Journal of Control, Automation and Electrical Systems (2018) 29:192–208 https://doi.org/10.1007/s40313-017-0361-8 A Real Test System For Power System Planning, Operation, and Reliability Meisam Mahdavi1 · Carlos Sabillón1 ·Majid Ajalli2 · Hassan Monsef3 · Ruben Romero1 Received: 10 April 2017 / Revised: 17 November 2017 / Accepted: 27 December 2017 / Published online: 1 February 2018 © Brazilian Society for Automatics–SBA 2018 Abstract Nowadays, several test systems available in the specialized literature are used to verify studies regarding power system planning or network reliability. However, there are no test systems currently available with enough information in order to endorse studies that simultaneously approach expansion planning, operation, and reliability issues. This paper introduces a real test system, including the load modeling, and generation and transmission systems. The main objective is to provide all the details and information required to evaluate methods and models developed for power system planning, operation, and reliability. The presented load modeling includes hourly, daily, weekly, monthly, and seasonal patterns. Furthermore, besides the substation data, reliability details, construction costs, and characteristics of right of ways (e.g., line length, impedance, and ratings) for the transmission system are exposed. The real transmission system presented contains 39 buses, 135 transformers, and 66 lines at two voltage levels: 230 and 400 kV. Finally, the generation system reliability data as well as operation and installation costs for each unit are also provided. Keywords Network reliability · Power system operation · Power system planning · Real test system 1 Introduction Interests in studying reliability and operation issues together with power system planning have increased due to the important role played by these areas in the generation and transmission capacity expansion. For reliability studies, test systems such as theRBTS (Billinton 1989), IEEERTS (IEEE Reliability Test System 1979), and Korean southeast power system (Choi et al. 2006) have been introduced. On the other hand, Garver’s network (Garver 1970), Brazilian 46- , 78-, and 87-bus interconnections (Romero and Monticelli 1994; Romero et al. 2002), Colombian network (Escobar 2002; Escobar et al. 2004), IEEE 24-, 25-, and 30-bus sys- tems (Ekwue and Cory 1984; Fang and Hill 2003; Tor et al. B Ruben Romero ruben@dee.feis.unesp.br 1 Department of Electrical Engineering, Faculty of Engineering on Ilha Solteira Campus, São Paulo State University, Ilha Solteira, SP, Brazil 2 Department of Electrical Engineering, Shahid Beheshti University, Tehran, Iran 3 School of Electrical and Computer Engineering, College of Engineering, University of Tehran, Tehran, Iran 2010), Portuguese generation/transmission network (Braga and Saraiva 2005), and Iranian 18-bus regional and 400 kV national grids (Shayeghi and Mahdavi 2009; Maghouli et al. 2011) have been used for planning case studies. However, none of these case studies provides a simultaneous com- parison of the results obtained using different methods of planning, operation, and reliability. Thus, it is desirable to have a reference test system that incorporates the real basic data needed in power system planning, operation, and relia- bility evaluation. In existing test systems, the whole set of parameters needed for both planning and reliability applications is not provided. For example,Garver’s network and other case stud- ies about power system planning (Garver 1970; Romero and Monticelli 1994; Romero et al. 2002; Escobar 2002; Esco- bar et al. 2004; Ekwue and Cory 1984; Fang and Hill 2003; Tor et al. 2010; Braga and Saraiva 2005; Shayeghi and Mah- davi 2009; Maghouli et al. 2011) do not contain reliability and operation details. Moreover, reliability test systems as reported in (Billinton 1989; IEEE Reliability Test System 1979; Choi et al. 2006) do not include configuration and com- plete reliability information about substations [e.g., number, age and capacity of transformers at each bus, as well as their forced outage rate (FOR), forced outage duration (FOD), 123 http://crossmark.crossref.org/dialog/?doi=10.1007/s40313-017-0361-8&domain=pdf Journal of Control, Automation and Electrical Systems (2018) 29:192–208 193 Table 1 Seasonal peak load as percentages of annual peak Season (%) Winter (%) Spring (%) Summer (%) Autumn (%) Peak load 91.3 90.6 100 90.2 Table 2 Monthly peak load as percentages of seasonal peak Season Month Peak load (%) Season Month Peak load (%) Winter Jan. 99.3 Summer Jul. 98.2 Feb. 97.8 Aug. 100 Mar. 100 Sep. 94.1 Spring Apr. 85.9 Autumn Oct. 100 May 90.4 Nov. 89.6 Jun. 100 Dec. 88.5 Table 3 Weekly peak load as percentages of annual peak (%) W. Peak load W. Peak load W. Peak load W. Peak load W. Peak load W. Peak load W. Peak load W. Peak load 1 81.5 8 82.2 15 75.9 22 85 29 99.2 36 94 43 77.6 50 81.65 2 81.8 9 81.7 16 77.2 23 88.6 30 98.4 37 92.6 44 80 51 81.5 3 80 10 81.35 17 79 24 90.7 31 99 38 91 45 80.5 52 81.2 4 81.2 11 81.95 18 80 25 93.8 32 100 39 90.2 46 80 – – 5 81.5 12 75.6 19 82 26 93.2 33 98.95 40 85.7 47 80.4 – – 6 79.4 13 67.85 20 83.2 27 96.1 34 97.9 41 84.6 48 79.9 – – 7 81.4 