Transient and Steady-State Evaluation of Distributed Generation in Medium-Voltage Distribution Networks

Abstract

As power generation systems with increasingly higher capacities are interconnected with distribution networks, a pressing need arises for a thorough analysis of their integration and the subsequent impacts on medium-voltage lines. This study conducts a comprehensive evaluation, encompassing both steady-state and transient behaviours, leading to a holistic assessment of a real-world biogas generation system integrated into a medium-voltage network. Although the methodology does not introduce revolutionary concepts, its detailed application on a real feeder under various operating conditions adds practical value to the existing body of knowledge. The methodology explores various aspects, including voltage profiles, load capacity, power losses, short-circuit currents, and protection coordination in steady-state conditions. Additionally, a transient analysis is performed to examine the system’s response under fault conditions. This systematic approach provides a deep understanding of the system’s behaviour across diverse operational scenarios, enriching the field with practical insights. The key contributions of this study include identifying the effects of distributed generation systems (DGSs) on short-circuit currents, protection coordination, and defining voltage levels that briefly exceed the CBEMA quality curve. The benefits of incorporating a generation system into a distribution network are discussed from various technical perspectives. In a peak demand scenario, with a 1.72 MW generation capacity, the phase current experiences a notable reduction of 35.78%. Concurrently, the minimum peak demand voltage increases from 12.62 to 12.83 kV compared to a nominal voltage of 12.7 kV. Furthermore, the contribution of the generation system to the short-circuit current remains minimal, staying below 4% even under the most adverse conditions. However, our findings reveal that voltage levels exceed the upper limit of the CBEMA quality curve briefly during a single-phase fault with generation, which could potentially damage electronic equipment connected to the grid. Nonetheless, the likelihood of encountering a single-phase grounding fault with zero resistance remains low.

1. Introduction

Distributed generation systems (DGSs) have experienced significant growth in recent years, particularly those related to renewable energy sources [1]. This trend has posed significant challenges in ensuring the quality and stability of service in the feeders to which they are connected [2]. DGSs offer several advantages, such as contributing towards meeting demand, reducing losses in the transmission network, and improving voltage profiles at nearby loads [3]. However, systems with considerable power compared to the minimum feeder demand present challenges and difficulties related to network security and service quality. The parallel operation of DGSs with distribution networks clearly improves the voltage profile at network nodes but can also introduce voltage fluctuations, noise, or flickering during switching events or faults, which may be visible to users and create a sense of service instability [4]. Voltage variation or noise in the network is caused by the dynamic behaviour of the machine during switching events or faults [4,5]. Therefore, the integration of one or multiple DGSs units into a distribution network must be analysed to determine their real impact on the distribution system.

Several studies concerning the integration of DGSs into the distribution network have been conducted. In [5], the authors use real data to partially define the impact of biogas plants on a specific distribution grid. The most relevant conclusion indicates that the delivered voltages remain very stable regardless of the current and power being supplied. This is beneficial for the distribution network, as it helps to maintain the service voltage within the ranges specified by regulations. Distributed generation (DG) of this kind reduces technical losses in the network by decreasing the passing currents, especially in locations near the feeder’s head-end [6].

A literature review enabled the identification of the four most important aspects to consider when connecting a generator to a medium-voltage grid, as described in the following subsections.

1.1. Power Flows

DG poses a challenge for electrical grids and distribution companies, as a large number of such systems can be connected to a medium-voltage grid. The study of load flows is one of the most important aspects for analysing a power system. Nowadays, computational methods based on the Newton–Raphson (NR) method are used, which have the advantage of converging with fewer iterations compared to other methods such as Gauss–Seidel [7].

To ensure the effective integration of generators into medium-voltage grids, a reassessment of the operating parameters and distribution characteristics is imperative [8]. Therefore, it is crucial to conduct comprehensive studies utilising advanced programs, which are predominantly based on the NR method [9]. These studies enable the analysis of data, the simulation of new DGS integrations, and the accurate determination of the distribution network’s behaviour under steady-state conditions and contingencies. For each specific contingency or network condition, parameters such as voltage, current, and chargeability can be precisely determined. Moreover, fault simulations can be performed to establish the potential short-circuit currents that the transmission network and all protection, operation, and control equipment may experience.

To simulate the different scenarios and required conditions in the system, there are two methods for determining load flows in unbalanced three-phase systems [10]. The first method is the Unbalanced Voltage Drop method, while the more recent one is the NR Unbalanced method [8,9]. When conducting a power flow study, the system’s chargeability and voltage levels are determined to establish whether they comply with the required technical regulations. According to [11], the presence of DGSs in a medium-voltage distribution network (MVDN) improves the voltage profile.

