1.5085 0.1666 0.7099 2 R16 0.1 0.5 1.1 0.9336 0.1371 0.5 1.0810 0.7936 0.1 1.0781 1.0957 1.9354 0.1200 0.5625 0.6290 1.25 1 T 3.3877 (s) 1.6825 (s) 1.6124 (s) 1.6065 (s) op Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 8 of 18 Fig. 5 Primary relay operating time having NI, VI, EI and mixed characteristics in grid-connected mode Fig. 6 MCT having NI, VI, and EI and mixed characteristics using dual setting DOCR in grid-connected mode Fig. 7 Backup relay operating time having NI, VI, EI and mixed characteristics in grid- connected mode T iwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 9 of 18 Table 5 Optimal relay setting with NI, VI, EI and mixed relay characteristics for dual setting DOCR in islanded mode Relay NI relay characteristics VI relay characteristics EI relay characteristics Mixed relay characteristics RCI Forward Reverse Forward Reverse Forward Reverse Forward Reverse TMS PS TMS PS TMS PS TMS PS TMS PS TMS PS TMS PS TMS PS R1 0.1 0.5 0.3990 1.7560 0.1 0.6179 0.8838 1.0268 0.1 1.1507 0.6248 1.6556 0.4037 0.5 0.8180 1.5353 2 R2 0.1 0.5 1.1 1.9999 0.1 0.7874 1.1 2 0.5490 0.5543 1.1 1.9860 0.6568 0.5 1.1 2 2 R3 0.1001 0.5107 0.1 0.5 0.1110 0.5 0.1 0.5 0.1 0.9322 0.1036 0.5 0.1499 0.7313 0.1 0.5 2 R4 0.1 0.5 1.1 2 0.1 0.5001 1.1 1.9994 0.1361 0.5150 1.1 1.9989 0.1 0.5 1.0999 1.9999 1 R5 0.1001 0.5 0.8837 0.5627 0.1746 0.5 0.2198 0.8933 0.1296 1.2249 0.1773 0.8465 0.3070 0.7862 0.4373 0.7167 2 R6 0.1 0.5023 1.1 2 0.1078 0.7464 1.1 2 0.2603 0.8131 1.1 1.9987 0.1082 0.7492 1.1 2 1 R7 0.1 0.5033 0.2640 1.0202 0.1 0.5 1.0687 0.5626 0.1 0.75 0.9422 0.75 0.1693 0.5258 1.1 0.6901 2 R8 0.1 0.5 1.0332 1.6895 0.1 0.5 1.1 2 0.1707 0.5212 1.1 1.9033 0.1690 0.5230 1.1 2 2 R9 0.1 0.5 0.9751 0.7813 0.1001 0.5 0.4204 1.7383 0.1 0.6063 1.1 1.6982 0.1421 0.5 0.5146 1.7406 2 R10 0.1 0.5 1.0968 1.9100 0.1126 0.5286 1.1 1.9979 0.3576 0.5108 1.1 1.9918 0.3705 0.5 1.1 2 2 R11 0.1 0.5 1.0970 2 0.1269 0.5 1.1 2 0.1779 0.7685 1.0928 1.9973 0.3679 0.53 1.1 2 2 R12 0.1001 0.5 0.8712 1.6211 0.1 0.5 0.9056 1.7699 0.1173 0.5078 0.7916 1.9945 0.1284 0.5 0.9226 1.5083 2 R13 0.1 0.5 1.1 2 0.1346 0.5 1.1 2 0.4711 0.5079 1.1 2 0.3753 0.5548 1.1 2 2 R14 0.1 0.5 0.1 0.7615 0.1 0.5128 0.3620 0.9708 0.1970 0.5121 0.9614 0.75 0.1 0.7111 0.9115 0.7626 2 R15 0.1 0.5 1.1 1.5384 0.1315 0.5026 0.8687 2 0.4680 0.5 1.1 1.3455 0.4483 0.5 1.1 1.6245 2 R16 0.1 0.5 0.3807 2 0.1121 0.5 0.9770 1.0648 0.3744 0.5 0.6468 1.45 0.1999 0.6384 1.0960 1.2421 2 T 3.9882 (s) 1.7765 (s) 1.6928 (s) 1.6345 (s) op Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 10 of 18 Fig. 8 Primary relay operating time having NI, VI, EI and mixed characteristics in islanded mode Table 6 Comparative analysis of conventional DOCR [20] and dual setting DOCR for 7-bus microgrid system Operating Relay Conventional Dual DOCR Conventional Dual DOCR Reduction Reduction mode characteristics DOCR operating operating time DOCR operating time in total relay in total relay time (s) using (s) using GA operating time (s) using GWO operating time operating time GA [20] (s) using GWO using GA using GWO Grid-connected NI 7.2041 3.3877 7.2453 3.4045 52.97% 53.01% VI 2.4392 1.6825 2.5482 1.7402 31.02% 31.70% EI 1.6681 1.6124 1.7053 1.6139 3.39% 5.35% Mixed 1.6684 1.6065 1.6868 1.6103 3.71% 4.53% Islanded NI 7.3148 3.9882 7.4868 3.9918 45.47% 46.68% VI 3.2457 1.7765 3.3625 1.7885 45.26% 46.81% EI 6.7142 1.6928 2.0911 1.7258 74.78% 17.46 Mixed 2.0670 1.6345 2.0888 1.6459 20.92% 21.20% Table 7 Coordination constraint violation summary of the 7-bus microgrid system using GA Setting calculated Characteristics curve Constraint violation in conventional DOCR Constraint violation in dual considered [20] setting DOCR Islanded Grid‑ connected Islanded Grid‑ connected Islanded NI NIL 13 NIL 01 VI NIL 14 NIL 16 EI NIL 5 NIL 17 Mixed NIL 12 NIL 16 Grid-connected NI 08 NIL 04 NIL VI 07 NIL 04 NIL EI 04 NIL 07 NIL Mixed 06 NIL 05 NIL T iwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 11 of 18 Load Test System Data for grid connected and islanded the common optimal relay setting for dual setting mode of operation of microgrid DOCRs. In this process, all the relay constraints of Identification of microgrid operating mode both operating modes are considered together when minimizing the objective function. The common opti- Measurement of three phase mid point fault mal relay settings obtained by GA with the optimally current selected relay characteristics are shown in Table  8. Identifying the P/B relay pairs for dual setting DOCR The primary relay operating times obtained by GA Formulation of objective function for dual setting using conventional and dual setting overcurrent relays DOCR with different fault locations are displayed in Fig.  10. In this case, the number of Combine relay constraints of grid connected and relays remains the same, but the number of relay con- islanded mode using dual setting DOCR straint, and relay pairs, are doubled (RP1-RP44) com- Define GA/GWO parameters and set an initial pared to grid-connected or islanded operating mode solution (RP1-RP22). The results reveal that for the obtained Apply GA/GWO to obtain optimum common setting common relay settings, all three types of relay char- using dual setting DOCR acteristics, i.e., NI, VI, and EI, are optimally deter- Obtain the common optimum relay setting with least mined. The total relay operating times obtained by total relay operating time GA are found to be 1.6800  s for dual setting DOCR Fig. 9 Method for common optimal setting for dual operating modes of MG and 2.4392  s for conventional DOCR [20]. This rep- resents a reduction of 31.12% while using dual setting relays with the common optimal settings, while the constraints in both operating modes are completely GA, the results are also compared with the grey wolf satisfied, i.e., no constraint violation occurs for either optimization (GWO) technique. The results show that of the operating modes. GA gives better results in terms of total relay operat- ing time in all cases except the islanded case of conven- 5 Proposed protection scheme validation tional DOCR using EI characteristics. The percentage on 18‑bus microgrid system reduction in operating time of dual-setting DOCRs To validate the effectiveness of the proposed protec- compared to conventional DOCR in each case is shown tion scheme, the proposed protection method imple- in Table  6. The violation constraints (in terms of num - mented on the distribution part of the IEEE-14 bus ber) in both operating modes of the microgrid are dis- test system is applied in a similar manner to a larger played in Table  7, while any protection schemes are no microgrid system, i.e., the distribution part of the longer valid if any of the constraints associated with the IEEE-30 bus test system (an 18-bus microgrid system) relay coordination problem are violated. It is seen that is considered. The 18-bus microgrid system consists when the optimal settings obtained for grid-connected of 22 lines, one SG (50MVA) connected at bus B1, and mode (for dual setting DOCRs) are applied in islanded three IBDG (20 MVA each) at buses B4, B11, and B18 mode, several constraints are violated (4 for NI, 4 for [20]. The other relevant information regarding the VI, 7 for EI and 5 for mixed characteristics). In the IEEE-30 bus system is given in “Appendix”. To pro- same way when the optimal relay settings of islanded tect this system, 44 dual setting relays (R1–R44) are mode are applied in grid-connected mode, some con- required. These are placed at both ends of the lines as straints are violated (1 for NI, 16 for VI, 17 for EI and 16 shown in Fig. 11. The system is connected to the utility for mixed characteristics). Therefore, it is desirable to grid through buses B1, B2 and B16 as shown in Fig. 11. obtain a common relay setting for the operation of the The primary-backup relay pairs (RP1–RP72) for dif- protection scheme, one which can satisfy all the operat- ferent fault locations (L1–L22) are shown in Table  9. ing mode constraints. In this test system, for some of the relay pairs, the fault currents flowing through the respective backup 4.4 C ommon optimum relay setting in dual operating relays are very small compared to the primary relays modes of microgrid because the backup relay operating times are larger The proposed method for a common optimal setting than those of the primary relays. Such relay pairs are that can be used in both operating modes is shown ignored during the relay coordination process, as they in Fig.  9, where the effects of both operating modes always satisfy the respective constraints. All other of the microgrid are taken into account, to identify test system information is taken from [22]. To show Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 12 of 18 Table 8 Common optimal relay setting using dual setting DOCR for 7-bus microgrid system Relay Forward Reverse RCI Relay Forward Reverse RCI TMS PS TMS PS TMS PS TMS PS R1 0.5071 0.595 0.1000 0.816 2 R9 0.2205 0.516 0.610 0.500 1 R2 0.6757 0.734 0.9420 1.649 2 