14 74.4 21 85.8 28 97.3 35 96 42 81.8 49 80.6 – – and scheduled outage duration (SOD)]. Furthermore, data on future expansion (e.g., load growth and lengths of new right of ways considering geographical limitations), actual location of buses, line characteristics (e.g., bundled con- ductors and line types), reliability and construction costs, daily peak loads, load diversity between buses, and sched- uled outages of transmission lines such as repair rate and mean time to repair (MTTR) were also ignored. Besides, data regarding equipment age and substations configurations, which have important effects on planning decisions (Mah- davi et al. 2016), have not been considered by proposed test systems such as RTS. Reliability parameters such as genera- tors forced and scheduled outage duration, lines MTTR and repair rate, and transformers forced and scheduled outages could efficiently affect proposed expansion plans. However, these essential data have not provided by RTS and other reli- ability test systems. The main contribution of this work is to provide all the details and information required to evaluate methods and models developed for power system planning, operation, and reliability; i.e., gathering the different data required for study- ing an experimental power system from various aspects. It describes the reliability data, generation system characteris- tics, and transmission network details. This paper provides essential data on the expansion, operation, and reliability of an actual power system, which is part of the Iranian north interconnected network and well-known as the regional elec- tric company of Tehran (RECT). All expansion, operation, and reliability data, except for lost load and energy costs, are representative of the experiences of the RECT. The values for lost loads and costs of energy not supplied are based on reliability data fromCanada, because such expenses have not yet been calculated in Iran. This case study does not include distribution system configuration or protective relays data, because the aim is to define a system that is broad enough to provide a basis for reporting on analysis methods for combined generation/transmission expansion planning with composite power system reliability. 2 Description of Test System 2.1 Load Characteristics The annual peak load for the test system is 10729 MW. Table 1 describes the peak loads as a percentage of the annual 123 194 Journal of Control, Automation and Electrical Systems (2018) 29:192–208 Table 4 Daily peak load as percentages of weekly peak (%) Days Week number 1 2 3 4 5 6 7 8 9 10 11 12 13 Mon 98.6 100 99.95 99.4 100 100 98.2 100 98.3 99.5 100 100 100 Tue 98.3 97.4 99.6 99.8 99 94.95 98.9 98.6 99.1 98.5 98.2 80.4 99.795 Wed 99.3 89.4 98.7 99.8 99.4 82.1 98.6 99.5 99.3 99.4 97.6 83.6 99.4 Thu 95 92.6 91.2 94.7 95.3 80.3 95.2 94.4 95.5 96.6 95.3 83.9 99.2 Fri 90.3 87.8 89.7 89.5 90 88.6 90.5 89.7 92.8 92.35 91 83.8 96 Sat 99.1 96.2 99.9 98.8 97.8 92.6 99.5 97.75 100 100 94.7 85.1 95.4 Sun 100 96.6 100 100 96.6 99.3 100 97.9 98.5 99.4 93.2 89.6 93.5 Days 14 15 16 17 18 19 20 21 22 23 24 25 26 Mon 98 99.5 99.1 98.5 98.3 96.75 97.8 95.5 99.6 93.97 96 98.3 99.8 Tue 98 98 100 100 100 97.65 97.5 96.6 97.4 100 98.6 99.5 96.6 Wed 98.8 99.9 98.6 95.3 98 98.5 100 96.45 99.7 98 98.2 99.2 97.5 Thu 100 96.7 99.6 98 98 96.5 99.7 97.1 100 95.9 89.1 99.5 98.8 Fri 96.45 97.5 98.6 97.6 95.4 98.4 97 93.9 98.95 94.6 98.2 94.2 95.2 Sat 90.6 95 95.3 91.5 89.4 93 92 91.8 93.8 91.9 95.2 92.6 92.9 Sun 95.7 100 99.9 98.7 96.4 100 98.65 100 95.3 98.7 100 100 100 Days 27 28 29 30 31 32 33 34 35 36 37 38 39 Mon 98.6 95.1 100 97.9 100 100 98.65 98.8 100 99.45 100 100 99 Tue 98.1 99.6 99.7 98.95 99.7 99.2 99.65 98.5 99.5 100 99.8 98.7 100 Wed 100 94.8 98.9 98.5 98.35 98.3 100 98.7 96 97.5 98.9 93.345 98.2 Thu 99.9 98.4 97.6 98.6 98.9 97 97.7 96 95.7 97.3 98.4 99.1 96 Fri 96.6 97.3 95.75 96.5 95 96 95.65 90.9 93.4 93.5 94.3 96.945 92.7 Sat 92.9 93.8 91.1 92.4 93.65 89.9 95.8 90.9 90.7 89.8 89.7 91.9 88.1 Sun 97.5 100 97.7 100 98.7 97.1 99.8 98 98.8 98.6 97.7 99.9 95.3 Days 40 41 42 43 44 45 46 47 48 49 50 51 52 Mon 100 98.9 99.6 99.1 97.5 99.8 98.35 99 96.9 99 99.1 99.2 98.3 Tue 100 98.5 98.9 94.2 96.8 100 98.6 97.7 91.6 100 100 100 98 Wed 99.3 100 99 89 93.8 97.3 99.1 97.8 98 99.8 99.4 99.7 98.9 Thu 97.8 99.4 100 98.4 96.3 98 98.4 99.7 99.25 99.8 99 96.85 100 Fri 95.8 96 95.5 95.25 94.2 94.6 95.75 96.4 95.9 96.2 96.4 88.9 95.84 Sat 91.5 91 89.7 92.95 87.4 89.25 89.9 88.3 90.3 88.5 88.9 90 89.1 Sun 99.2 96.4 95.7 100 100 98.6 100 100 100 99.8 99.9 98.1 99.45 peak load for each season. This table is helpful for multi- stage power system expansion planning when the planners consider a multi-level load for the electrical power demand. Table 2 shows monthly peak loads as a percentage of the seasonal peak loads for each month. Three months in every season have been normalized with respect to the peak load of the corresponding season. For example, the peak load of January is stated as a percentage of winter peak load, and July is represented as a percentage of summer peak. Table 3 gives data on weekly peak loads as percentages of the annual peak load. Week 1 is taken the first week in January. The annual peak