1.2. Short Circuits

Short-circuit simulations in medium-voltage distribution networks are required to define the operation of protections and system stability. These tests determine fault currents and the effectiveness of protective devices, optimise system design, and avoid major damage by isolating faults. They also ensure regulatory compliance. In the study of short circuits in the distribution network, the network should be analysed under two load scenarios [5]: (a) the generation units are not connected to the network, and (b) the generation units are connected and contributing power to the network. Several short-circuit tests, including both single-phase and three-phase tests, must be conducted to determine the fault currents in the network and the protective and switching equipment. This analysis aims to determine if the design capacities of these components meet the minimum requirements for safe operation.

According to [12], the integration of DG results in elevated short-circuit levels compared to the original network configuration. Thus, it becomes imperative to evaluate the resultant impacts on the network infrastructure and equipment under fault scenarios. Short-circuit currents typically attenuate as they move further from the source of the feeder; however, they exhibit a marked increase in the presence of DG [11], potentially exceeding 100%, which is contingent upon the system parameters and the power installed. Furthermore, an analysis of various fault conditions within a DG-integrated network indicates that fault currents occurring upstream of the DG interconnection point remain largely unaffected [13]. Conversely, when faults occur downstream of the DG connection, the resulting fault currents manifest with significantly higher magnitudes.

Short-circuit faults can be classified as either symmetrical or asymmetrical, necessitating a thorough examination of the associated thermal stresses and the capacity of all network elements. Moreover, it is vital to analyse the transient behaviours induced during fault conditions in medium-voltage networks, particularly considering the influence of DG [14]. A rigorous evaluation of short-circuit currents, both with and without DG, is fundamental to accurately characterise the altered dynamics of the network, its components, and the transient voltage profiles observed throughout fault clearance.

1.3. Protection Coordination

When implementing a DGS, it is imperative to ensure the safety of both the generation system and the interconnected network. Primarily, it is critical to prevent the DGS from operating in island mode, as the feeder’s demand generally exceeds the maximum generation capacity [15]. If, during a fault transient, the generator remains connected to the grid, it may continue supplying power to a segment of the distribution network, potentially resulting in short-term islanding. Such conditions can complicate the restoration process due to synchronisation challenges with the grid.

Out-of-step protection and the rate of change in frequency (df/dt), also known as ROCOF [16], are designed to detect grid disturbances and initiate the disconnection of the DGS to avert islanding. The operating time of this protection must be below 250 ms to prevent micro-outages. The ROCOF function (ANSI 81R) can be parameterised between 0.3 and 0.4 Hz/s, significantly affecting the tripping time. For the vector shift function (ANSI 78), a setting of 4 degrees is recommended [16]. However, alternative values may be specified depending on the desired tripping characteristics and grid stability considerations.

From the feeder’s perspective, rapid fault clearance is essential. According to [15], DG within a network must be capable of detecting and clearing faults within 200 ms irrespective of the fault location along the feeder. Consequently, the sensitivity and selectivity of ANSI 50/51 overcurrent and overload protection schemes must be meticulously calibrated to ensure that DG integration does not compromise the established coordination of the feeder’s protective systems.

1.4. Transient Regime Analysis

Synchronous machines connected to radial systems are capable of providing reactive power support to the grid, benefiting consumers [17]. During fault conditions, however, the associated currents and voltages within the grid escalate until fault clearance is achieved. The growing integration of DG into distribution networks has led to a reduction in the critical fault clearing time necessary for maintaining system stability, which is primarily due to diminished equivalent rotational inertia. This underscores the necessity for rapid fault isolation within distribution networks [18]. In [19], the author analyses fault levels in systems considering DG and compares synchronous machine-based with inverters of similar capacities under the same conditions. The findings reveal that synchronous machines contribute substantially higher fault currents compared to inverters, underscoring the critical need for the precise characterisation of system behaviour when these technologies are integrated into distribution networks.

Voltage behaviour is crucial in transient regime analysis, particularly due to switching events or faults, as these variations can significantly impact loads connected to the grid. According to the IEEE 1547.7-2013 standard [20], equipment is susceptible to increased vulnerability to voltage variations if these oscillations exceed the limits defined by the ITIC curve (CBEMA-2000) (Voltage Tolerance Curve) [21,22] (see Figure 1). Thus, it is essential to perform a comprehensive analysis to determine the transient voltage values due to the aforementioned events and contingencies.

The study [23] presents an analysis of the subtransient, transient, and steady-state dynamics of systems with DG, albeit these were conducted exclusively through simulations employing standard models. The results underscore the critical need for validation through empirical studies under real-world conditions.