R10 0.6688 0.500 1.1000 1.744 2 R3 0.1329 0.500 0.1188 0.500 1 R11 0.2159 1.502 1.1000 1.638 2 R4 0.1000 0.500 0.3501 1.657 3 R12 0.2540 0.500 1.0990 0.531 2 R5 0.7841 0.682 0.1626 0.504 2 R13 0.1614 1.594 1.1000 2.000 2 R6 0.1000 1.146 0.9213 1.500 1 R14 0.6022 0.500 0.1000 0.572 2 R7 0.2440 0.500 0.1610 0.622 2 R15 0.1000 1.211 0.2417 0.500 1 R8 0.2390 0.5000 1.1000 1.2920 1 R16 0.1333 0.5075 0.1475 0.8044 1 Top 1.68 (s) Fig. 10 Primary relay operating time using single and dual setting DOCR for common relay setting the efficacy of the proposed protection scheme for shown in Table  10. From Table  10, it can be seen that the 18-bus microgrid system, only the common oper- the total primary relay operating time obtained by GA ating mode is considered due to page limitations. To for dual setting overcurrent relays, is 4.4472  s, which determine the common optimal relay settings which is 60.47% lower than that for conventional DOCRs can be used in both operating modes, the impacts of [20] as shown in Table 11. The primary relay operating both operating modes are considered simultaneously. times for all the relay pairs (RP1–RP144) associated Therefore, the number of constraints is doubled com- with grid-connected mode (RP1–RP72) and islanded pared to those in the individual operating mode. The mode (RP73–RP144) using single and dual setting minimum and maximum values of TMS, PS, and pri- overcurrent relays in common operating mode are mary relay operating time are considered the same as shown in Fig. 12. in the 7-bus microgrid system. The common optimal It can be concluded that the common optimal relay set- relay settings for the 18-bus microgrid system using tings satisfy all the constraints related to grid-connected dual-setting overcurrent relays, obtained by GA are and islanded mode of operation simultaneously. Thus, T iwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 13 of 18 B17 R43 R40 L22 L20 IBDG R44 R39 B18 R42 R41 L21 B16 R38 L19 R37 R35 R36 L17 L18 R34 B15 B14 B12 R33 B13 L10 IBDG R19 R20 R31 R32 R30 L16 B4 L15 R16 R12 R17 R29 IBDG R28 L8 B7 B8 L14 B11 R25 R15 R18 R23 R24 R8 L9 L12 L13 R27 R26 B1 B10 L6 B3 R10 R4 R6 L4 L5 L2 L3 L7 L11 L1 R9 R11 R13 R14 R21 R22 R2 R1 R3 R5 R7 B5 B6 B2 B1 SG Fig. 11 Distribution part of IEEE-30 bus system (18-bus microgrid system) the proposed protection scheme using dual-setting over- is the determination of common settings of dual set- current relays also provides the common optimal relay ting relays for both operating modes of the microgrid. settings for larger test system such as the 18-bus micro- From the results, it can be concluded that the relay grid test system which can be used in both operating operating times in both modes decrease significantly modes. To show the efficacy of the GA, a comparative as the relay characteristics change. In this context, analysis in terms of total relay operating time for both for the 7-bus microgrid system, 16 dual-setting relays test systems (the 7-bus and 18-bus microgrid systems) is (R1–R16) have been considered with NI, VI, EI and shown in Table 11. It can be seen there that the total relay mixed characteristics by which the total relay operat- operating times obtained by the GA are better than the ing times are reduced by 52.97%, 31.02%, 3.39% and GWO for both test cases. In addition, the total primary 3.71% in grid-connected mode, and by 45.47%, 45.26%, relay operating time in the common operating mode 74.78% and 20.92% in islanded mode as compared using dual setting DOCR is always lower than the con- to conventional DOCR. Also, in common operating ventional DOCR [20]. mode, the percentage reductions in total relay operat- ing time for dual setting DOCR obtained by GA in the 6 Conclusion 7-bus and 18-bus microgrid systems are 31.02% and This paper presents a comparative analysis of relay 60.47% respectively, compared to the conventional coordination for 7-bus and 18-bus microgrid systems DOCR. Similarly, the percentage reductions in total using dual-setting relays in both operating modes of a relay operating time for dual-setting DOCR obtained microgrid. One of the major findings of the research by GWO in the 7-bus and 18-bus microgrid systems Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 14 of 18 Table 9 Primary-Backup relay pair for different fault locations in 18 bus microgrid system Fault location Relay pair (RP) Primary relay Backup Fault location Relay pair (RP) Primary relay Backup Fault location Relay pair (RP) Primary relay Backup relay relay relay (dual) (dual) (dual) L1 RP1 R1 R3 L7 RP26 R13 R9 L15 RP51 R29 R28 RP2 R1 R5 RP27 R13 R11 RP52 R30 R32 RP3 R1 R7 RP28 R14 R21 RP53 R30 R33 RP4 R2 R22 L8 RP29 R15 R10 L16 RP54 R31 R20 L2 RP5 R3 R1 RP30 R16 R12 RP55 R32 R30 RP6 R3 R5 RP31 R16 R17 RP56 R32 R33 RP7 R3 R7 RP32 R16 R19 L17 RP57 R33 R30 RP8 R4 R26 L9 RP33 R17 R12 RP58 R33 R32 L3 RP9 R5 R1 RP34 R17 R16 RP59 R34 R37 RP10 R5 R3 RP35 R17 R19 L18 RP60 R35 R34 RP11 R5 R7 RP36 R18 R23 RP61 R35 R37 RP12 R6 R27 L10 RP37 R19 R12 L19 RP62 R37 R34 L4 RP13 R7 R1 RP38 R19 R16 RP63 R38 R39 RP14 R7 R3 RP39 R19 R17 RP64 R38 R41 RP15 R7 R5 RP40 R20 R31 L20 RP65 R39 R38 RP16 R8 R28 L11 RP41 R21 R14 RP66 R39 R41 RP17 R8 R29 RP42 R22 R2 RP67 R40 R43 L5 RP18 R9 R11 L12 RP43 R23 R18 L21 RP68 R41 R38 RP19 R9 R13 RP44 R24 R25 RP69 R41 R39 RP20 R10 R15 L13 RP45 R25 R24 RP70 R42 R44 L6 RP21 R11 R9 RP46 R26 R4 L22 RP71 R43 R40 RP22 R11 R13 L14 RP47 R27 R6 RP72 R44 R42 RP23 R12 R16 RP48 R28 R8 RP24 R12 R17 RP49 R28 R29 RP25 R12 R19 RP50 R29 R8 T iwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 15 of 18 Table 10 Optimal relay setting for common operating mode in 18 bus microgrid system using GA Relay RCI Forward Reverse Relay RCI Forward Reverse TMS PS TMS PS TMS PS TMS PS 1 2 0.2909 1.1371 1.1000 1.9998 23 1 0.2277 0.5167 1.1000 1.9998 2 2 0.1 1.7002 0.4104 0.5510 24 2 0.4351 0.9222 1.1000 1.0659 3 2 0.1477 1.7122 1.1000 2.0000 25 2 0.1581 1.5164 1.1000 0.6721 4 2 1.0844 0.5740 0.7170 0.5913 26 2 0.5009 0.6876 1.1000 2.0000 5 2 0.8237 0.7349 1.1000 2.0000 27 2 0.4578 0.9954 1.0751 1.9645 6 1 0.2503 0.5144 1.0034 0.7500 28 2 0.1000 1.9102 1.1000 2.0000 7 2 0.6753 0.7578 1.1000 2.0000 29 2 0.5285 0.7757 1.1000 1.9953 8 2 0.2382 1.1168 1.1000 1.6350 30 2 0.4732 0.8708 1.0933 1.9979 9 2 0.5338 0.8283 1.1000 2.0000 31 2 0.4841 0.9310 0.9246 1.4508 10 2 1.0805 0.5953 1.1000 0.5156 32 2 0.1660 1.5015 1.1000 2.0000 11 1 0.2643 0.5162 1.1000 1.1119 33 2 0.7823 0.7869 1.1000 2.0000 12 2 0.2656 1.3253 1.1000 2.0000 34 2 1.0812 0.5786 1.1000 1.9987 13 2 1.0956 0.6344 1.1000 1.8827 35 2 0.3466 1.0587 1.1000 1.2698 14 2 0.8333 0.6044 1.1000 2.0000 36 2 0.2712 0.5864 1.1000 0.7618 15 2 0.3386 1.1727 0.1061 0.5050 37 2 0.2140 1.5094 0.1841 1.3251 16 2 1.0961 0.5312 1.1000 2.0000 38 1 0.2141 0.5218 1.1000 1.9983 17 2 0.1610 1.5053 1.1000 2.0000 39 2 0.3391 1.1641 1.1000 2.0000 18 2 1.0198 0.6835 1.1000 1.9844 40 2 1.0323 0.6713 1.1000 2.0000 19 2 0.3944 0.9916 1.1000 1.9985 41 2 1.0477 0.6434 1.1000 1.9999 20 2 0.9609 0.5456 1.0377 1.3120 42 3 0.1001 0.5000 1.1000 2.0000 21 2 0.5839 0.7671 1.0999 2.0000 43 2 1.0830 0.5672 1.1000 0.8326 22 2 0.2362 1.2411 1.1000 2.0000 44 2 0.9623 0.6789 1.1000 2.0000 T 4.4472 (s) op Table 11 Summary of total relay operating time using single and dual setting overcurrent relays in common operating mode Sr. nos Test system Optimization Total relay operating time (s) Percentage reduction in technique total relay operating time Conventional DOCR Dual setting DOCR 1 7 Bus microgrid GA [20] 2.4392 1.6800 31.12% GWO 2.4412 1.7028 30.24% 2 18 Bus microgrid GA [20] 11.2509 4.4472 60.47% GWO 7.0393 4.5780 34.96% are 30.24% and 34.96% respectively when compared to The performance of the proposed protection scheme conventional DOCR. One of the major advantages of can be further enhanced by taking the relay character- the proposed technique is that there is no constraints istic coefficients (α and β) as continuous variables. violation in either operating mode of the microgrid. Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 16 of 18 2.2 Single Setting-Primary Relay 2.0 Dual Setting-Primary Relay 1.8 1.6 1.4 1.2 1.0 0.8 0.6 0.4 0.2 20 40 60 80 100 120 140 Relay Pair (RP) Fig.12 Primary relay operating time using single and dual setting overcurrent relays for common relay setting in 18 bus microgrid test system Appendix See Tables 12, 13 and 14. Table 12 Bus load and injection data of IEEE 30-bus system Table 13 Reactive power limit of IEEE-30 bus test system Bus Load Bus Load Bus Qmin (p.u.) Qmax (p.u.) Bus Qmin (p.u.) Qmax (p.u.) 1 0.0 16 3.5 1 − 0.2 0.0 16 2 21.7 17 9.0 2 − 0.2 0.2 17 − 0.05 0.05 3 18 0.0 0.055 3 2.4 18 3.2 4 19 4 67.6 19 9.5 5 − 0.15 0.15 20 5 34.2 20 2.2 6 0.0 21 17.5 6 21 7 22.8 22 0.0 7 22 8 30.0 23 3.2 8 − 0.15 0.15 23 − 0.05 0.055 9 0.0 24 8.7 9 24 10 5.8 25 0.0 10 25 11 0.0 26 3.5 11 − 0.1 0.1 26 12 11.2 27 0.0 12 27 − 0.055 0.055 13 − 0.15 0.15 28 13 0.0 28 0.0 14 29 14 6.2 29 2.4 15 30 15 8.2 30 10.6 Operating Time (s) T iwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 17 of 18 Table 14 Line parameter of IEEE-30 bus test system Line From bus To bus /t (p.u.) I (p.u) Tap ratio Rating (p.u) 1 1 2 0.0192 0.0575 0.300 2 1 3 0.0452 0.1832 0.9610 0.300 3 2 4 0.0570 0.1737 0.9560 0.300 4 3 4 0.0132 0.0379 0.300 5 2 5 0.0472 0.1983 0.300 6 2 6 0.0581 0.1763 0.300 7 4 6 0.0119 0.0414 0.300 8 5 7 0.0460 0.1160 0.300 9 6 7 0.0267 0.0820 0.300 10 6 8 0.0120 0.0420 0.300 11 6 9 0.0000 0.2080 0.300 12 6 10 0.0000 0.5560 0.300 13 9 11 0.0000 0.2080 0.300 14 9 10 0.0000 0.1100 0.9700 0.300 15 4 12 0.0000 0.2560 0.9650 0.650 16 12 13 0.0000 0.1400 0.9635 0.650 17 12 14 0.1231 0.2559 0.320 18 12 15 0.0662 0.1304 0.320 19 12 16 0.0945 0.1987 0.320 20 14 15 0.2210 0.1997 0.160 21 16 17 0.0824 0.1932 0.160 22 15 18 0.1070 0.2185 0.160 23 18 19 0.0639 0.1292 0.9590 0.160 24 19 20 0.0340 0.0680 0.320 25 10 20 0.0936 0.2090 0.320 26 10 17 0.0324 0.0845 0.9850 0.320 27 10 21 0.0348 0.0749 0.300 28 10 22 0.0727 0.1499 0.300 29 21 22 0.0116 0.0236 0.300 30 15 23 0.1000 0.2020 0.160 31 22 24 0.1150 0.1790 0.300 32 23 24 0.1320 0.2700 0.9655 0.160 33 24 25 0.1885 0.3292 0.300 34 25 26 0.2544 0.3800 0.300 35 25 27 0.1093 0.2087 0.300 36 28 27 0.0000 0.3960 0.300 37 27 29 0.2198 0.4153 0.9810 0.300 38 27 30 0.3202 0.6027 0.300 39 29 30 0.2399 0.4533 0.300 40 8 28 0.0636 0.2000 0.9530 0.300 41 6 28 0.0169 0.0599 0.300 Abbreviations Acknowledgements DOCR: Directional overcurrent relay; TMS: Time multiplier setting; PS: Plug Not applicable. setting; RCI: Relay characteristics identifier; CTI: Coordination time interval; CTR : Current transformer ratio; RP: Relay pair; OF: Objective function; NI: Authors’ contributions Normal inverse; VI: Very inverse; EI: Extremely inverse; IIDG: Inverter interface RT carried out problem formulation, simulation, calculations, preparing manu- distributed generator; SBDG: Synchronous based distributed generator; CCM: script, RKS and NKC participated in problem conceptualization, coordination Current control mode; VCM: Voltage control mode; GA:: Genetic algorithm; and helped to draft manuscript. All authors read and approved the final GWO: Grey wolf optimization. manuscript. Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 18 of 18 Authors’ information with DG penetration. IEEE Transactions on Industry Applications, 54(2), Mr. Raghvendra Tiwari is Research Scholar pursuing his PhD in Electrical Engg. 1155–1165. https:// doi. org/ 10. 1109/ TIA. 2017. 27730 18 from Motilal Nehru National Institute of Technology (MNNIT ) Allahabad, Praya- 10. Birla, D., Maheshwari, R. P., Gupta, H. O., Deep, K., & Thakur, M. (2006). graj (U.P), India., he graduated (2007) and post graduated (2013) in Electrical Application of random search technique in directional overcurrent relay Engg. From National Institute of Technical Teachers Training and Research coordination. International Journal of Emerging Electric Power Systems, 7(1), (NITTTR), Chandigarh (Haryana). His areas of interest include Power system 1–16. https:// doi. org/ 10. 2202/ 1553- 779X. 1271 analysis, power system protection and artificial intelligence. 11. Singh, M., Panigrahi, B. K., & Abhyankar, A. R. (2013). Optimal coordination Prof. Ravindra Kumar Singh is presently working as a Professor (H.A.G) in Dept of directional over-current relays using teaching learning-based optimiza- of Electrical Engg., MNNIT Allahabad, Prayagraj (U.P.) India. He has completed tion ( TLBO) algorithm. International Journal of Electrical Power and Energy his PhD from IIT, Kanpur. His areas of interest include Power electronics, power Systems, 50(1), 33–41. https:// doi. org/ 10. 1016/j. ijepes. 2013. 02. 011 system protection, and power systems. 12. Radosavljević, J., & Jevtić, M. (2016). Hybrid GSA-SQP algorithm for Dr. Niraj Kumar Choudhary is presently working as a Asst. Professor in Dept of optimal coordination of directional overcurrent relays. IET Generation, Electrical Engg., MNNIT Allahabad, Prayagraj (U.P.) India. He has completed his Transmission and Distribution, 10(8), 1928–1937. https:// doi. org/ 10. 1049/ PhD from MNNIT Allahabad. His areas of interest include renewable energy and iet- gtd. 2015. 1223 distributed generation based power system power system protection, and micro- 13. Costa, M. H., Saldanha, R. R., Ravetti, M. G., & Carrano, E. G. (2017). Robust grid protection and smart grid, integration issues of DG in distribution system. coordination of directional overcurrent relays using a matheuristic algorithm. IET Generation, Transmission and Distribution, 11(2), 464–474. Fundinghttps:// doi. org/ 10. 1049/ iet- gtd. 2016. 1010 No funding received from any agency. 14. Albasri, F. A., Alroomi, A. R., & Talaq, J. H. (2015). Optimal coordination of directional overcurrent relays using biogeography-based optimization Availability of data and materials algorithms. IEEE Transactions on Power Delivery, 30(4), 1810–1820. https:// Not applicable.doi. org/ 10. 1109/ TPWRD. 2015. 24061 14 15. Solati Alkaran, D., Vatani, M. R., Sanjari, M. J., Gharehpetian, G. B., & Naderi, M. S. (2018). Optimal overcurrent relay coordination in interconnected Declarations networks by using fuzzy-based GA method. IEEE Transactions on Smart Grid, 9(4), 3091–3101. https:// doi. org/ 10. 1109/ TSG. 2016. 26263 93 Competing interests 16. Sharaf, H. M., Zeineldin, H. H., Ibrahim, D. K., El Din, E., & El-Zahab, A. (2015). The authors declare that they have no known competing financial interests A proposed coordination strategy for meshed distribution systems with or personal relationships that could have appeared to influence the work DG considering user-defined characteristics of directional inverse time reported in this paper. overcurrent relays. International Journal of Electrical Power and Energy Systems, 65, 49–58. https:// doi. org/ 10. 1016/j. ijepes. 2014. 09. 028 Received: 21 September 2020 Accepted: 27 January 2022 17. Sharaf, H. M., Zeineldin, H. H., & El-Saadany, E. (2018). Protection coordination for microgrids with grid-connected and islanded capabilities using commu- nication assisted dual setting directional overcurrent relays. IEEE Transactions on Smart Grid, 9(1), 143–151. https:// doi. org/ 10. 1109/ TSG. 2016. 25469 61 18. Nimpitiwan, N., Heydt, G. T., Ayyanar, R., & Suryanarayanan, S. (2007). Fault References current contribution from synchronous machine and inverter based 1. Singh, M. (2017). Protection coordination in distribution systems with and distributed generators. IEEE Transactions on Power Delivery, 22(1), 634–641. without distributed energy resources—A review. 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Coordination of dual setting overcurrent relays in microgrid with optimally determined relay characteristics for dual operating modes

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Springer Journals
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Copyright © The Author(s) 2022
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2367-2617
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2367-0983
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10.1186/s41601-022-00226-1
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Abstract

Fault current magnitude in a microgrid depends upon its mode of operation, namely, grid-connected mode or islanded mode. Depending on the type of fault in a given mode, separate protection schemes are generally employed. With the change in microgrid operating mode, the protection scheme needs to be modified which is uneconomical and time inefficient. In this paper, a novel optimal protection coordination scheme is proposed, one which enables a common optimal relay setting which is valid in both operating modes of the microgrid. In this con- text, a common optimal protection scheme is introduced for dual setting directional overcurrent relays (DOCRs) using a combination of various standard relay characteristics. Along with the two variables, i.e., time multiplier setting ( TMS) and plug setting (PS) for conventional directional overcurrent relay, dual setting DOCRs are augmented with a third variable of relay characteristics identifier (RCI), which is responsible for selecting optimal relay characteristics from the standard relay characteristics according to the IEC-60255 standard. The relay coordination problem is formulated as a mixed-integer nonlinear programming (MINLP) problem, and the settings of relays are optimally determined using the genetic algorithm (GA) and the grey wolf optimization (GWO) algorithm. To validate the superiority of the pro- posed protection scheme, the distribution parts of the IEEE-14 and IEEE-30 bus benchmark systems are considered. Keywords: Plug setting, Time multiplier setting, Protection coordination, Overcurrent relay, Coordination time interval 1 Introduction as measured coordination time interval (MCT) must be Relay coordination is the operation of protective relays in greater than or equal to CTI to ensure proper coordina- a proper sequence when a fault occurs. Depending upon tion among the relays. the fault location in a network, primary