occurs at week 32. Table 4 lists daily peak loads as percentages of the weekly peak. The data in Table 4 define a daily peak load model of 52 × 7 = 364 days, with Monday as the first day of the year. Table 5 gives hourly load models for each of the four sea- sons. The first column reflects winter, while the second, third, and fourth columns indicate spring, summer, and autumn, respectively. Combining Tables 3, 4, and 5 with the annual peak load generates an hourly loadmodel of 364×24 = 8736 h. In simple terms, the annual load curve for 8736 hours is available and the planners can determine minimum andmax- imum load level in every day, week, month, season or year. 123 Journal of Control, Automation and Electrical Systems (2018) 29:192–208 195 Table 5 Hourly load as percentages of daily peak (%) Hour Winter Spring Summer Autumn 1 73 81 83.7 75 2 70 78.7 80.3 73.5 3 68 74 77.9 71 4 69 70 75.6 69 5 70 69 75 70 6 74 70.5 74.4 71.5 7 78 70 70.9 72 8 72 75 70.3 79 9 78 81 73.8 84 10 79 85 77.9 89 11 80 88 81.4 90 12 85 90 85.5 91.5 13 85 89 88.3 91 14 80 86 89.5 88 15 81 84 90.7 81.5 16 87 87 91.3 83 17 98 92 90.7 93 18 100 96 87.2 96 19 99 98 82.5 100 20 98 100 83 98 21 98.5 98.5 96 97 22 94 97 100 96 23 89 96 97 85 24 80 87 92.5 81 Minimum load would be useful for demand response and peak load shifting studies. The annual load factor for this model is 65. The annual load factor is equal to the annual average demand divided by the annual peak load. 2.2 Generation System Table 6 lists the generating unit ratings, the reduced-capacity duration (RCD), and reliability data (such as FOR,mean time to failure (MTTF), MTTR, FOD, and SOD), where RCD is the time that a generating unit is operated in derated state and can deliver partial output. FOD is the average time taken to repair the failed unit, i.e., FOD refers to the time necessary to execute corrective repairs, due to unexpected failures in a generating unit. On the other hand, SOD is the average duration of the time necessary to execute preventive repairs (maintenance), i.e., the generating unit was still working but a scheduled withdraw is done to correct specific defects in order to avoid forced outages (Mahdavi et al. 2017). Table 7 gives the operating data for the generating units, while the unit size and operating output of the generation mix are shown in Table 8. Table 9 gives the ages and the installation costs of the generating units for maintenance and planning applications. Moreover, fuel costs are suggested in Tables 10 and 11. These costs are subject to variation due to geographical location and other factors. Thus, in Table 10, nodal fuel transportation costs for power production are given. Finally, the generating unit operating costs (OCs), com- monly used in economic dispatch studies, can be calculated using the information presented in Tables 7, 10, 11, and 12. The calculation of the OCs is shown in (1), in terms of the fuel rate (FR; fourth column of Table 7), the heat rate (HR; sixth column of Table 7), the Transportation Cost (TC; third column of Table 10), the Toll (fourth column of Table 10), and the Price (second column of Table 11). Further infor- mation regarding capacity outage for the generating units is presented as an “Appendix”. OC = FR × HR × (TC+ Toll+ Price) (1) 2.3 Transmission Network The transmission network consists of 39 bus locations con- nected by 66 lines as shown in Fig. 1. The transmission lines are at two voltage levels: 230 and 400 kV. The locations of the generating units are shown in Table 12. Moreover, Table 12 shows the number of existing units in each generation bus and the maximum number of units (i.e., the sum of existing units and new units that can be installed in each generation bus). It can be seen that 13 out of the 39 buses are generating stations. Moreover, buses 7 and 32 are connected to the Ira- nian Interconnected Network (which is a large transmission systemwithmore than 200 buses); hence, they are considered slack buses. Table 13 provides data on generating unit reac- tive power capability for use in AC load flow calculations. Table 14 gives the reactive capability of voltage corrective devices. These devices help the system to maintain its rated voltage under contingency conditions. In addition, the annual peak load of the system is shown in Table 15. In Table 15, the load diversity between buses is provided by load type. Load types 1, 2, 3, 4, and 5 indicate domes- tic, public, agricultural, industrial, and commercial demands, respectively.Moreover, substation characteristics, such as the number and capacity of each transformer, and their reliability data are given in Table 16. It is important to remark that the reliability information presented in Table 16 includes all the devices within the substation (e.g., transformers, capacitors, and reactors). In buses with the two transmission voltage lev- els (5, 8, 12, 13, 19, 25, and 27), loads are connected to the 63 kV side. The value of lost load (VOLL) and cost of energy not supplied (cost of ENS) for each load type are given in Table 17. The VOLL of each bus was obtained by combining the data in Table 15 with Table 17. For example, the VOLL of bus 1 is equal to 0.5× 150+ 0.28× 500+ 0.02× 3500+ 