DG comprises various technologies, such as solar photovoltaics (PV), wind turbines, biomass generators, geothermal generators, natural gas generators, and fuel cells, with capacities often governed by country-specific regulations. For instance, some authors [24] consider DG between 5 kW and 5 MW, while in Russia, it can vary between 1 and 150 MW [25]. Typically, DG is distinguished by its proximity to demand centres. The impact of DG on the grid is multifaceted [24,26,27] and should be evaluated considering both the negative and positive aspects, which vary depending on the technology employed (

Table 1. DG positive and negative aspects.

Impact	+/−	Technology	References
Voltage support	+	Wind, tidal, wave, geo-thermal, wind, tidal, wave, geo-thermal, distributed generation in general	[25,26,28,29]
Reduction in transmission and distribution losses	+	Wind, tidal, wave, geo-thermal, induction generators	[25,26,28,29]
Transmission and distribution capacity release	+	Wind, tidal, wave, geo-thermal, with induction generators, DG in general	[26,28]
Improved reliability	+	DG in general, PV	[26,28]
Voltage fluctuations	−	PV, wind	[27,30,31,32]
Frequency fluctuations	−	PV, wind	[27]
Harmonics	−	PV, wind	[27,30,33]
Short circuit current	−	DG in general	[25,27,33]
Reduced reliability	−	PV/WIND	[25,27]

).

The studies presented in Table 1 primarily focus on theoretical analysis, elucidating the advantages and challenges associated with integrating distributed energy into electrical grids; however, they lack emphasis on real-world applications involving implemented projects. The contribution of this article lies in bridging this gap by presenting both the network and the practical implementation of a biogas plant. Similarly, most studies focus on plants with intermittent renewable resources, whereas this study is a plant that utilises biogas and generates electricity from a conventional combustion engine generator.

This work evaluates the steady-state, transient behaviour and establishes the requirements to be analysed in the integration of a real-world biogas generation into an MVDN. A real feeder is evaluated as a case study under normal operating conditions and maximum generation scenarios (1.72 MW). This approach provides a holistic understanding of the system behaviour under normal and maximum generation scenarios. The practical insights gained from our case study offer valuable contributions to the field, particularly in terms of voltage profile improvement, power losses reduction, and enhanced protection coordination. In this study, minimum and maximum faults were analysed, in single-phase or three-phase short circuits with and without generation, to verify protections and specified selectivity. Although the study may not introduce groundbreaking concepts, its thorough examination of a real feeder’s behaviour under various conditions adds practical significance to the existing body of knowledge.

The most important contributions are as follows:

• A methodology is proposed to evaluate the transient and steady-state incorporation of DG in an MVDN.
• Reveal the effects of DGSs on short-circuit currents and protection coordination.
• Voltage values exceeding the CBEMA quality curve briefly during single-phase fault with generation may damage grid-connected electronic equipment.

This analysis can be used to determine if the project should or should not be accepted by the utility, facilitates the assessment of the advantages and disadvantages of the project, and enables the technical experts to include recommendations for the operation of the system.

The remainder of the manuscript is organised as follows. Section 2 details the Methodology. Section 3 presents the results applied to a specific case study. Section 4 offers an analysis of the results, and finally, Section 5 provides conclusions and recommendations.

2. Methodology to Evaluate the Impact of Distributed Generation in Distribution Networks

The proposed methodology for evaluating the impact of DG in distribution networks comprises three stages: information gathering, modelling and simulation, and analysis of results, as shown in Figure 2.

2.1. Stage 1: Information Gathering

In this stage, all the required information is collected. The quality and accuracy of the data and information obtained have a direct impact on the reliability of the study. As shown in Figure 2, this stage is divided into several sub-stages, which are described below.

2.1.1. Location and Type of Project

The geographical location of the project and its altitude are determined, in order to locate the possible connection point to the medium voltage grid. In addition, it is essential to know the nature of the project to be analysed in order to request all the technical parameters required in the study.

2.1.2. Feeder Configuration

Information about the feeder is requested from the distribution company, which should include the complete electrical diagram, the type of cable used in its main system, the transference points, the location of the protection equipment with their respective configurations.

2.1.3. Establish Maximum and Minimum Power Demands

The distribution utility is requested to provide a five-year projection of maximum and minimum demands. Additionally, specific maximum and minimum demand values to be used in the study must be established, as well as the technical characteristics required by the distribution utility for the integration of DG into its network. Using this information, various scenarios test points can be formulated for the development of the study.

2.1.4. Technical Data of the Electrical Substation and Generator

It is essential to gather comprehensive information regarding the substation, including the single-line diagram, nameplate data of the step-up transformer, and details of the protection equipment, specifying the active functions and their calibrations. Additionally, technical information about the generator must be obtained, including plate data, recommendation by derating by the height at which it is located, plants and control diagrams with their respective counters, both of the speed regulator, as well as the voltage regulator. a, the maximum and minimum generation powers to be used are established.