and backup relay A relay coordination scheme has two types of inde- pairs (RP) are identified. For proper relay coordination, pendent variables, namely TMS and PS. Depending on the primary relay must operate before the backup relay, these decision variables, the coordination scheme is for- and there must be a time gap between the primary and mulated as a linear, nonlinear, or MINLP programming backup relay operating times, known as the coordination problems [2]. In linear programming, only TMS is treated time interval (CTI) which depends on the type of relays. as a decision variable, while PS is fixed. Using linear pro - The CTI is within the range of 0.3–0.6  s for electrome- gramming (LP) techniques, the optimal value of TMS is chanical relays, while for microprocessor-based relays it obtained by root tree optimization (RTO) [3], improved ranges between 0.2 and 0.5  s [1]. The existing operating firefly algorithm (IFA) [4], genetic algorithm (GA) [5], time gap between the primary and backup relays, known improved harmony search algorithm (IHSA) [6], etc. In nonlinear programming techniques, TMS and PS are both taken as continuous or discrete decision variables. *Correspondence: raghvendra@mnnit.ac.in For electromechanical relays, TMS is continuous, and Electrical Engineering Department, MNNIT, Allahabad, Payagraj, UP, India © The Author(s) 2022. Open Access This article is licensed under a Creative Commons Attribution 4.0 International License, which permits use, sharing, adaptation, distribution and reproduction in any medium or format, as long as you give appropriate credit to the original author(s) and the source, provide a link to the Creative Commons licence, and indicate if changes were made. The images or other third party material in this article are included in the article’s Creative Commons licence, unless indicated otherwise in a credit line to the material. If material is not included in the article’s Creative Commons licence and your intended use is not permitted by statutory regulation or exceeds the permitted use, you will need to obtain permission directly from the copyright holder. To view a copy of this licence, visit http:// creat iveco mmons. org/ licen ses/ by/4. 0/. Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 2 of 18 PS is taken as a discrete variable whereas, for micropro- for both operating modes, the fault current magnitude cessor-based relays, both TMS and PS are considered as must be maintained approximately equal in each mode. continuous variables. Using nonlinear programming, To achieve this, a series connected, fault current limiter the optimal values of TMS and PS are obtained by the (FCL) is used for reducing the fault current magnitude modified firefly algorithm (MFA) [7], differential evolu - in the grid-connected mode during the fault period [19]. tion (DE) [8], gravitational search algorithm (GSA) [9], However, with the inclusion of an extra device, the pro- random search technique (RST) [10], teaching learning tection scheme becomes costly and complicated [20]. To based optimization (TLBO) [11], etc. To overcome the overcome this, a common optimum protection scheme problem of trapping in local minima, some hybrid tech- using conventional DOCR for both operating modes of niques consisting of two different optimization tech - microgrid is proposed in [21], where the combination of niques, such as gravitational search algorithm-sequential optimally selected standard relay characteristics is used. quadratic programming (GSA-SQP) [12], DE-LP [13], To further improve the performance in terms of the total biogeography-based optimization-linear program- relay operating time, dual setting DOCR is considered in ming (BBO-LP) [14], etc. have also been implemented place of conventional DOCR in this paper, and the com- to obtain the optimal values of TMS and PS. In contrast, mon setting is optimally determined for both operating for the MINLP technique [15], TMS and PS are consid- modes of the microgrid. The novelty of this work lies in ered continuous and discrete, respectively. To increase identifying common settings for dual setting relays in the flexibility in the coordination scheme, relay charac - both operating modes without using any external ele- teristic coefficients (α and β) have been introduced as ment or communication system. another decision variable. Thus, each relay is associated The protection scheme for the relay coordination prob - with four decision variables, i.e., TMS, PS, α and β, to fur- lem  formulated  in  this  paper  is an  MINLP because of ther reduce the total relay operating time as compared to the involvement of the third decision variable RCI. The fixed relay characteristics [16]. proposed protection scheme is tested on the 7-bus and Using the above-mentioned techniques, several coor- 18-bus microgrid systems. To show the effectiveness of dination schemes have been proposed for conventional dual setting DOCR, its performance is compared with and dual setting DOCR. Conventional DOCR operates the results obtained by conventional DOCRs [21]. The for the forward direction of the fault current, and hence remainder of the paper is divided into five sections as fol - there exists a single setting, used by DOCR for both lows. Section 2 describes problem formulation using dual primary and backup operations. Whereas, dual setting setting DOCRs, and the solution method is defined in DOCR can operate independently for both forward and Sect.  3. Section  4 provides a brief discussion of the test reverse directions, based upon which two different relay system and results, while validation of the proposed pro- settings (TMS , PS , and TMS , PS ), one for each tection scheme on a larger microgrid system is presented fow fow rev rev direction, are identified. For the forward direction, the in Sect. 5. Finally, the conclusion is given in Sect. 6. relay will act as the primary, and for the reverse direction, the same relay acts as backup protection in both operat- ing modes of the microgrid. [17] 2 Relay coordination problem formulation The fault current characteristics of inverter interface in a microgrid distribution generator (IIDGs) are completely different The operating time of overcurrent relay depends on its from those of the conventional rotating synchronous time–current characteristics, classified according to machine-based DGs (SBDGs). The fault current contri - IEC-60255 standard as normal inverse (NI), very inverse bution of SBDGs are 4–5 times that of the rated current, (VI), and extremely inverse (EI), as shown in Fig. 1. Each whereas, due to the limitation of inverter thermal over- relay characteristic is identified considering the respec - load capability, the fault current contribution of IIDGs is tive characteristic coefficients as shown in Table  1. From limited typically to about 1.2–2 times the rated current Fig.  1, it can be seen that, for a fixed fault current value, [18]. Therefore, overcurrent protection schemes may not the relay operating time is reduced as the relay charac- be significant in the islanded mode of operation consist - teristics change from NI to EI. The relay characteristics ing of only IIDGs. However, in the presence of multi- shown in Fig.  1 can be derived for different values of ple highly penetrated IIDGs along with SBDG, the total TMS and PS using (2) and (3). The objective of the pro - fault current contribution can still be significant for the posed work is to find optimum relay settings and reduce implementation of the overcurrent protection schemes. the overall operating time of dual setting DOCR for both Because of the fault current variation in grid-connected operating modes of the microgrid. and islanded modes of the microgrid, two different relay The objective function (OF) for relay coordination is for - settings are assigned. To obtain a common relay setting mulated as the summation of all primary relay operating T iwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 3 of 18 2.0 PS ≤ PS , PS ≤ PS min rev max fow (7) EI VI NI In (1), t is the operating time of the ith relay in the op_fow forward direction, and n is the number of primary relays 1.5 Reverse Direction Forward Direction for different fault locations. The relay operating times for TMS , PS . TMS , PS . rev rev fow fow forward and reverse directions of fault current are t op_fow and t respectively, as given in (2) and (3). The relay 1.0 op_rev, characteristic coefficients α and β are selected as per IEC- 60255 standard. TMS and TMS are the time multiplier fow rev 0.5 setting and PS and PS are the plug setting of relays fow rev operating in forward and reverse directions respectively. In (4), CTI is the coordination time interval, and its minimum -20-10 -5 05 10 20 value is 0.2 s. The maximum and minimum operating time Multiple of pickup current of relays (t and t ) are 4.0  s and 0.1  s, respec- op_max op_min Fig. 1 Time–current characteristics of a dual setting DOCR tively. Different kind of transients may exist in the power system