123 196 Journal of Control, Automation and Electrical Systems (2018) 29:192–208 Table 6 Generating unit reliability data Unit size (MW) No. of units FOR MTTF (h) MTTR (h) FOD (h) SOD (h) RCD (h) 12.5 4 0.036 1607 60 6 14 2553 23.7 16 0.17 244 50 4.5 16 2941 24 4 0.073 1016 80 13 20 6031 25 5 0.17 195 40 6 9.5 2941 32 13 0.17 146.5 30 7 8.5 2941 38.5 3 0.072 902 70 10 22 6031 82.5 3 0.08 460 40 6.5 8.5 1920 85 3 0.017 2024 35 4 11 2941 100 2 0.06 1097 70 3 4 1004 102 3 0.019 2840 55 14.5 30 1655 105 3 0.017 3469 60 6 13 2070 116.2 6 0.019 1549 30 5 17 1655 123.8 6 0.17 220 45 7 9 2070 128.5 4 0.06 940 60 3 3 1004 156.5 4 0.09 607 60 4 4 1090 159 12 0.022 1778 40 8 22 2930 161 4 0.15 340 60 8 15 5324 166 5 0.04 960 40 8 10 980 250 4 00.005 7960 40 11 3.8 2070 263 3 0.09 708 70 3 7 1050 318 5 0.035 2206 80 10 18 3240 322 1 0.15 567 100 10 20 980 332 1 0.04 2400 100 10 20 5324 526 3 0.095 1429 150 10 30 1050 0.09× 1500+ 0.11× 4500 = 915 $/MW. The cost of ENS for bus 39 is 4.17 $/kWh (0.455 × 0.56 + 0.15 × 1.45 + 0.05× 14+ 0.245× 5.5+ 0.1× 16.5). Furthermore, Table 18 illustrates the average annual load growth of each bus. Figure 1 defines the actual geographical connections for the transmission network. The line lengths, which are shown in Tables 19 and 20, determine the physical bus locations in Fig. 1. Table 19 includes the number of cir- cuits and bundled conductors, line voltage levels and types, transmission reliability data, and line ages for an actual network. Line ages show when a transmission line was constructed in the network. Types 1, 2, and 3 indicate Canary, Cardi- nal, and Curlew conductors, while type 4 explains that the connection between the two buses is provided by cables. The length of each corridor is not a direct route between two buses. All distances have been calculated considering geographical limitations such as hills, forests, parks, roads, highways, farms, and other barriers. Table 20 gives the practical lengths of all candidate corridors for transmission network expansion, considering geographical restrictions. Impedance, rating data and construction cost for the lines are listed in Table 21. TheRECTsystem represents the 23 and20%of the Iranian interconnected network total generation and consumption, respectively. Besides, its transmission and distribution power losses are 3.5 and 13.5%of the interconnected network power losses, respectively. The RECT system is the first ranked network in power generation and demand among all regional electric companies in Iran. In addition, each year the RECT system sales 5966 MWh and buys 3777 MWh to/from the interconnected network. Furthermore, annual average outage durations of 400 and230kV lines inRECTsystemare 7.2 and 7.7 h, respectively. Finally, average duration of each outage for 400 and 230 kV substations in RECT system is 5.9 and 30.5 h, respectively. 3 Conclusion A real test system known as regional electric company of Tehran (RECT) system, which is part of the Iranian north interconnected network, has been presented in this work, including the reliability data, generation system character- istics, and transmission network details. The presented data allow to incorporate various real parameters into experimen- tal integrated models, contributing to the research on power 123 Journal of Control, Automation and Electrical Systems (2018) 29:192–208 197 Table 7 Generating unit operating data Size MW Type Fuel type Fuel rate lit/kcal Max. output MW Heat rate kcal/kW 12.5 Fossil Oil 1.0114 10 3958 Steam 23.7 Comb. Oil 0.8566 20 3702 Turbine Gasoil 0.1463 24 Hydro – – 24 – 25 Comb. Oil 0.8566 20 3702 Turbine Gasoil 0.1463 32 Comb. Oil 0.8566 26 3702 Turbine Gasoil 0.1463 38.5 Hydro – – 38.5 – 82.5 Fossil Gasoil 0.0073 75 2960 Steam Gas 0.7356* Oil 0.237 85 Comb. Oil 0.8566 70 3702 Turbine Gasoil 0.1463 100 Combined Gasoil 0.093 100 1874 Cycle Gas 0.9123* 102 Combined Gasoil 1.481 100 1875 Cycle Gas 0.853* 105 Combined Gasoil 0.0763 100 1987 Cycle Gas 0.93* 116.2 Combined Gasoil 1.481 96.5 1875 Cycle Gas 0.853* 123.8 Combined Gasoil 0.0763 100 1987 Cycle Gas 0.93* 128.5 Combined Gasoil 0.093 106 1874 Cycle Gas 0.9123* 156.5 Fossil Gasoil 0.0075 150 2502 Steam Gas 0.642* Oil 0.319 159 Comb. Oil 0.77 135 3063 Turbine Gasoil 0.231 161 Combined Gasoil 0.0898 160 1850 Cycle Gas 0.662* 166 Comb. Oil 0.395 160 3500 Turbine Gasoil 0.0576 250 Fossil Gasoil 0.00007 250 2124 Steam Gas 0.661* Oil 0.31 263 Comb. Oil 0.149 250 3700 Turbine 318 Comb. Oil 0.631 300 4000 Turbine 322 Combined Gasoil 0.0898 320 1850 Cycle Gas 0.662* 332 Comb. Oil 0.395 320 3500 Turbine Gasoil 0.0576 526 Comb. Oil 0.149 500 3700 Turbine * m3/kcal 123 198 Journal of Control, Automation and Electrical Systems (2018) 29:192–208 Table 8 Generation mix Type Unit size (MW) Operating output (MW) Fossil steam 1923.5 1865 Combustion turbine 8202.2 7458 Combined cycle 3741 3363 Hydro 211.5 211.5 Total 14,078.2 12897.5 Table 9 Unit ages (year) and installation costs (Million$) Size MW Age Cost Size MW Age Cost 12.5 56 10 123.8 21 111 23.7 37 20 128.5 22 116 24 9 14 156.5 42 125 25 37 21 159 10 135 32 37 27 161 6 145 38.5 27 23 166 6 141 82.5 47 66 250 23 200 85 37 72 263 8 224 100 17 90 318 9 270 102 15 92 322 6 290 105 14 95 332 5 282 