2.2. Stage 2: Modelling and Simulation

2.2.1. Feeder Modelling

With the obtained data, system modelling must be performed in a simulation software with the required detail according to the depth of the study. For this case study, a real model of the feeder with all its nodes is used. Once the base model is established, all the technical information is added, the generation units are created, the substation is modelled including its transformer, entering all the technical parameters, and then proceeding with the evaluation of each of the points and scenarios established in the previous stage.

2.2.2. Power Flows and Chargeability

Once the model is fully parameterised and calibrated, the scenarios previously defined with the distribution company are loaded. The first data to be taken into account to enter generation inputs in a distribution network comprise the system chargeability. This means that all the feeder conductors must be analysed with the network at maximum demand and under maximum generation conditions. The chargeability values obtained under these conditions should not exceed 75% of the nominal design load of the network (maximum load value established by the distribution company to consider the project).

A second crucial factor is to ensure that service voltage levels across the network, under both maximum and minimum demand conditions, with the generation system operating at both minimum and maximum output, remain within the limits set by Ecuadorian regulations (6%) [34]. To verify this, the feeder is configured in maximum demand, a flow run is performed and the voltage values are verified for the established generation conditions; then, the same process is performed in minimum demand. The power flow run also allows determining the behaviour of the feeder power losses, and even its economic evaluation can be performed using the commercial price of energy.

2.2.3. Short Circuits

The short circuit analysis is performed under two conditions: first with the feeder operating under normal conditions and second with the maximum generation connected to the grid. The purpose of this study is to compare the short-circuit current values along the feeder so that the increase in fault currents at the nodes can be determined and the impact of the DGS can be evaluated. Furthermore, this analysis allows for recommendations regarding the short-circuit level requirements for circuit-breaking and switching equipment installed at the head-end and throughout the medium-voltage network.

2.2.4. Protection Coordination

The protection coordination study is one of paramount importance, since proper coordination will allow the DGS and the network to operate reliably and selectively so that a fault event affects as few users as possible. The integration of generators into the grid has a substantial impact on protection coordination in the MVDN. Key effects include increased coordination complexity, potential alterations in fault current profiles, and the need for adjustments in protection settings to ensure selective operation. This dynamic interplay underscores the importance of a thorough analysis and potential recalibration of protection strategies to maintain network reliability and safety.

For feeder protection coordination, the initial step involves identifying the circuit-breaking and switching equipment that require coordination as well as their respective locations within the network. The protection functions that the feeder will operate with need to be defined. For phase overcurrent protection, often in a radial feeder, slow and fast ground overcurrents are coordinated depending on the configuration of the feeder and whether fuses need to be safeguarded along the route. Subsequently, it is necessary to determine the curves to be used together with the inrush current values. To protect network conductors, current settings are established close to the rated current of the conductors employed.

2.2.5. Transient Regime

In a distribution network, a transient regime study has the purpose of determining the voltage and current variations in the instant immediately after a fault or outage event in order to be able to evaluate if these values are within the established limits. Comprehensive information on the feeder, booster transformer, generator, and their respective control systems is essential for effective transient regime analysis. Upon completion of the calibration and data validation phase, the type of fault, its conditions, and the precise location within the MVDN are defined. To determine the time between events in the transient regime, the fault current value at the given point must be evaluated. By using protection coordination curves along with the DGS fault clearing times, the time intervals between the fault, the fault clearing time in the distribution network, and the DGS protection tripping time can be calibrated. Under these circumstances, an electromagnetic transient (EMT) test is conducted to obtain the behaviour of voltages and currents during the full transient regime for a particular fault. Finally, the results are analysed and evaluated mostly using the CEBEMA curve [20] (Figure 1).

2.3. Stage 3: Results

Analysis of Results

The obtained results are compared against the utility’s technical parameters as well as regulatory standards. Additionally, a comparative evaluation is conducted with findings from similar studies. This comparative analysis aims to ascertain the consistency of outcomes and the methodologies adopted when incorporating real-world data.

3. Results—Case Study

In order to understand properly the proposed methodology, in the following subsections a real case study is presented.

3.1. Information Gathering

3.1.1. Location and Type of Project

The Pichacay power plant consists of an internal combustion engine fuelled by biogas. The biogas is generated in a landfill located in the Santa Ana district, 21 km from the city of Cuenca at an altitude of 2600 m above sea level (UMT Coordinates; E: 729996 S: 9671881), as depicted in Figure 3. The biogas capture is divided into three stages: North I, North II and South, covering a total area of twelve hectares. The first stage, North I, consists of four hectares [35]. The site belongs to the Cuenca Public Sewage Company (EMAC EP) [36,37]. The ENERGY MIXED ECONOMY COMPANY (EMAC-BGP) from Cuenca, Azuay, Ecuador, operates the power plant.