for a time period of less than one microsecond to several milliseconds. In order to tackle all the transients in the system, the minimum relay operating time (0.1 s) is Table 1 Overcurrent relay characteristics coefficient, according also considered as a constraint to establish the overcurrent to IEC-60255 std relay coordination. Therefore, all transients vanish before Characteristic curve of relay α β Relay the operation of the primary relay. The lower and upper characteristics bound of TMS (TMS and TMS ) and PS (PS and min max min identifier (RCI) PS ) are 0.1, 1.1, 0.5, 2.0 respectively. max Very inverse ( VI) 13.5 1 1 Extremely inverse (EI) 80 2 2 3 Solution method for the relay coordination Normal inverse (NI) 0.14 0.02 3 problem The optimal coordination among the dual setting DOCRs can be achieved by obtaining the optimum values of relay settings, i.e., TMS , TMS , PS and PS , along with times for different fault locations shown in (1) and the fow rev fow, rev the optimal selection of relay characteristics RCI. The required constraints to fulfill the objective of the relay optimal values of all decision variables must be selected coordination problem are given from (4) to (7). to reduce the total relay operating time without any viola- tion of constraints. Thus, each relay is associated with twice OF = min t (1) op_fow the number of variables used in conventional DOCR. For i=1 the forward direction of fault current, the relay is associ- where ated with the forward settings (TMS , PS , and RCI) fow fow and for the reverse direction the same relay is associated α ∗ TMS fow with reverse settings (TMS , PS , and RCI). In this paper t = rev rev op_fow I (2) GA and GWO are used to obtain the values of all decision − 1 PS ∗CTR fow variables. The structure of the chromosome used in GA for dual setting DOCR is shown in Fig. 2. α ∗ TMS rev The proposed protection method using dual setting t = op_rev I (3) f DOCR for both operating modes of the microgrid is shown − 1 PS ∗CTR rev in Fig. 3. In the proposed protection scheme, the first step is to identify the operating mode of the microgrid, and then t − t ≥ CTI the three-phase midpoint fault current is measured at each op_rev op_fow (4) line using short circuit analysis. The relay pairs (primary t ≤ t ≤ t op_ min op_fow op_ max (5) Chromosome TMSfow1 ……. TMSfowm PSfow1 ……. PSfowm TMSrev1 ……. TMSrevn PSrev1 ……. PSrevn RCIfow1 ……. RCIfowm RCIrev1 ……. RCIrevn TMS ≤ TMS , TMS ≤ TMS min rev max fow (6) Fig. 2 Structure of chromosome in GA technique T( ime s) Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 4 of 18 Start Read the test system data Identify the operating mode of test system Grid-Connected or Islanded? Islanded Mode Grid-Connected Mode Modify the test system data according to Modify the test system data according islanded mode of operation to grid-connected mode of operation Identifying the P/B relay pairs for dual setting DOCR Formulation of objective function &Constraints for dual DOCR with different fault locations using NI,VI, EI and mix characterstics Define GA/GWO parameters and set an initial solution Apply GA/GWO to obtain optimum setting using dual setting DOCR All the Constraints are validated? NO YES Obtain the optimum relay setting with least total relay operating time End Fig. 3 Proposed protection method to determine optimal relay setting in grid connected and islanded operating mode and backup) for the different fault locations are identified in part of the IEEE-14 bus system (7-bus microgrid system), both operating modes. Furthermore, the summation of the as shown in Fig.  4, has two inverter-based DGs (IBDGs) operating times of all primary relays is taken as an objective each rated at 20 MVA, connected at buses B2 and B7, and function, and all the constraints related to CTI as well as one synchronous generator (SG) of 50 MVA at bus B1. minimum and maximum relay operating times are formu- The 7-bus microgrid system is connected with the sub- lated. After the determination of GA/GWO parameters, transmission network through buses B3 and B6 each hav- the optimum settings of relays are obtained. If the obtained ing 60 MVA generation capacity. Buses B1, B2, B3, and values satisfy all the constraints for both operating modes, B6 have a maximum short circuit capacity of 250 MVA, they are considered as the final optimal relay settings. 80 MVA, 300 MVA, and 300 MVA, respectively. All other However, in the case where there is any violation of con- specifications of the test system can be obtained from straints, the values of GA/GWO parameters are updated [22]. The 7-bus microgrid test system consists of 8 lines, and the process continues until the final optimal relay set - which are protected by 16 dual setting DOCRs placed ting is obtained without any violation of relay constraints. at both ends of the lines. The CT ratios (CTR) used for dual setting DOCRs are given in Table  2. The fault cur - 4 Test system description and results rent magnitudes through each relay coil for different fault In this paper, for both test systems considered (distri- locations in both operating modes of the microgrid are bution parts of the IEEE-14 and IEEE-30 bus test sys- shown in Table  3. For eight different fault locations (L1, tems), multiple IIDGs are used along with one SBDG L2, L8), there are twenty-two relay pairs (RP1-RP22). and a utility grid. Therefore, the total fault current in For relay pair RP1, R1 and R3 will act as the primary and grid connected mode is shared by all the considered backup dual setting DOCR, respectively. The fault cur - active sources of IIDGs, SBDG and the utility grid. In rent via the primary and backup relay coils in grid-con- the islanded mode of operation, the total fault current is nected and islanded operating modes are 12.075A (R1), shared by multiple IIDGs and the SBDG. The distribution 3.19A (R3), 9.03A (R1), and 0.64A (R3), respectively. T iwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 5 of 18 direction is higher than the reverse direction, which justi- IBDG SG IBDG fies the need of dual setting relays. B1 B2 B7 R16 R5 R2 R6 R1 R7 L3 L1 R3 4.1 Optimum relay setting in grid‑connected mode The settings of the optimal dual setting DOCR obtained L2 by GA in the grid-connected mode of operation, using L8 L4 NI, VI, EI and mixed relay characteristics, are shown in Table  4. The total operating times of all dual setting L7 L6 L5 DOCRs with NI and VI characteristics are found to be R4 3.3877  s and 1.6825  s, respectively. From the results, R15 R13 R12 R11 R10 R9 R8 R14 it can be seen that by using VI characteristics the over- B6 B4 B3 B5 all relay operating time can be reduced by up to 50.33% when compared to NI characteristics. From the obtained optimal settings, it can be seen that for NI characteris- tics, the operating time of R1 in RP1 is 0.2146  s for the forward direction, whereas for the reverse direction the Fig. 4 Distribution part of IEEE-14 bus test system with dual setting operating time of R1 in RP4 is 2.049  s. Thus, the relay DOCR operating time for the forward direction of fault cur- rent is lower than the reverse direction. This statement is valid for all the dual setting DOCRs with NI, VI, EI, and Table 2 CT ratios of DOCR for 7-bus microgrid system mixed characteristics in grid-connected mode. Similarly, the results obtained using EI relay characteristics and a Relay CT ratio combination of optimally selected relay characteristics 1 2000/5 (mixed-characteristics) in grid-connected mode show 2 1000/5 that the total operating times of dual setting DOCRs with 3 3000/5 EI and mixed characteristics are 1.6124  s and 1.6065  s, 4 2000/5 respectively. Thus, there is a reduction of 0.36% in total 5 1600/5 relay operating time using mixed characteristics as com- 6 1000/5 pared to EI characteristics. In addition, it can be seen that 7 2500/5 by using mixed characteristics the total relay operating 8 1600/5 time is reduced by 52.57% and 4.51% as compared to NI 9 2500/5 and VI characteristics, respectively. From the results, it 10 1200/5 can be concluded that by using optimally selected relay 11 1200/5 characteristics the total relay operating time is the least 12 2500/5 when compared to NI, VI, EI characteristics. Also only 13 800/5 VI and EI characteristics are optimally selected in mixed 14 3000/5 characteristics. A graphical representation of the primary 15 1600/5 relay operating times obtained by GA with NI, VI, EI, and 16 1600/5 mixed characteristics in grid-connected mode using dual setting DOCR is shown in Fig.  5. The MCT and backup relay operating times for dual setting DOCR obtained It can be seen from the short circuit analysis that the by GA in grid-connected mode of the 7-bus microgrid fault current magnitude in grid-connected mode is higher system are presented in Figs.  6 and 7, respectively. Here than in the islanded mode of operation. Consequently, MCT can be defined as the actual operating time differ - it is possible that DOCRs with NI relay characteristics ence between the primary and