116.2 23 105 526 8 447 Table 10 Fuel expenses Bus Fuel Transportation cost Toll 4 Gas 0.000004 ($/m3) 0.000058 ($/m3) Gasoil 0.0000078 ($/lit) 0.00011 ($/lit) 7 Gas 0.0000052 ($/m3) 0.000058 ($/m3) Oil 0.0000049 ($/lit) 0.000055 ($/lit) Gasoil 0.0000097 ($/lit) 0.00011 ($/lit) 10 Gas 0.0000035 ($/m3) 0.000093 ($/m3) Oil 0.0000033 ($/lit) 0.000089 ($/lit) Gasoil 0.0000066 ($/lit) 0.00018 ($/lit) 11 Gas 0.0000035 ($/m3) 0.000093 ($/m3) Gasoil 0.0000066 ($/lit) 0.00018 ($/lit) 17 Oil 0 0 23 Gas 0.0000067 ($/lit) 0.000054 ($/m3) Oil 0.0000064 ($/lit) 0.000052 ($/lit) Gasoil 0.000013 ($/lit) 0.0001 ($/lit) 30 Oil 0.0000083 ($/lit) 0.00013 ($/lit) 31 Oil 0.0000088 ($/lit) 0.00013 ($/lit) Gasoil 0.0000057 ($/lit) 0.00026 ($/lit) 32 Oil 0.00000324 ($/lit) 0.000095 ($/lit) Gasoil 0.00000647 ($/lit) 0.000187 ($/lit) 33 Gas 0.0000038 ($/m3) 0.00011 ($/m3) Gasoil 0.0000076 ($/lit) 0.00022 ($/lit) 34 Oil 0.0000036 ($/lit) 0.00011 ($/lit) Gasoil 0.0000072 ($/lit) 0.0002 ($/lit) 36 Oil 0.0000039 ($/lit) 0.00011 ($/lit) system expansion planning, operation, and reliability. Due to their small size, widely known test systems (e.g., Garver’s Table 11 Fuel prices Fuel Price Gas 0.00307 ($/m3) Oil 0.00293 ($/lit) Gasoil 0.00586 ($/lit) Table 12 Generating unit locations Bus Size (MW) No. of existing units Max. number of units 4 161 4 8 322 1 5 6 24 4 8 38.5 3 6 7 105 3 6 123.8 6 10 250 4 8 10 156.5 4 8 11 102 3 6 116.2 6 10 17 12.5 4 8 23 82.5 3 6 30 318 5 8 31 23.7 16 20 25 5 8 32 13 16 85 3 6 32 159 12 16 33 100 2 5 128.5 4 8 34 166 5 8 332 1 5 36 263 3 6 526 3 6 network and RBTS) may not adequately show the accu- racy of proposed models. On the other hand, due to lack of information, larger test systems (e.g., RTS and Brazilian interconnections) may not be of use to authors of techni- cal papers. Thus, the complete set of information exposed makes the presented test system highly useful to researchers in order to demonstrate robustness and effectiveness of pro- posedmethodologies, evaluating present and future scenarios in the power system considering reliability and economic aspects. 123 Journal of Control, Automation and Electrical Systems (2018) 29:192–208 199 Fig. 1 RECT system 123 200 Journal of Control, Automation and Electrical Systems (2018) 29:192–208 Table 13 Generating unit reactive capability Unit size (MW) MVAr Unit size (MW) MVAr Min Max Min Max 12.5 0 8 123.8 − 25 60 23.7 0 10 128.5 0 40 24 0 10 156.5 0 25 25 0 10 159 0 85 32 − 10 15 161 0 85 38.5 − 10 15 166 − 20 45 82.5 0 35 250 − 40 130 85 − 25 35 263 0 70 100 − 25 30 318 − 25 90 102 0 45 322 − 50 170 105 − 30 50 332 0 90 116.2 − 35 55 526 − 50 150 Table 14 Voltage correction devices Bus Device Amount of devices Capability of each device (MVAr) Total capability (MVAr) Failure rate (h) MTTR (h) FOD (h) 2 Capacitor 2 20 40 0.2 20 2 3 Capacitor 2 20 40 0.22 18 1.8 8 Reactor 4 25 100 0.16 24 0.7 10 Capacitor 2 20 40 0.25 26 0.9 12 Reactor 1 25 25 0.15 25 0.6 16 Capacitor 2 10 20 0.22 32 1.5 17 Capacitor 2 20 40 0.28 16 2.5 19 Reactor 4 25 100 0.14 20 0.2 21 Capacitor 2 20 40 0.18 28 0.7 27 Reactor 2 25 50 0.14 30 1.4 32 Reactor 3 50 150 0.17 35 0.8 36 Reactor 2 50 100 0.16 22 0.3 Table 15 Bus load data Bus Load Portion of load type from active bus load % MW MVAr Type 1 2 3 4 5 1 138 34 50 28 2 9 11 2 211 70 50 28 2 9 11 3 339 250 50 28 2 9 11 4 66 29 50 28 2 9 11 5 125 57 50 28 2 9 11 8 550 260 40 31 0.04 15 14 9 190 68 40 31 0.04 15 14 10 350 175 40 31 0.04 15 14 11 170 96 40 31 0.04 15 14 12 290 200 40 31 0.04 15 14 13 620 350 40 31 0.04 15 14 14 34 20 40 31 0.04 15 14 15 290 154 40 31 0.04 15 14 123 Journal of Control, Automation and Electrical Systems (2018) 29:192–208 201 Table 15 continued Bus Load Portion of load type from active bus load % MW MVAr Type 1 2 3 4 5 16 354 210 39 20.5 5.5 30 5 17 234 90 39 20.5 5.5 30 5 18 480 220 50 28 2 9 11 19 800 280 50 28 2 9 11 20 210 116 50 28 2 9 11 21 315 219 50 28 2 9 11 22 168 96 40.5 28.5 0 4 27 23 175 9 40.5 28.5 0 4 27 24 206 116 45.5 15 5 24.5 10 25 780 260 39 17 5.5 30 8.5 26 746 390 40.5 28.5 0 4 27 27 720 360 45.5 15 5 24.5 10 28 268 114 42 16 2.5 24 15.5 29 6 1 42 16 2.5 24 15.5 30 230 92 42 16 2.5 24 15.5 31 278 42 42 16 2.5 24 15.5 33 128 42 37.5 13.5 15.5 26 7.5 34 240 150 37.5 13.5 15.5 26 7.5 35 64 20 37.5 13.5 15.5 26 7.5 37 404 268 40.5 28.5 0 4 27 38 250 120 40 31 0.04 15 14 39 300 144 45.5 15 5 24.5 10 Total load 10729 MW 5122 MVAr Table 16 Substation data: capacity and reliability Bus Voltage (kV) Capacity of transformers (MVA) Failure rate (1/year) Failure duration (h) Repair rate (1/year) Repair duration (h) Age (year) 1 230/63 2× 160 0.96 4.5 7 8 13 2 230/63 1× 80 0.9 9.5 11 9 42 3× 90 0.8 8 12 7 42 3 230/63 3× 180 0.85 5.5 9 7 42 4 15/230 4× 200 0.75 6.5 15 6 20 19/230 1× 350 0.75 6.5 15 6 20 5 400/230/63 2× 500 0.1 2 6.5 6.5 7 6 13.8/230 7× 40 0.75 6.5 15 6 27 7 10.5/400 3× 125 0.1 2 6.5 6.5 14 13.8/400 6× 154 0.1 2 6.5 6.5 21 19/400 4× 312.5 0.1 2 6.5 6.5 23 8 400/230/63 2× 500 0.05 3 5 8 37 9 230/63 2× 160 0.96 4.5 7 8 14 10 15/230 4× 160 0.7 5 6 10 45 11 13.8/230 6× 140 0.7 5 6 10 13 10.5/230 3× 125 0.7 5 6 10 13 123 202 Journal of Control, Automation and Electrical Systems (2018) 29:192–208 Table 16 continued Bus Voltage (kV) Capacity of transformers (MVA) Failure rate (1/year) Failure duration (h) Repair rate (1/year) Repair duration (h) Age (year) 12 400/230/63 1× 500 0.05 3 5 8 13 1× 500 0.05 3 5 8 10 13 400/230/63 2× 500 0.05 3 5 8 40 14 230/63 1× 160 0.96 4.5 7 8 15 15 230/63 2× 250 0.7 5 6 10 10 16 230/63 3× 180 0.85 5.5 9 7 40 17 11.5/230 4× 35 0.828 6.5 10 7.8 44 18 230/63 3× 180 0.85 5.5 9 7 26 1× 180 0.85 5.5 9 7 11 19 400/230/63 2× 500 0.05 3 5 8 35 20 230/63 2× 160 0.96 4.5 7 8 17 21 230/63 3× 180 0.85 5.5 9 7 41 22 230/63 2× 180 0.85 5.5 9 7 16 23 13.8/230 3× 100 0.1 2 6.5 6.5 49 24 230/63 2× 160 0.96 4.5 7 8 18 25 400/230/63 2× 500 0.05 3 5 8 34 1× 500 0.05 3 5 8 14 1× 500 0.05 3 5 8 7 26 230/63 2× 180 0.85 5.5 9 7 25 230/63 1× 180 0.85 5.5 9 7 10 230/20 2× 90 0.8 8 12 7 25 27 400/230/63 2× 500 0.05 3 5 8 29 28 230/63 2× 160 0.96 4.5 7 8 21 29 230/20 2× 40 0.75 6.5 15 6 12 30 19/230 5× 350 0.7 5 6 10 13 31 11.5/230 16× 35 0.7 5 6 10 33 10.5/230 5× 35 0.7 5 6 10 33 11/230 13× 40 0.7 5 6 10 33 11/230 3× 110 0.7 5 6 10 33 32 15.75/400 12× 200 0.1 2 6.5 6.5 41 33 11.5/230 2× 137.5 0.7 5 6 10 38 13.8/230 4× 126 0.7 5 6 10 38 34 15/230 5× 200 0.7 5 6 10 21 19/230 1× 350 0.7 5 6 10 21 35 230/63 2× 40 0.75 6.5 15 6 11 36 15.75/400 3× 312.5 0.1 2 6.5 6.5 31 19/400 3× 550 0.1 2 6.5 6.5 31 37 230/63 3× 180 0.85 5.5 9 7 21 230/20 2× 90 0.8 8 12 7 21 38 400/63 2× 200 0.15 1 8 5 6 39 400/63 2× 200 0.15 1 8 5 7 123 Journal of Control, Automation and Electrical Systems (2018) 29:192–208 203 Table 17 Costs of lost load and energy Load type 1 2 3 4 5 VOLL ($/MW) 150 500 3500 1500 4500 Cost of ENS ($/kWh) 0.56 1.45 14 5.5 16.5 Table 18 Load growth data (%) Bus Load type 1 2 3 4 5 1 6.2 9.3 7.6 2 14 2 6.2 9.3 7.6 2 14 3 6.2 9.3 7.6 2 14 4 6.2 9.3 7.6 2 14 5 6.2 9.3 7.6 2 14 8 3.9 7.9 17 4.8 13 9 3.9 7.9 17 4.8 13 10 3.9 7.9 17 4.8 13 11 3.9 7.9 17 4.8 13 12 3.9 7.9 17 4.8 13 13 3.9 7.9 17 4.8 13 14 3.9 7.9 17 4.8 13 15 3.9 7.9 17 4.8 13 16 9.3 10 9.5 8.3 8.6 17 9.3 10 9.5 8.3 8.6 18 6.2 9.3 7.6 2 14 19 6.2 9.3 7.6 2 14 20 6.2 9.3 7.6 2 14 21 6.2 9.3 7.6 2 14 22 3.2 18 0 6.6 6 23 3.2 18 0 6.6 6 24 6.1 8.3 14 5.8 7.2 25 9.3 10 9.5 8.3 8.6 26 3.2 18 0 6.6 6 27 6.1 8.3 14 5.8 7.2 28 6.4 2.8 4.8 7 7.1 29 6.4 2.8 4.8 7 7.1 30 6.4 2.8 4.8 7 7.1 31 6.4 2.8 4.8 7 7.1 33 11 15 5.4 10 8 34 11 15 5.4 10 8 35 11 15 5.4 10 8 37 3.2 18 0 6.6 6 38 3.9 7.9 17 4.8 13 39 6.1 8.3 14 5.8 7.2 123 204 Journal of Control, Automation and Electrical Systems (2018) 29:192–208 Table 19 Transmission line data Corr Length (km) Number of circuits Number of bundled conductors Type Voltage (kV) Failure rate (1/year) Failure duration (h) Repair rate (1/year) Repair duration (h) Age (year) 1–2 9.5 1 2 1 230 0.15 4 0.3 11 13 1–19 21.5 1 2 1 230 0.3 4 0.33 11 13 2–3 17 1 2 1 230 0.26 4 0.33 11 40 2–11 55 1 2 1 230 0.85 6 0.4 15 19 2–20 15 1 2 1 230 0.23 4 0.32 11 18 3–13 30 1 2 1 230 0.46 4 0.35 11 19 4–5 20 1 1 1 230 0.3 3 0.33 10 10 5–6 9 1 1 1 230 0.14 3 0.31 10 11 5–32 75 2 3 3 400 0.7 11 0.52 35 9 5–38 50 2 3 3 400 0.47 9 0.47 25 8 6–23 53 2 1 1 230 0.8 5 0.4 12 30 7–8 25 2 3 3 400 0.23 6 0.43 15 26 7–12 110 2 3 3 400 1.03 13 0.59 40 7 7–36 110 2 3 3 400 1.02 13 0.58 40 16 8–9 33 1 1 2 230 0.5 3 0.36 10 14 8–12 82 1 3 3 400 0.77 11 0.53 35 14 8–13 101 1 3 3 400 0.95 11 0.57 35 16 9–15 23 1 1 2 230 0.35 3 0.34 10 14 10–11 3 2 2 1 230 0.05 4 0.3 11 20 10–15 18 1 1 2 230 0.27 3 0.33 10 21 10–25 31 1 2 1 230 0.48 4 0.35 11 40 11–12 18 2 2 1 230 0.27 4 0.33 11 13 11–15 17 1 2 1 230 0.26 4 0.33 11 8 11–25 28 1 1 1 230 0.43 3 0.35 10 49 12–13 17 2 2 3 400 0.26 4 0.33 11 14 12–15 7 1 2 1 230 0.11 4 0.3 11 8 12–38 25 2 3 3 400 0.23 6 0.43 15 9 13–14 10 1 2 2 230 0.15 4 0.31 11 8 13–16 11 1 2 1 230 0.17 4 0.31 11 40 13–17 8 2 2 1 230 0.12 4 0.31 11 40 13–18 14 1 2 2 230 0.21 4 0.32 11 15 13–25 24 1 2 1 230 0.37 4 0.34 11 40 14–18 7 1 2 2 230 0.11 4 0.33 11 8 16–25 13 1 2 1 230 0.2 4 0.32 11 40 17–23 15 1 1 1 230 0.23 4 0.32 11 7 17–25 14 2 1 1 230 0.21 3 0.32 10 10 19–20 9 1 2 1 230 0.13 4 0.31 11 18 19–21 8 1 2 1 230 0.12 4 0.12 11 41 19–27 32 1 2 1 230 0.49 4 0.36 11 18 19–32 62 2 3 3 400 0.58 9 0.5 25 12 21–27 27 1 2 1 230 0.42 4 0.35 11 16 21–24 9 1 1 1 230 0.13 4 0.31 11 1 22–31 19 1 1 2 230 0.29 3 0.33 10 17 22–37 4.5 – – 4 230 0 0 0.2 16 11 23–25 15 2 1 1 230 0.23 3 0.32 10 49 24–27 20 2 2 1 230 0.31 4 0.33 11 17 123 Journal of Control, Automation and Electrical Systems (2018) 29:192–208 205 Table 19 continued Corr Length (km) Number of circuits Number of bundled conductors Type Voltage (kV) Failure rate (1/year) Failure duration (h) Repair rate (1/year) Repair duration (h) Age (year) 25–26 6 2 2 2 230 0.09 4 0.3 11 29 25–28 11.5 1 1 2 230 0.18 3 0.31 10 11 25–30 40 2 2 2 230 0.62 6 0.37 15 7 25–31 15 1 1 2 230 0.23 3 0.32 10 11 25–36 46 2 3 3 400 0.43 9 0.47 25 34 26–37 12 – – 4 230 0 0 0.25 16 11 27–31 17 2 1 1 230 0.26 3 0.33 10 29 27–32 28 1 2 3 400 0.26 5 0.43 12 15 27–39 18 1 2 3 400 0.17 5 0.41 12 7 28–29 18 1 1 1 230 0.28 3 0.33 10 12 28–31 21.5 1 1 2 230 0.33 3 0.33 10 11 28–34 120 1 1 1 230 1.85 8 0.54 20 4 29–30 13 1 1 1 230 0.2 3 0.32 10 12 29–31 38 1 1 1 230 0.58 5 0.37 12 12 29–33 115 1 1 1 230 1.77 7 0.53 18 12 30–34 145 1 1 1 230 2.23 8 0.6 20 12 32–36 100 2 3 3 400 0.93 10 0.56 309 34 32–39 