In the initial stage of biogas generation, organic matter undergoes aerobic degradation in the presence of oxygen until the air within the compacted matter is depleted, resulting in the production of water, thermal energy, carbon dioxide and biogas [38]. This biogas is subsequently utilised to fuel an internal combustion engine, which, when coupled to a generator, produces electricity [35]. The biogas extraction process must be meticulously controlled to avoid excessive extraction; as such, an approach could compromise the methanogenic bacteria responsible for biogas production, ultimately halting gas generation.

At present, the power plant operates a single generation unit with a capacity of 1.05 MW. However, the utility has reported recurrent fault events, specifically transients outside the CEBEMA curve limits. To leverage the surplus biogas production, the installation of a second unit identical to the first (1.05 MW) is proposed, resulting in a total nominal capacity of 2.1 MW and an effective capacity of 1.72 MW, as specified by the manufacturer, accounting for derating effects due to the plant’s elevation at 2600 m above sea level. In this context, it is necessary to assess whether the DG connected to the feeder is the cause of transient events and to determine the potential impact on the operation of the second unit.

The generation units are connected to a common busbar, which in turn is linked to a step-up transformer and subsequently to the substation’s metering and switching equipment. Power is delivered to the common point of connection (CPC), on Feeder 321 of Empresa Eléctrica Regional CENTROSUR (Cuenca, Ecuador) [39], as depicted in Figure 4. The system operates at a voltage of 22 kV with the furthest point approximately 43 km from the source.

In Figure 4, several key points of interest are highlighted. The orange circle indicates the location of the Feeder 321 head, while the purple circles denote the locations of the reclosers. The green circle represents the location of the Pichacay generation power plant.

3.1.2. Feeder Configuration

Another important aspect is understanding the complete configuration of the feeder and the details of the location of the switching, operation, metering and protection equipment of both the feeder and the DGS. Figure 5 presents the simplified single-line diagram highlighting the most relevant equipment of Feeder 321. The Pichacay power plant is located 18 km from the feeder head. Feeder 321 has transfer points with adjacent feeders 322, 323, 824 and 1521.

Based on the single-line diagram and the total feeder diagram, the points of interest for subsequent analysis, including the relevant nodes for loadability and short-circuit analysis, are defined. The points of interest for protection coordination are chosen according to the position of the protection equipment, the head-end, the reclosers to be coordinated, and the connection point of the DG. In order to carry out the coordination of protections, the distribution company and the generators must provide the location and information of the equipment between which the coordination will be carried out. For this case study, the protection relays are the following:

• Siemens 7SJ85 relay in the Header (8040).
• First recloser IESS (21315) the ABB PCD2000 relay.
• Second recloser CENSO_1 (44730) the SIEMENS 7SR244 relay.
• SCHWEITZER SEL787 for protection of the Pichacay step-up transformer.
• SCHWEITZER SEL 451 relay for generator protection.

The used cable for the three-phase medium-voltage trunk network of Feeder 321 is ACSR 3/0 with a rated capacity of 315 A. The distribution company, in order to adequately protect its infrastructure, requested to calibrate the overcurrent protections (ANSI 51) as follows:

• 300 A reclosers for phase faults both at the head-end.
• 80 A for single-phase faults at the head-end and first recloser.
• 80 A for the slow curve for single-phase faults of the second recloser.
• 40 A for the fast curve for single-phase faults of the second recloser.

3.1.3. Maximum and Minimum Demands

The feeder demand projection is fundamental in this type of study, which was supplied by the distribution company, establishing three growth scenarios: expected, medium and high. In this study, only the medium-scenario data for the year 2020 are used, as this is the project’s entry year. In this context, the minimum demand considered is 3.1 MW and 0.57 MVAr at 3h00, and the maximum demand is 5.9 MW and 0.87 MVAr at 17h30.

3.1.4. Substation and Generator Technical Data

The Pichacay power plant has a substation with switching and metering equipment, as well as a step-up transformer, the nameplate data of which are shown in

Table 2. Set-up transformer of Pichacay power plant.

Parameter	Value	Unit
Rated power	2200	[kVA]
Voltage LV/HV	480/22,000	[V]
Current LV/HV	2646/57.7	[A]
Basic insulation level (BIL) HV/LV	30/150	[kV]
Number of phases	3	-
Frequency	60	[Hz]
Connection group.	YnD11	-
Impedance (85 °C)	4.1	[%]
Operation	3000	m.o.s.l.