backup relays using opti- may take a long time to operate. This is not desirable as mal values of TMS and PS. In all cases, the value of MCT it may lead to mis-coordination of relay pairs, potentially is always greater than CTI. This indicates the required resulting in a larger portion of the system being isolated. time gap between primary and backup relays for each RP. To avoid this situation, relay characteristic curves have The optimal results satisfy all the considered constraints been optimally selected by including a third optimization while formulating the relay coordination problem. variable known as a relay characteristics identifier (RCI). Besides this, the fault current magnitude in the forward Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 6 of 18 Table 3 Current through relay coils in grid-connected and islanded operating modes for 7-bus microgrid system Faulty line Relay pair Primary relay Backup relay Fault current through relay coils (dual) Grid‑ connected (A) Islanded mode (A) Primary Backup Primary Backup L1 RP1 R1 R3 12.075 3.19 9.03 0.64 RP2 R1 R5 12.075 2.53 9.03 1.76 RP3 R2 R7 17.175 4.13 11.52 1.45 L2 RP4 R3 R1 9.561 4.10 8.07 2.39 RP5 R3 R5 9.561 2.16 8.07 1.04 RP6 R4 R14 16.075 2.64 5.35 1.59 RP7 R4 R15 16.075 1.69 5.35 3.30 L3 RP8 R5 R1 17.196 3.27 12.4 2.32 RP9 R5 R3 17.196 2.67 12.4 0.538 RP10 R6 R16 16.785 6.18 11.72 2.60 L4 RP11 R7 R2 7.038 9.94 6.174 7.34 RP12 R8 R9 16.793 2.34 6.134 2.80 L5 RP13 R9 R8 16.038 6.08 5.356 6.52 RP14 R10 R11 11.634 10.86 8.65 7.85 L6 RP15 R11 R10 19.90 19.37 9.154 8.36 RP16 R12 R13 7.18 22.15 4.94 15.11 L7 RP17 R13 R12 18.28 5.75 9.675 2.97 RP18 R14 R4 11.04 5.51 6.43 6.37 RP19 R14 R15 11.04 3.012 6.43 3.66 L8 RP20 R15 R4 17.728 3.047 9.52 5.22 RP21 R15 R14 17.728 2.075 9.52 1.435 RP22 R16 R6 9.734 9.145 8.14 6.165 4.2 O ptimum relay setting in islanded mode by GA is reduced by 59% and 7.99% compared to NI and The optimal settings obtained by GA in islanded mode VI characteristics, respectively. It can be concluded that using dual setting DOCR, with NI, VI, EI and mixed relay by using optimally selected relay characteristics the relay characteristics are shown in Table  5. It is found that the operating time is lower than all the other (NI, VI, and EI) total operating times of relays obtained by GA using NI characteristics. In the islanded mode of operation, only and VI characteristics are 3.9882  s and 1.7765  s, respec- VI and EI type relay characteristics are optimally selected tively. It can be seen that using VI characteristics, the in the case of mixed characteristics. The primary dual total relay operating time obtained by GA can be mini- setting DOCR operating times obtained by GA using NI, mized by 55.45% when compared to NI characteristics. VI, EI and mixed characteristics in islanded operating Also, the operating time for relay R1 in RP1 is 0.2350  s mode are shown in Fig. 8. for the forward direction whereas for the reverse direc- tion of fault current the operating time of relay R1 in 4.3 Comparative analysis of results in dual operating RP4 is 1.6779  s (with NI characteristics). Thus the relay mode operating time for the forward direction is lower than The performance of dual setting DOCR in terms of the that of the reverse direction. Similarly, from the results total relay operating time is compared with conven- obtained by GA using EI and mixed relay characteristics tional DOCR [20], in Table  6. It can be seen that, as in islanded mode, the total dual setting DOCR operat- the relay characteristics change from NI to optimally ing times obtained by GA using EI and mixed charac- selected mixed characteristics, there is a significant teristics are 1.6928  s and 1.6345  s respectively. By using reduction in the relay operating time in both operating mixed characteristics, the relay operating time obtained modes of the microgrid. To validate the effectiveness of T iwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 7 of 18 Table 4 Optimal relay setting with NI, VI, EI and mixed relay characteristics for dual setting DOCR in grid-connected mode Relay NI relay characteristics VI relay characteristics EI relay characteristics Mixed relay characteristics RCI Forward Reverse Forward Reverse Forward Reverse Forward Reverse TMS PS TMS PS TMS PS TMS PS TMS PS TMS PS TMS PS TMS PS R1 0.1 0.5121 0.9624 0.5 0.1664 0.5127 1.1 0.6921 0.1631 1.0575 1.1 1.980 0.7210 0.5 0.1156 1.7939 2 R2 0.1 0.5 0.9838 1.8298 0.1014 1.1690 1.1 2 1.1 0.5848 1.1 1.9954 0.1579 1.5166 1.1 1.9999 2 R3 0.1 0.5 0.7723 0.7037 0.1289 0.5145 0.4245 1.097 0.4819 0.5 1.1 1.9986 0.3517 0.5673 0.4377 0.6875 2 R4 0.1002 0.5 0.3553 1.6428 0.1 1.1015 1.0171 0.5 1.0843 0.5433 1.0965 2 1.0824 0.5433 0.1539 1.3230 2 R5 0.1 0.5 0.6815 0.5001 0.1736 0.6995 0.1156 1.5592 0.5740 0.8006 1.1 2 0.4359 0.9163 0.5404 0.5011 2 R6 0.1 0.5 0.8508 0.8232 0.1572 0.7579 1.0591 1.9992 1.0277 0.5821 1.1 2 0.5267 0.8171 1.1 1.9065 2 R7 0.1 0.5 1.1 0.6261 0.1040 0.5 1.1 0.8780 0.2207 0.5402 1.1 2 0.2347 0.5107 1.1 0.8577 2 R8 0.1 0.8808 1.1 0.9211 0.1948 0.6102 1.1 1.2910 0.2753 1.1354 1.1 1.9940 1.0746 0.5699 1.1 1.2693 2 R9 0.1 0.5 0.2334 1.5578 0.2293 0.5 0.1625 1.5080 0.975 0.5766 1.1 2 0.1 1.7735 0.1 1.0914 2 R10 0.1 0.5644 1.1 2 0.1073 0.7490 1.1 1.9999 0.6700 0.5 1.1 1.9846 0.6703 0.5 1.0999 1.9966 2 R11 0.1 0.5 1.1 1.6436 0.1874 0.75 1.0945 1.3768 0.2089 1.5295 0.9944 1.9579 1.0363 0.6902 1.0999 2 2 R12 0.1 0.5 1.1 0.8664 0.1064 0.5 0.3895 1.6736 0.1124 0.75 1.0245 2 0.1006 0.7924 0.8604 1.0015 2 R13 0.1 0.5 1.1 2 0.2679 0.5 1.1 2 0.2875 1.2163 1.0849 1.9933 0.9133 0.6726 1.1 1.9999 2 R14 0.1 0.5082 0.1483 0.5 0.2666 0.5 0.1046 1.5332 0.6012 0.5028 1.0994 1.9357 0.3895 0.6214 0.1014 0.5063 2 R15 0.1 0.5 0.108 0.5136 0.2533 0.5 0.3810 0.5 0.1604 1.5536 1.1 1.6875 0.1720 1.5085 0.1666 0.7099 2 R16 0.1 0.5 1.1 0.9336 0.1371 0.5 1.0810 0.7936 0.1 1.0781 1.0957 1.9354 0.1200 0.5625 0.6290 1.25 1 T 3.3877 (s) 1.6825 (s) 1.6124 (s) 1.6065 (s) op Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 8 of 18 Fig. 5 Primary relay operating time having NI, VI, EI and mixed characteristics in grid-connected mode Fig. 6 MCT having NI, VI, and EI and mixed characteristics using dual setting DOCR in grid-connected mode Fig. 7 Backup relay operating time having NI, VI, EI and mixed characteristics in grid- connected mode T iwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 9 of 18 Table 5 Optimal relay setting with NI, VI, EI and mixed relay characteristics for dual setting DOCR in islanded mode Relay NI relay characteristics VI relay characteristics EI relay characteristics Mixed relay characteristics RCI Forward Reverse Forward Reverse Forward Reverse Forward Reverse TMS PS TMS PS TMS PS TMS PS TMS PS TMS PS TMS PS TMS PS R1 0.1 0.5 0.3990 1.7560 0.1 0.6179 0.8838 1.0268 0.1 1.1507 0.6248 1.6556 0.4037 0.5 0.8180 1.5353 2 R2 0.1 0.5 1.1 1.9999 0.1 0.7874 1.1 2 0.5490 0.5543 1.1 1.9860 0.6568 0.5 1.1 2 2 R3 0.1001 0.5107 0.1 0.5 0.1110 0.5 0.1 0.5 0.1 0.9322 0.1036 0.5 0.1499 0.7313 0.1 0.5 2 R4 0.1 0.5 1.1 2 0.1 0.5001 1.1 1.9994 0.1361 0.5150 1.1 1.9989 0.1 0.5 1.0999 1.9999 1 R5 0.1001 0.5 0.8837 0.5627 0.1746 0.5 0.2198 0.8933 0.1296 1.2249 0.1773 0.8465 0.3070 0.7862 0.4373 0.7167 2 R6 0.1 0.5023 1.1 2 0.1078 0.7464 1.1 2 0.2603 0.8131 1.1 1.9987 0.1082 0.7492 1.1 2 1 R7 0.1 0.5033 0.2640 1.0202 0.1 0.5 1.0687 0.5626 0.1 0.75 0.9422 0.75 0.1693 0.5258 1.1 0.6901 2 R8 0.1 0.5 1.0332 1.6895 0.1 0.5 1.1 2 0.1707 0.5212 1.1 1.9033 0.1690 0.5230 1.1 2 2 R9 0.1 0.5 0.9751 0.7813 0.1001 0.5 0.4204 1.7383 0.1 0.6063 1.1 1.6982 0.1421 0.5 0.5146 1.7406 2 R10 0.1 0.5 1.0968 1.9100 0.1126 0.5286 1.1 1.9979 0.3576 0.5108 1.1 1.9918 0.3705 0.5 1.1 2 2 R11 0.1 0.5 1.0970 2 0.1269 0.5 1.1 2 0.1779 0.7685 1.0928 1.9973 0.3679 0.53 1.1 2 2 R12 0.1001 0.5 0.8712 1.6211 0.1 0.5 0.9056 1.7699 0.1173 0.5078 0.7916 1.9945 0.1284 0.5 0.9226 1.5083 2 R13 0.1 0.5 1.1 2 0.1346 0.5 1.1 2 0.4711 0.5079 1.1 2 0.3753 0.5548 1.1 2 2 R14 0.1 0.5 0.1 0.7615 0.1 0.5128 0.3620 0.9708 0.1970 0.5121 0.9614 0.75 0.1 0.7111 0.9115 0.7626 2 R15 0.1 0.5 1.1 1.5384 0.1315 0.5026 0.8687 2 0.4680 0.5 1.1 1.3455 0.4483 0.5 1.1 1.6245 2 R16 0.1 0.5 0.3807 2 0.1121 0.5 0.9770 1.0648 0.3744 0.5 0.6468 1.45 0.1999 0.6384 1.0960 1.2421 2 T 3.9882 (s) 1.7765 (s) 1.6928 (s) 1.6345 (s) op Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 10 of 18 Fig. 8 Primary relay operating time having NI, VI, EI and mixed characteristics in islanded mode Table 6 Comparative analysis of conventional DOCR [20] and dual setting DOCR for 7-bus microgrid system Operating Relay Conventional Dual DOCR Conventional Dual DOCR Reduction Reduction mode characteristics DOCR operating operating time DOCR operating time in total relay in total relay time (s) using (s) using GA operating time (s) using GWO operating time operating time GA [20] (s) using GWO using GA using GWO Grid-connected NI 7.2041 3.3877 7.2453 3.4045 52.97% 53.01% VI 2.4392 1.6825 2.5482 1.7402 31.02% 31.70% EI 1.6681 1.6124 1.7053 1.6139 3.39% 5.35% Mixed 1.6684 1.6065 1.6868 1.6103 3.71% 