18 1 2 3 400 0.17 5 0.41 12 7 33–34 20 3 2 1 230 0.31 4 0.33 11 22 33–35 40 2 1 1 230 0.61 5 0.37 12 9 34–35 30 1 1 1 230 0.46 4 0.35 11 2 Table 20 Corridor length Corr Length (km) Corr Length (km) Corr Length (km) Corr Length (km) Corr Length (km) Corr Length (km) 1–3 22 2–14 15 6–13 55 10–12 19 13–39 12 25–29 30 1–4 70 2–18 14 6–14 8 10–13 25 14–17 14 25–37 14 1–5 65 2–19 10 6–18 10 10–16 25 14–19 18 26–27 10 1–6 12 2–21 10 6–19 6 10–26 42 14–20 13 26–28 8 1–8 100 3–4 55 6–20 7 10–28 40 14–37 14 26–29 12 1–9 60 3–5 65 7–13 127 11–13 26 14–38 6 26–30 15 1–10 52 3–6 7 7–23 60 11–14 33 15–16 25 26–33 120 1–11 50 3–8 41 7–25 47 11–16 25 15–25 15 27–28 25 1–12 32 3–10 42 8–10 65 11–26 40 15–28 21 27–29 60 1–13 21 3–11 40 8–11 66.5 11–28 40 16–18 14.5 27–30 50 1–14 9 3–12 35 8–15 45 12–14 22 16–28 16 27–37 11 1–18 10 3–18 14 8–23 30 12–16 14 17–38 14 28–30 35 1–20 15 3–19 8 8–25 60 12–18 24 18–20 7 28–33 110 1–21 20 4–6 7 8–26 10 12–19 35 18–37 10 28–37 14 1–37 25 4–19 58 8–28 65 12–20 28 19–23 16 29–34 120 123 206 Journal of Control, Automation and Electrical Systems (2018) 29:192–208 Table 20 continued Corr Length (km) Corr Length (km) Corr Length (km) Corr Length (km) Corr Length (km) Corr Length (km) 2–4 65 4–21 65 9–10 45 12–25 40 19–26 24 29–35 140 2–5 75 4–24 70 9–11 47 12–28 32 19–38 18 30–31 28 2–6 7 5–13 80 9–12 57 12–37 31 20–21 9 30–33 123 2–8 105 5–19 30 9–13 70 12–39 20 21–26 17 30–35 147 2–9 65 5–21 40 9–16 55 13–19 35 22–26 7 31–33 150 2–10 55 5–24 45 9–25 41 13–20 18 22–28 16 31–35 180 2–12 35 6–11 65 9–26 66 13–28 22 23–27 6 31–37 20 2–13 24 6–12 45 9–28 47 13–37 21 24–26 14 36–39 70 Table 21 Impedance, rating data (Sb = 100 MVA) and construction costs (Haddadian et al. 2011) Voltage (kV)Type Number of bundled conduc- tors Rating (P.U.) Resistance (P.U./km) ×10e−4 Reactance (P.U./km) ×10e−4 Susceptance (P.U./km) ×10e−4 Constant cost ($)×10e3 Variable cost ($)×10e3 230 CANARY 1 4 1.22 3.85 19 500 42 2 8 0.61 2.84 24 500 43 CARDINAL1 4.5 1.16 3.85 19 500 45 2 8.5 0.58 2.82 24.5 500 46 Cable – 3.45 1 16 3200 200 60 400 CERLEW 1 7.5 0.35 1.24 58 1600 85 2 15 0.175 0.97 74 1600 86.5 3 25 0.115 0.86 83 1600 87 Appendix: Capacity Outage Probability Cal- culation Several indices can be calculated in transmission systems in order to asses the operation reliability. Hereby, the capac- ity outage probability for the RECT system is presented in Table 22, enabling the calculation of the main reliability cri- teria (e.g., loss of load probability (LOLP) and loss of load expectation (LOLE)) in further studies. Table 22 includes the capacity outage probabilities (COP) in the range of 0– 100 MW. 123 Journal of Control, Automation and Electrical Systems (2018) 29:192–208 207 Table 22 Capacity outage probability table (0–100 MW) Cap. out (MW) Cap. in (MW) Ind. prob. Cum. prob. Cap. out (MW) Cap. in (MW) Ind. prob. Cum. prob. 0 14,078.2 1.01E−05 1.0000000000 79.7 = 32+ 23.7+ 24 13,998.5 5.86E−06 0.9992957224 12.5 14,065.7 1.50E−06 0.9999899350 80 = 2× 24+ 32 13,998.2 9.97E−07 0.9992898640 23.7 14,054.5 3.30E−05 0.9999884315 80.7 = 2× 12.5+ 23.7+ 32 13,997.5 7.35E−07 0.9992888668 24 14,054.2 3.17E−06 0.9999554465 81 = 2× 12.5+ 32+ 24 13,997.2 7.06E−08 0.9992881319 25 14,053.2 1.03E−05 0.9999451385 82 = 2× 25+ 32 13,996.2 1.12E−05 0.9992880612 25 = 2× 12.5 14,053.2 8.42E−08 0.9999348305 82 = 4× 12.5+ 32 13,996.2 5.21E−11 0.9992768182 32 14,046.2 3.30E−05 0.9999347463 82.5 13,995.7 2.63E−06 0.9992768182 36.2 = 12.5+ 23.7 14,042 1.61E−05 0.9999017613 83.6 = 3× 23.7+ 12.5 13,994.6 6.20E−06 0.9992741925 36.5 = 12.5+ 24 14,041.7 4.74E−07 0.9998856143 83.9 = 12.5+ 2× 23.7+ 24 13,994.3 2.38E−06 0.9992679915 37.5 = 3× 12.5 14,040.7 2.10E−09 0.9998851407 84.2 = 12.5+ 23.7+ 2× 24 13,994 9.94E−07 0.9992656074 37.5 = 12.5+ 25 14,040.7 1.54E−06 0.9998851386 84.5 = 3× 24+ 12.5 13,993.7 2.94E−09 0.9992646132 38.5 14,039.7 2.34E−06 0.9998835989 84.9 = 12.5+ 2× 23.7+ 25 13,993.3 7.75E−06 0.9992646103 44.5 = 12.5+ 32 14,033.7 4.00E−06 0.9998812526 84.9 = 2× 23.7+ 3× 12.5 13,993.3 1.06E−08 0.9992568591 47.4 = 2× 23.7 14,030.8 5.07E−05 0.9998772529 85 13,993.2 5.22E−07 0.9992568486 47.7 = 23.7+ 24 14,030.5 1.04E−05 0.9998265839 85.2 = 3× 12.5+ 23.7+ 24 13,993 2.16E−09 0.9992563264 48 = 2× 24 14,030.2 3.75E−07 0.9998161939 85.5 = 2× 24+ 3× 12.5 13,992.7 6.70E−11 0.9992563242 48.7 = 23.7+ 25 14,029.5 3.38E−05 0.9998158561 85.5 = 12.5+ 25+ 2× 24 13,992.7 5.73E−08 0.9992563242 48.7 = 2× 12.5+ 23.7 14,029.5 2.76E−07 0.9997820771 85.9 = 2× 23.7+ 38.5 13,992.3 1.18E−05 0.9992562669 49 = 24+ 25 14,029.2 3.25E−06 0.9997818011 86.2 = 38.5+ 23.7+ 24 13,992 2.42E−06 0.9992444729 49 = 2× 12.5+ 24 14,029.2 2.65E−08 0.9997785542 86.2 = 12.5+ 23.7+ 2× 25 13,992 1.42E−06 0.9992420545 50 = 4× 12.5 14,028.2 1.96E−11 0.9997785277 86.2 = 3× 12.5+ 23.7+ 25 13,992 7.04E−09 0.9992406306 50 = 2× 25 14,028.2 4.22E−06 0.9997785277 86.5 = 2× 24+ 38.5 13,991.7 8.72E−08 0.9992406236 50 = 2× 12.5+ 25 14,028.2 8.63E−08 0.9997743053 86.5 = 12.5+ 2× 25+ 24 13,991.7 1.99E−07 0.9992405364 51 = 12.5+ 38.5 14,027.2 3.50E−07 0.9997742191 86.5 = 3× 12.5+ 25+ 24 13,991.7 6.76E−10 0.9992403377 55.7 = 23.7+ 32 14,022.5 8.78E−05 0.9997738692 87.2 = 2× 12.5+ 23.7+ 38.5 13,991 6.42E−08 0.9992403370 56 = 24+ 32 14,022.2 