.

The power plant has two generators with the same characteristics. The minimum power generation established is 340 kW with one unit, while the maximum is 1720 kW with both units at full load. The delivery of reagents is not considered, as they are not requested in the operation contract signed. The nameplate data of the generators are presented in

Table 3. Electrical generator characteristics.

Power plant	Pichacay
Unit	1 and 2
Brand	Leroy Sommer
Frequency	60 HZ
Avr	R450
Excitation	AREP
Rated power	1.06 MW
Max effective power	0.860 MW
Min effective power	0.340 MW
Max reactive power generation	0.63 MVAR
Max reactive power absorption	0.240 MVAR
Rated voltage	480 V
Rotor type	Deep slot rotor

. These data will be used for the steady-state simulations.

In order to perform the EMT analysis of the system, the transient and subtransient reactances in direct and quadrature axis with their time constants of the generators were obtained. The information must include the positive, negative and zero sequence reactances.

In this study, it is also necessary to have the control plants, both the automatic voltage regulator (AVR) and the GOV, supplied by the generator manufacturer [40]. The information must include the control diagram with the AVR constants and the GOV control diagram with their respective time constants. In Supplementary S1, the reactances and time constants of the generators are specified.

3.2. Modelling and Simulation

The most important points for the adequate modelling of the feeder are presented below in order to subsequently carry out the study including the simulations required by the distribution company and the regulation.

3.2.1. Feeder Modelling

Once the complete information supplied by the distribution utility of Feeder 321 has been collected, all these data are added to the base model in CYME 8.0 REV 11 software. Note that the study performed is on a real electrical network in which there are 2153 nodes and 1074 transformers. For this reason, we consider that simulation is the best option. It is important to consider that the three-phase backbone of the distribution system of Feeder 321 is constructed with ACSR.3/0 cable with a rated capacity of 315 A.

3.2.2. Power Flows

For the study of power flows, short circuits, loadability and the coordination of protections, CYME 8.0 REV 11 software was used and specifically the CymTCC 5.0 tool. In addition, the R/X ratio of the distribution network considered in this case study is 0.1.

Chargeability

In order to assess the system chargeability according to the proposed procedure, Feeder 321 is analysed under maximum demand conditions with maximum generation. On analysing the MVDN under these conditions, it was found that the lines with the greatest change are at the feeder head-end (overhead line per phase—49535 MTA) and at the exit of the Pichacay project at the PCC (overhead line per phase—129764 MTA). These values are presented in

Table 4. Feeder 321 at maximum demand without generator.

Load flow chart at the header
Phase overhead line—49535_MTA
Phase	kV LN	I (A)	kVA	kW	kVAR	Load (%)
A	13.15	162.2	2133.37	2105.72	342.4	51.49
B	13.15	144.52	1901.2	1883.97	255.44	45.88
C	13.15	146.22	1923.51	1905.26	264.34	46.42
Load flow chart at the generator outlet
Phase overhead line—129764_MTA
Phase	kV LN	I (A)	kVA	kW	kVAR	Load (%)
A	12.72	1.53	19.52	19.47	1.37	0.49
B	12.81	0.19	2.4	2.28	−0.76	0.06
C	12.78	7.03	89.9	89.41	9.45	2.23

and

Table 5. Feeder 321 at maximum demand with generator.

Load flow chart at the header
Phase overhead line—49535_MTA
Phase	kV LN	I (A)	kVA	kW	kVAR	Load (%)
A	13.15	119.46	1571.43	1534.85	337.11	37.92
B	13.15	101.49	1335.24	1311.12	252.63	32.22
C	13.15	103.14	1356.86	1331.62	260.51	32.74
Load flow chart at the generator outlet
Phase	kV LN	I (A)	kVA	kW	kVAR	Load (%)
A	13	42	546.9	−546.9	5.9	13.33
B	13	43.5	563.8	−563.8	6.2	13.81
C	13	35.2	459.6	−459.6	20.5	11.71

, which summarise the chargeability of Feeder 321 in its most variable elements.

When Feeder 321 is at peak demand conditions and without generation (see Table 4), the current in phase A on line 49535\_MTA is 162.2 A, which represents 51.49% of the chargeability on the feeder head-end output line. Phase A on line 129764_MTA has a value of 1.53 A representing 0.49% of the chargeability on the DGS PCC line.

In the second scenario (Table 5), the feeder is at the same demand conditions but with a generation of 1.72 MW. It can be seen that the current in phase A on the head-end line decreases to 119.46 A, which represents a chargeability of 37.92%. At the output of the SGD on the PCC line, there is a current of 42.0 A, i.e., 13.3% chargeability. The greatest contribution of the power generated is directed towards the head of the feeder, and a minor part is directed towards the end of the feeder. The maximum load current is on phase B towards the head-end (43.5 A), which represents 13.81% of the line’s chargeability. In all conditions, the chargeability in the network is less than the 75% requested by the distribution company to grant permission to operate.