4.53% Islanded NI 7.3148 3.9882 7.4868 3.9918 45.47% 46.68% VI 3.2457 1.7765 3.3625 1.7885 45.26% 46.81% EI 6.7142 1.6928 2.0911 1.7258 74.78% 17.46 Mixed 2.0670 1.6345 2.0888 1.6459 20.92% 21.20% Table 7 Coordination constraint violation summary of the 7-bus microgrid system using GA Setting calculated Characteristics curve Constraint violation in conventional DOCR Constraint violation in dual considered [20] setting DOCR Islanded Grid‑ connected Islanded Grid‑ connected Islanded NI NIL 13 NIL 01 VI NIL 14 NIL 16 EI NIL 5 NIL 17 Mixed NIL 12 NIL 16 Grid-connected NI 08 NIL 04 NIL VI 07 NIL 04 NIL EI 04 NIL 07 NIL Mixed 06 NIL 05 NIL T iwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 11 of 18 Load Test System Data for grid connected and islanded the common optimal relay setting for dual setting mode of operation of microgrid DOCRs. In this process, all the relay constraints of Identification of microgrid operating mode both operating modes are considered together when minimizing the objective function. The common opti- Measurement of three phase mid point fault mal relay settings obtained by GA with the optimally current selected relay characteristics are shown in Table  8. Identifying the P/B relay pairs for dual setting DOCR The primary relay operating times obtained by GA Formulation of objective function for dual setting using conventional and dual setting overcurrent relays DOCR with different fault locations are displayed in Fig.  10. In this case, the number of Combine relay constraints of grid connected and relays remains the same, but the number of relay con- islanded mode using dual setting DOCR straint, and relay pairs, are doubled (RP1-RP44) com- Define GA/GWO parameters and set an initial pared to grid-connected or islanded operating mode solution (RP1-RP22). The results reveal that for the obtained Apply GA/GWO to obtain optimum common setting common relay settings, all three types of relay char- using dual setting DOCR acteristics, i.e., NI, VI, and EI, are optimally deter- Obtain the common optimum relay setting with least mined. The total relay operating times obtained by total relay operating time GA are found to be 1.6800  s for dual setting DOCR Fig. 9 Method for common optimal setting for dual operating modes of MG and 2.4392  s for conventional DOCR [20]. This rep- resents a reduction of 31.12% while using dual setting relays with the common optimal settings, while the constraints in both operating modes are completely GA, the results are also compared with the grey wolf satisfied, i.e., no constraint violation occurs for either optimization (GWO) technique. The results show that of the operating modes. GA gives better results in terms of total relay operat- ing time in all cases except the islanded case of conven- 5 Proposed protection scheme validation tional DOCR using EI characteristics. The percentage on 18‑bus microgrid system reduction in operating time of dual-setting DOCRs To validate the effectiveness of the proposed protec- compared to conventional DOCR in each case is shown tion scheme, the proposed protection method imple- in Table  6. The violation constraints (in terms of num - mented on the distribution part of the IEEE-14 bus ber) in both operating modes of the microgrid are dis- test system is applied in a similar manner to a larger played in Table  7, while any protection schemes are no microgrid system, i.e., the distribution part of the longer valid if any of the constraints associated with the IEEE-30 bus test system (an 18-bus microgrid system) relay coordination problem are violated. It is seen that is considered. The 18-bus microgrid system consists when the optimal settings obtained for grid-connected of 22 lines, one SG (50MVA) connected at bus B1, and mode (for dual setting DOCRs) are applied in islanded three IBDG (20 MVA each) at buses B4, B11, and B18 mode, several constraints are violated (4 for NI, 4 for [20]. The other relevant information regarding the VI, 7 for EI and 5 for mixed characteristics). In the IEEE-30 bus system is given in “Appendix”. To pro- same way when the optimal relay settings of islanded tect this system, 44 dual setting relays (R1–R44) are mode are applied in grid-connected mode, some con- required. These are placed at both ends of the lines as straints are violated (1 for NI, 16 for VI, 17 for EI and 16 shown in Fig. 11. The system is connected to the utility for mixed characteristics). Therefore, it is desirable to grid through buses B1, B2 and B16 as shown in Fig. 11. obtain a common relay setting for the operation of the The primary-backup relay pairs (RP1–RP72) for dif- protection scheme, one which can satisfy all the operat- ferent fault locations (L1–L22) are shown in Table  9. ing mode constraints. In this test system, for some of the relay pairs, the fault currents flowing through the respective backup 4.4 C ommon optimum relay setting in dual operating relays are very small compared to the primary relays modes of microgrid because the backup relay operating times are larger The proposed method for a common optimal setting than those of the primary relays. Such relay pairs are that can be used in both operating modes is shown ignored during the relay coordination process, as they in Fig.  9, where the effects of both operating modes always satisfy the respective constraints. All other of the microgrid are taken into account, to identify test system information is taken from [22]. To show Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 12 of 18 Table 8 Common optimal relay setting using dual setting DOCR for 7-bus microgrid system Relay Forward Reverse RCI Relay Forward Reverse RCI TMS PS TMS PS TMS PS TMS PS R1 0.5071 0.595 0.1000 0.816 2 R9 0.2205 0.516 0.610 0.500 1 R2 0.6757 0.734 0.9420 1.649 2 R10 0.6688 0.500 1.1000 1.744 2 R3 0.1329 0.500 0.1188 0.500 1 R11 0.2159 1.502 1.1000 1.638 2 R4 0.1000 0.500 0.3501 1.657 3 R12 0.2540 0.500 1.0990 0.531 2 R5 0.7841 0.682 0.1626 0.504 2 R13 0.1614 1.594 1.1000 2.000 2 R6 0.1000 1.146 0.9213 1.500 1 R14 0.6022 0.500 0.1000 0.572 2 R7 0.2440 0.500 0.1610 0.622 2 R15 0.1000 1.211 0.2417 0.500 1 R8 0.2390 0.5000 1.1000 1.2920 1 R16 0.1333 0.5075 0.1475 0.8044 1 Top 1.68 (s) Fig. 10 Primary relay operating time using single and dual setting DOCR for common relay setting the efficacy of the proposed protection scheme for shown in Table  10. From Table  10, it can be seen that the 18-bus microgrid system, only the common oper- the total primary relay operating time obtained by GA ating mode is considered due to page limitations. To for dual setting overcurrent relays, is 4.4472  s, which determine the common optimal relay settings which is 60.47% lower than that for conventional DOCRs can be used in both operating modes, the impacts of [20] as shown in Table 11. The primary relay operating both operating modes are considered simultaneously. times for all the relay pairs (RP1–RP144) associated Therefore, the number of constraints is doubled com- with grid-connected mode (RP1–RP72) and islanded pared to those in the individual operating mode. The mode (RP73–RP144) using single and dual setting minimum and maximum values of TMS, PS, and pri- overcurrent relays in common operating mode are mary relay operating time are considered the same as shown in Fig. 12. in the 7-bus microgrid system. The common optimal It can be concluded that the common optimal relay set- relay settings for the 18-bus microgrid system using tings satisfy all the constraints related to grid-connected dual-setting overcurrent relays, obtained by GA are and islanded mode of operation simultaneously. Thus, T iwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 13 of 18 B17 R43 R40 L22 L20 IBDG R44 R39 B18 R42 R41 L21 B16 R38 L19 R37 R35 R36 L17 L18 R34 B15 B14 B12 R33 B13 L10 IBDG R19 R20 R31 R32 R30 L16 B4 L15 R16 R12 R17 R29 IBDG R28 L8 B7 B8 L14 B11 R25 R15 R18 R23 R24 R8 L9 L12 L13 R27 R26 B1 B10 L6 B3 R10 R4 R6 L4 L5 L2 L3 L7 L11 L1 R9 R11 R13 R14 R21 R22 R2 R1 R3 R5 R7 B5 B6 B2 B1 SG Fig. 11 Distribution part of IEEE-30 bus system (18-bus microgrid system) the proposed protection scheme using dual-setting over- is the determination of common settings of dual set- current relays also provides the common optimal relay ting relays for both operating modes of the microgrid. settings for larger test system such as the 18-bus micro- From the results, it can be concluded that the relay grid test system which can be used in both operating operating times in both modes decrease significantly modes. To show the efficacy of the GA, a comparative as the relay characteristics change. In this context, analysis in terms of total relay operating time for both for the 7-bus microgrid system, 16 dual-setting relays test systems (the 7-bus and 18-bus microgrid systems) is (R1–R16) have been considered with NI, VI, EI and shown in Table 11. It can be seen there that the total relay mixed characteristics by which the total relay operat- operating times obtained by the GA are better than the ing times are reduced by 52.97%, 