8.44E−06 0.9996860432 87.5 = 2× 25+ 3× 12.5 13,990.7 8.80E−10 0.9992402728 57 = 25+ 32 14,021.2 2.74E−05 0.9996776014 87.5 = 3× 25+ 12.5 13,990.7 1.29E−07 0.9992402719 57 = 2× 12.5+ 32 14,021.2 2.24E−07 0.9996501554 87.5 = 2× 12.5+ 38.5+ 24 13,990.7 6.17E−09 0.9992401427 59.9 = 12.5+ 2× 23.7 14,018.3 7.57E−06 0.9996499312 87.7 = 2× 32+ 23.7 13,990.5 1.08E−04 0.9992401365 60.2 = 12.5+ 23.7+ 24 14,018 1.55E−06 0.9996423624 88 = 2× 32+ 24 13,990.2 1.04E−05 0.9991322065 60.5 = 12.5+ 2× 24 14,017.7 5.59E−08 0.9996408104 88.5 = 2× 25+ 38.5 13,989.7 9.83E−07 0.9991218325 61.2 = 3× 12.5+ 23.7 14,017 6.87E−09 0.9996407545 89 = 2× 32+ 25 13,989.2 3.37E−05 0.9991208497 61.2 = 12.5+ 23.7+ 25 14,017 5.05E−06 0.9996407476 89 = 2× 12.5+ 2× 32 13,989.2 2.76E−07 0.9990871207 61.5 = 3× 12.5+ 24 14,016.7 6.60E−10 0.9996357017 89.5 = 2× 38.5+ 12.5 13,988.7 2.72E−08 0.9990868451 61.5 = 12.5+ 24+ 25 14,016.7 4.85E−07 0.9996357010 91.9 = 12.5+ 2× 23.7+ 32 13,986.3 2.02E−05 0.9990868180 62.2 = 23.7+ 38.5 14,016 7.68E−06 0.9996352160 92.5 = 12.5+ 32+ 2× 24 13,985.7 1.49E−07 0.9990666650 62.5 = 24+ 38.5 14,015.7 7.38E−07 0.9996275386 93.2 = 3× 12.5+ 23.7+ 32 13,985 1.83E−08 0.9990665160 62.5 = 12.5+ 2× 25 14,015.7 6.31E−07 0.9996268007 93.5 = 3× 12.5+ 32+ 24 13,984.7 1.76E−09 0.9990664977 62.5 = 3× 12.5+ 25 14015.7 2.15E−09 0.9996261700 94.8 = 4× 23.7 13983.4 2.76E−05 0.9990664960 63.5 = 25+ 38.5 14,014.7 2.40E−06 0.9996261679 95 = 12.5+ 82.5 13,983.2 3.92E−07 0.9990388630 63.5 = 2× 12.5+ 38.5 14,014.7 6.53E−09 0.9996237687 95.1 = 3× 23.7+ 24 13,983.1 1.31E−05 0.9990384708 64 = 2× 32 14,014.2 3.29E−05 0.9996237622 95.4 = 2× 23.7+ 2× 24 13,982.8 1.89E−06 0.9990253948 68.2 = 12.5+ 23.7+ 32 14,010 1.31E−05 0.9995908272 95.7 = 3× 24+ 23.7 13,982.5 6.44E−08 0.9990235095 68.5 = 12.5+ 24+ 32 14,009.7 1.26E−06 0.9995777082 96 = 4× 24 13,982.2 3.87E−10 0.9990234451 69.5 = 3× 12.5+ 32 14,008.7 5.88E−07 0.9995764472 96 = 3× 32 13,982.2 2.47E−05 0.9990234447 70.5 = 32+ 38.5 14,007.7 6.24E−06 0.9995758593 96.1 = 2× 12.5+ 3× 23.7 13,982.1 3.47E−07 0.9989987107 123 208 Journal of Control, Automation and Electrical Systems (2018) 29:192–208 Table 22 continued Cap. out (MW) Cap. in (MW) Ind. prob. Cum. prob. Cap. out (MW) Cap. in (MW) Ind. prob. Cum. prob. 71.1 = 3× 23.7 14,007.1 4.15E−05 0.9995696214 96.1 = 3× 23.7+ 25 13,982.1 4.25E−05 0.9989983633 71.4 = 2× 23.7+ 24 14,006.8 1.60E−05 0.9995281094 96.4 = 25+ 2× 23.7+ 24 13,981.8 1.63E−05 0.9989558513 71.7 = 23.7+ 2× 24 14,006.5 1.23E−06 0.9995121494 96.4 = 2× 12.5+ 2× 23.7+ 24 13,981.8 1.47E−08 0.9989395063 72 = 3× 24 14,006.2 1.97E−08 0.9995109221 96.7 = 25+ 23.7+ 2× 24 13,981.5 1.26E−06 0.9989394916 72.4 = 2× 23.7+ 25 14,005.8 5.19E−05 0.9995109024 97 = 2× 12.5+ 3× 24 13,981.2 1.65E−10 0.9989382347 72.7 = 23.7+ 24+ 25 14,005.5 1.06E−05 0.9994590124 97 = 3× 24+ 25 13,981.2 2.01E−08 0.9989382345 72.7 = 2× 12.5+ 23.7+ 24 14,005.5 8.69E−08 0.9994483724 97.4 = 2× 23.7+ 4× 12.5 13,980.8 9.85E−11 0.9989382144 73 = 2× 24+ 25 14,005.2 3.84E−07 0.9994482855 97.4 = 2× 23.7+ 2× 25 13,980.8 2.13E−05 0.9989382144 73 = 2× 12.5+ 2× 24 14,005.2 3.13E−09 0.9994479020 97.4 = 2× 12.5+ 2× 23.7+ 25 13,980.8 4.34E−07 0.9988947944 73.7 = 23.7+ 2× 25 14,004.5 9.53E−06 0.9994478989 97.5 = 12.5+ 85 13,980.7 7.80E−08 0.9988943602 73.7 = 4× 12.5+ 23.7 14,004.5 6.42E−11 0.9994383664 97.7 = 2× 25+ 23.7+ 24 13,980.5 4.36E−06 0.9988942822 73.7 = 2× 12.5+ 23.7+ 25 14,004.5 2.63E−07 0.9994383664 98 = 2× 24+ 4× 12.5 13,980.2 7.28E−13 0.9988899235 74 = 24+ 2× 25 14,004.2 1.33E−06 0.9994381037 98 = 2× 24+ 2× 25 13,980.2 1.57E−07 0.9988899235 74 = 4× 12.5+ 24 14,004.2 6.17E−12 0.9994367737 98.4 = 12.5+ 2× 23.7+ 38.5 13,979.8 1.76E−06 0.9988897664 74 = 2× 12.5+ 24+ 25 14,004.2 2.72E−08 0.9994367737 98.7 = 3× 25+ 23.7 13,979.5 2.83E−06 0.9988880047 74.7 = 12.5+ 23.7+ 38.5 14,003.5 1.49E−09 0.9994367456 99 = 3× 25+ 24 13,979.2 2.72E−07 0.9988851705 75 = 3× 25 14,003.2 8.65E−07 0.9994367450 99 = 12.5+ 38.5+ 2× 24 13,979.2 1.30E−08 0.9988848981 75 = 2× 12.5+ 2× 25 14,003.2 3.53E−08 0.9994358802 99 = 2× 12.5+ 2× 25+ 24 13,979.2 1.11E−08 0.9988848851 75 = 4× 12.5+ 25 14,003.2 1.60E−11 0.9994358449 99.7 = 3× 12.5+ 23.7+ 38.5 13,978.5 1.60E−09 0.9988848740 75 = 12.5+ 24+ 38.5 14,003.2 1.10E−07 0.9994358449 100 13,978.2 1.28E−06 0.9988848724 76 = 3× 12.5+ 38.5 14,002.2 4.88E−10 0.9994357347 100 = 4× 25 13,978.2 8.86E−08 0.9988835875 76.5 = 12.5+ 2× 32 14,001.7 4.92E−06 0.9994357342 100 = 2× 12.5+ 3× 25 13,978.2 7.24E−09 0.9988834989 77 = 2× 38.5 14,001.2 1.82E−07 0.9994308142 100 = 2× 25+ 4× 12.5 13,978.2 8.21E−12 0.9988834917 79.4 = 2× 23.7+ 32 13,998.8 1.35E−04 0.9994306324 100 = 3× 12.5+ 38.5+ 24 13,978.2 1.54E−10 0.9988834917 References Billinton, R. 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Journal of Electrical Engineering, 60, 237– 245. Tor, O. B., Guven, A. N., & Shahidehpour, M. (2010). Promoting the investment on IPPs for optimal grid planning. IEEE Transactions on Power Systems, 25, 1743–1750. 123 A Real Test System For Power System Planning, Operation, and Reliability Abstract 1 Introduction 2 Description of Test System 2.1 Load Characteristics 2.2 Generation System 2.3 Transmission Network 3 Conclusion Appendix: Capacity Outage Probability Calculation References