Power Flow Run

In order to verify that the service voltage values along the feeder are within the limits established by the regulation (±6% of the rated value), the feeder is first configured at maximum demand to evaluate under normal conditions and with maximum generation. Secondly, the feeder is configured at minimum demand, and the same evaluation is carried out to determine the behaviour of the voltages along the feeder. The simulations are presented below under the conditions described.

Feeder 321 at Peak Demand

The simulations with and without generation show that voltage profiles have a noticeable improvement due the voltage drop decreasing. In Figure 6, the voltage profile of all Feeder 321 nodes, without generation (Figure 6a) and with maximum generation (Figure 6b), is presented. For ease of review, voltage reference lines have been plotted at ±5% of the nominal phase neutral voltage, i.e., Vmin at 13.335 kV and Vmax at 12.065 kV.

Table 6. Feeder 321 at maximum demand with generation.

Load Scenario	Generator Power No. 1 [kW]	Generator Power No. 2 [kW]	Minimum Voltage [kV]	Minimum Voltage as a % of Nominal 12.7 kV
1	----	----	12.620	−0.63%
2	340	----	12.665	−0.28%
3	860	----	12.730	0.24%
4	340	340	12.708	0.06%
5	340	860	12.771	0.56%
6	860	340	12.771	0.56%
7	860	860	12.831	1.03%

provides a summary of the minimum voltage values observed on Feeder 321 under various generation scenarios. The correlation between generated power and feeder voltage levels is evident, demonstrating how DG enhances the voltage profile of the feeder. Voltage levels on the feeder improve in direct proportion to the active power injected by the distributed management system. However, the operating licence of Pichacay Power Plant does not allow reactive power generation.

Feeder 321 at Minimum Demand

In this scenario, the voltage profile improves and remains within the regulatory limits (±6%) (

Table 7. Feeder 321 at minimum demand with generation.

Load Scenario	Generator Power No. 1 [kW]	Generator Power No. 2 [kW]	Minimum Voltage [kV]	Minimum Voltage as a % of Nominal 12.7 kV
1	----	----	12.826	0.99%
2	340	----	12.880	1.42%
3	860	----	12.946	1.94%
4	340	340	12.925	1.77%
5	340	860	12.986	2.25%
6	860	340	12.986	2.25%
7	860	860	13.043	2.70%

). This is the most critical point to verify in this analysis and represents a significant benefit in Feeder 321. Figure 7 illustrates the voltage profile of all the nodes of Feeder 321 with and without generation at minimum demand. However, if the minimum demand decreases considerably, the voltages will exceed the allowable 6% threshold.

Losses are considerably reduced at peak demand when the generator is working at its maximum capacity. The simulations show a reduction of 44.40 kW, 22.58 kVAr, 42.22 kVA and 162.28 MWh/year of active, reactive, apparent and energy power, respectively.

3.2.3. Short Circuits

The study was carried out using the CYME 8.0 REV 11 program with the fault analysis module under the IEC 60909 standard [41] for short-circuit analysis. A maximum short-circuit scenario was analysed. In order to show in a graphical way, current ranges or bands (

Table 8. Current ranges assigned to the colors in the short-circuit graphics.

Colour	From: Current [A]	To: Current [A]
	11,800	>11,800
	9000	11,800
	6000	9000
	3000	6000
	0	3000

) were defined to present the short-circuit levels of Feeder 321 without generation and with maximum generation.

Figure 8 shows the result of the simulation in the two mentioned conditions, and it can be seen that there is no major variation in the two scenarios; therefore, the fault current contribution of the DGS is minimal.

In addition, three types of short circuits were simulated: the three-phase short circuit (Ik LLL), the two-phase short circuit (Ik LL) and the single-phase to ground (Ik LT). The results showed that the largest contribution to the short-circuit current from the DGS is in a single-phase to ground fault. The results obtained at relevant feeder nodes are presented in

Table 9. Contribution of the DGS in the monophasic short circuit.