31.02%, 3.39% and GWO for both test cases. In addition, the total primary 3.71% in grid-connected mode, and by 45.47%, 45.26%, relay operating time in the common operating mode 74.78% and 20.92% in islanded mode as compared using dual setting DOCR is always lower than the con- to conventional DOCR. Also, in common operating ventional DOCR [20]. mode, the percentage reductions in total relay operat- ing time for dual setting DOCR obtained by GA in the 6 Conclusion 7-bus and 18-bus microgrid systems are 31.02% and This paper presents a comparative analysis of relay 60.47% respectively, compared to the conventional coordination for 7-bus and 18-bus microgrid systems DOCR. Similarly, the percentage reductions in total using dual-setting relays in both operating modes of a relay operating time for dual-setting DOCR obtained microgrid. One of the major findings of the research by GWO in the 7-bus and 18-bus microgrid systems Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 14 of 18 Table 9 Primary-Backup relay pair for different fault locations in 18 bus microgrid system Fault location Relay pair (RP) Primary relay Backup Fault location Relay pair (RP) Primary relay Backup Fault location Relay pair (RP) Primary relay Backup relay relay relay (dual) (dual) (dual) L1 RP1 R1 R3 L7 RP26 R13 R9 L15 RP51 R29 R28 RP2 R1 R5 RP27 R13 R11 RP52 R30 R32 RP3 R1 R7 RP28 R14 R21 RP53 R30 R33 RP4 R2 R22 L8 RP29 R15 R10 L16 RP54 R31 R20 L2 RP5 R3 R1 RP30 R16 R12 RP55 R32 R30 RP6 R3 R5 RP31 R16 R17 RP56 R32 R33 RP7 R3 R7 RP32 R16 R19 L17 RP57 R33 R30 RP8 R4 R26 L9 RP33 R17 R12 RP58 R33 R32 L3 RP9 R5 R1 RP34 R17 R16 RP59 R34 R37 RP10 R5 R3 RP35 R17 R19 L18 RP60 R35 R34 RP11 R5 R7 RP36 R18 R23 RP61 R35 R37 RP12 R6 R27 L10 RP37 R19 R12 L19 RP62 R37 R34 L4 RP13 R7 R1 RP38 R19 R16 RP63 R38 R39 RP14 R7 R3 RP39 R19 R17 RP64 R38 R41 RP15 R7 R5 RP40 R20 R31 L20 RP65 R39 R38 RP16 R8 R28 L11 RP41 R21 R14 RP66 R39 R41 RP17 R8 R29 RP42 R22 R2 RP67 R40 R43 L5 RP18 R9 R11 L12 RP43 R23 R18 L21 RP68 R41 R38 RP19 R9 R13 RP44 R24 R25 RP69 R41 R39 RP20 R10 R15 L13 RP45 R25 R24 RP70 R42 R44 L6 RP21 R11 R9 RP46 R26 R4 L22 RP71 R43 R40 RP22 R11 R13 L14 RP47 R27 R6 RP72 R44 R42 RP23 R12 R16 RP48 R28 R8 RP24 R12 R17 RP49 R28 R29 RP25 R12 R19 RP50 R29 R8 T iwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 15 of 18 Table 10 Optimal relay setting for common operating mode in 18 bus microgrid system using GA Relay RCI Forward Reverse Relay RCI Forward Reverse TMS PS TMS PS TMS PS TMS PS 1 2 0.2909 1.1371 1.1000 1.9998 23 1 0.2277 0.5167 1.1000 1.9998 2 2 0.1 1.7002 0.4104 0.5510 24 2 0.4351 0.9222 1.1000 1.0659 3 2 0.1477 1.7122 1.1000 2.0000 25 2 0.1581 1.5164 1.1000 0.6721 4 2 1.0844 0.5740 0.7170 0.5913 26 2 0.5009 0.6876 1.1000 2.0000 5 2 0.8237 0.7349 1.1000 2.0000 27 2 0.4578 0.9954 1.0751 1.9645 6 1 0.2503 0.5144 1.0034 0.7500 28 2 0.1000 1.9102 1.1000 2.0000 7 2 0.6753 0.7578 1.1000 2.0000 29 2 0.5285 0.7757 1.1000 1.9953 8 2 0.2382 1.1168 1.1000 1.6350 30 2 0.4732 0.8708 1.0933 1.9979 9 2 0.5338 0.8283 1.1000 2.0000 31 2 0.4841 0.9310 0.9246 1.4508 10 2 1.0805 0.5953 1.1000 0.5156 32 2 0.1660 1.5015 1.1000 2.0000 11 1 0.2643 0.5162 1.1000 1.1119 33 2 0.7823 0.7869 1.1000 2.0000 12 2 0.2656 1.3253 1.1000 2.0000 34 2 1.0812 0.5786 1.1000 1.9987 13 2 1.0956 0.6344 1.1000 1.8827 35 2 0.3466 1.0587 1.1000 1.2698 14 2 0.8333 0.6044 1.1000 2.0000 36 2 0.2712 0.5864 1.1000 0.7618 15 2 0.3386 1.1727 0.1061 0.5050 37 2 0.2140 1.5094 0.1841 1.3251 16 2 1.0961 0.5312 1.1000 2.0000 38 1 0.2141 0.5218 1.1000 1.9983 17 2 0.1610 1.5053 1.1000 2.0000 39 2 0.3391 1.1641 1.1000 2.0000 18 2 1.0198 0.6835 1.1000 1.9844 40 2 1.0323 0.6713 1.1000 2.0000 19 2 0.3944 0.9916 1.1000 1.9985 41 2 1.0477 0.6434 1.1000 1.9999 20 2 0.9609 0.5456 1.0377 1.3120 42 3 0.1001 0.5000 1.1000 2.0000 21 2 0.5839 0.7671 1.0999 2.0000 43 2 1.0830 0.5672 1.1000 0.8326 22 2 0.2362 1.2411 1.1000 2.0000 44 2 0.9623 0.6789 1.1000 2.0000 T 4.4472 (s) op Table 11 Summary of total relay operating time using single and dual setting overcurrent relays in common operating mode Sr. nos Test system Optimization Total relay operating time (s) Percentage reduction in technique total relay operating time Conventional DOCR Dual setting DOCR 1 7 Bus microgrid GA [20] 2.4392 1.6800 31.12% GWO 2.4412 1.7028 30.24% 2 18 Bus microgrid GA [20] 11.2509 4.4472 60.47% GWO 7.0393 4.5780 34.96% are 30.24% and 34.96% respectively when compared to The performance of the proposed protection scheme conventional DOCR. One of the major advantages of can be further enhanced by taking the relay character- the proposed technique is that there is no constraints istic coefficients (α and β) as continuous variables. violation in either operating mode of the microgrid. Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 16 of 18 2.2 Single Setting-Primary Relay 2.0 Dual Setting-Primary Relay 1.8 1.6 1.4 1.2 1.0 0.8 0.6 0.4 0.2 20 40 60 80 100 120 140 Relay Pair (RP) Fig.12 Primary relay operating time using single and dual setting overcurrent relays for common relay setting in 18 bus microgrid test system Appendix See Tables 12, 13 and 14. Table 12 Bus load and injection data of IEEE 30-bus system Table 13 Reactive power limit of IEEE-30 bus test system Bus Load Bus Load Bus Qmin (p.u.) Qmax (p.u.) Bus Qmin (p.u.) Qmax (p.u.) 1 0.0 16 3.5 1 − 0.2 0.0 16 2 21.7 17 9.0 2 − 0.2 0.2 17 − 0.05 0.05 3 18 0.0 0.055 3 2.4 18 3.2 4 19 4 67.6 19 9.5 5 − 0.15 0.15 20 5 34.2 20 2.2 6 0.0 21 17.5 6 21 7 22.8 22 0.0 7 22 8 30.0 23 3.2 8 − 0.15 0.15 23 − 0.05 0.055 9 0.0 24 8.7 9 24 10 5.8 25 0.0 10 25 11 0.0 26 3.5 11 − 0.1 0.1 26 12 11.2 27 0.0 12 27 − 0.055 0.055 13 − 0.15 0.15 28 13 0.0 28 0.0 14 29 14 6.2 29 2.4 15 30 15 8.2 30 10.6 Operating Time (s) T iwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 17 of 18 Table 14 Line parameter of IEEE-30 bus test system Line From bus To bus /t (p.u.) I (p.u) Tap ratio Rating (p.u) 1 1 2 0.0192 0.0575 0.300 2 1 3 0.0452 0.1832 0.9610 0.300 3 2 4 0.0570 0.1737 0.9560 0.300 4 3 4 0.0132 0.0379 0.300 5 2 5 0.0472 0.1983 0.300 6 2 6 0.0581 0.1763 0.300 7 4 6 0.0119 0.0414 0.300 8 5 7 0.0460 0.1160 0.300 9 6 7 0.0267 0.0820 0.300 10 6 8 0.0120 0.0420 0.300 11 6 9 0.0000 0.2080 0.300 12 6 10 0.0000 0.5560 0.300 13 9 11 0.0000 0.2080 0.300 14 9 10 0.0000 0.1100 0.9700 0.300 15 4 12 0.0000 0.2560 0.9650 0.650 16 12 13 0.0000 0.1400 0.9635 0.650 17 12 14 0.1231 0.2559 0.320 18 12 15 0.0662 0.1304 0.320 19 12 16 0.0945 0.1987 0.320 20 14 15 0.2210 0.1997 0.160 21 16 17 0.0824 0.1932 0.160 22 15 18 0.1070 0.2185 0.160 23 18 19 0.0639 0.1292 0.9590 0.160 24 19 20 0.0340 0.0680 0.320 25 10 20 0.0936 0.2090 0.320 26 10 17 0.0324 0.0845 0.9850 0.320 27 10 21 0.0348 0.0749 0.300 28 10 22 0.0727 0.1499 0.300 29 21 22 0.0116 0.0236 0.300 30 15 23 0.1000 0.2020 0.160 31 22 24 0.1150 0.1790 0.300 32 23 24 0.1320 0.2700 0.9655 0.160 33 24 25 0.1885 0.3292 0.300 34 25 26 0.2544 0.3800 0.300 35 25 27 0.1093 0.2087 0.300 36 28 27 0.0000 0.3960 0.300 37 27 29 0.2198 0.4153 0.9810 0.300 38 27 30 0.3202 0.6027 0.300 39 29 30 0.2399 0.4533 0.300 40 8 28 0.0636 0.2000 0.9530 0.300 41 6 28 0.0169 0.0599 0.300 Abbreviations Acknowledgements DOCR: Directional overcurrent relay; TMS: Time multiplier setting; PS: Plug Not applicable. setting; RCI: Relay characteristics identifier; CTI: Coordination time interval; CTR : Current transformer ratio; RP: Relay pair; OF: Objective function; NI: Authors’ contributions Normal inverse; VI: Very inverse; EI: Extremely inverse; IIDG: Inverter interface RT carried out problem formulation, simulation, calculations, preparing manu- distributed generator; SBDG: Synchronous based distributed generator; CCM: script, RKS and NKC participated in problem conceptualization, coordination Current control mode; VCM: Voltage control mode; GA:: Genetic algorithm; and helped to draft manuscript. All authors read and approved the final GWO: Grey wolf optimization. manuscript. Tiwari et al. Protection and Control of Modern Power Systems (2022) 7:6 Page 18 of 18 Authors’ information with DG penetration. IEEE Transactions on Industry Applications, 54(2), Mr. Raghvendra Tiwari is Research Scholar pursuing his PhD in Electrical Engg. 1155–1165. https:// doi. org/ 10. 1109/ TIA. 2017. 27730 18 from Motilal Nehru National Institute of Technology (MNNIT ) Allahabad, Praya- 10. Birla, D., Maheshwari, R. P., Gupta, H. O., Deep, K., & Thakur, M. (2006). graj (U.P), India., he graduated (2007) and post graduated (2013) in Electrical Application of random search technique in directional overcurrent relay Engg. From National Institute of Technical Teachers Training and Research coordination. International Journal of Emerging Electric Power Systems, 7(1), (NITTTR), Chandigarh (Haryana). 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Journal

Protection and Control of Modern Power SystemsSpringer Journals

Published: Dec 1, 2022

Keywords: Plug setting; Time multiplier setting; Protection coordination; Overcurrent relay; Coordination time interval

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