Number	Equipment Code	kV Before Fault (kV)	Short Circuit Currents Without DGS Ik LT (kA)	Short Circuit Currents with DGS Ik LT (kA)	Pichacay Contribution Ik LT (kA)
32530	Isolating switch	22	15.568452	15.800882	0.232430
8040	Automatic Switch	22	15.594404	15.827634	0.233230
7821	Isolating switch	22	15.552529	15.785139	0.232609
4582	Isolating switch	22	14.756344	14.972534	0.216191
23176	Fuse	22	13.726989	13.916900	0.189912
43965	Recloser	22	0.758587	0.794403	0.035816
22834	Isolating switch	22	0.984778	1.045762	0.060984
69	Isolating switch	22	0.796275	0.856588	0.060314
4367	Fuse	22	3.054331	3.131524	0.077193
44339	Recloser	22	5.481711	5.578818	0.097107

, where some specific data on through currents under single-phase short-circuit conditions are shown as an example. It is important to note that in Table 9, a comparison of currents is made with the feeder in normal state and with maximum generation.

The contribution of the Pichacay DGS to the short-circuit current of the system is very small, as can be seen in Table 9. The value of the increase in fault current is less than 240A; in other words, it is less than 2% in the worst-case scenario. It should be noted that the short-circuit currents very close to the head-end are of considerable magnitude; this situation should be taken into account for the selection of protection and switching equipment.

4. Coordination of Protections

The coordination of protections between the head-end circuit breaker (8040), the IESS recloser (21315), and the Censo 1 recloser (44730), located in the trunk circuit of Feeder 321 (Figure 5), must be verified. The coordination time between protection equipment in a distribution network is 200 ms in order to maintain selectivity [42]. The starting value for the phase overcurrent curves is set at 300 A, as recommended by the distribution utility, to adequately protect the trunk cable (ACSR.3/0).

The coordination study for phase faults is conducted using IEC VI (Very Inverse) curves in the protection relays. Detailed information regarding the behaviour of the equipment can be found in the respective manuals [43,44,45]. The operating time is determined by Equation (1) [45]:

$$IEC\_VI{t}_{op}={\displaystyle \frac{K}{{\left[\frac{I}{I_s}\right]}^{\alpha }-1}}·T_m$$

(1)

where t_op is the time of operation, K = 13.5, α = 1, I is the current, I_s is the adjusted current, and T_m is the time multiplier.

For the coordination of ANSI 50/51 overcurrent protection, the CymTCC short-circuit current simulation module was used with a safety factor of 1.1 and three-phase impedance of 5 Ohm (values recommended by the distribution company). The diagram of the phase overcurrent protection coordination curves is shown in Supplementary S2.

The minimum tripping time difference between the coordination curves of the header and the first recloser is 197 ms, while between the first recloser and the second recloser, there is a time difference of 197 ms. On each of the curves in Supplementary S2 (coordination between the three IEC VI phase curves), the information of the curve type, the instantaneous trip value, the trip threshold I_s and the time dial or selector Tm has been labelled.

For single-phase overcurrent coordination, the CymTCC module was used with a safety factor of 1.1 and a single-phase fault impedance of 20 Ohm. The single-phase pick-up value is 90 A; for the head-end (8040) and the first recloser (21315), IEC VI single-phase curves were considered (Equation (1)). For the second recloser (44730), the curves used are IEC EI (Extremely Inverse), as shown in Equation (2). Two curves were calibrated: a fast curve with a pick-up value of 40 A in order to protect fuses and a fast curve with a pick-up value of 80 A for coordination with the two protection devices towards the feeder head. The result is shown in Supplementary S3, in which the single-phase coordination curves can be seen. Between the head-end (8040) and the first recloser (21315), the minimum time separation between curves is maintained at 202 ms with and without generation. Between recloser 1 (21315) and recloser 2 (44730) the minimum inter-curve separation times vary between 201 ms with no generation and 199 ms with maximum generation.

The fast protection curve in recloser 2 (44730) is suggested to be able to safeguard fuses in case of a single-phase fault; for this purpose, the recloser should work with reclosing: thus the proposal to guarantee the selectivity and coordination of protections for single-phase faults on Feeder 321. In each of the curves in Supplementary S3, the information of the type of curve, the instantaneous trip value, the trip threshold Is and the time dial or selector T_m has been labelled.

$$IEC\_EI{t}_{op}={\displaystyle \frac{K}{{\left[\frac{I}{I_s}\right]}^{\alpha }-1}}·T_m$$

(2)

5. Transient Regimes

In this aspect of the study, the base model of Feeder 321 was simulated using DIG-SILENT Power Factory 2019 software. Upon validating the supplied base model, detailed information regarding the Pichacay substation, transformer, and generators was incorporated into the software to conduct the transient regime simulation. It was imperative to input all manufacturer-provided data for both the transformer (Table 1) and the generator (Table 2), including transient and sub-transient reactances and time constants.

To analyse the electromagnetic transient (EMT) behaviour of the system, the control systems for both the Automatic Voltage Regulator (AVR) and the Governor (GOV) were configured using manufacturer-provided information. These data include control diagrams with AVR constants and GOV control diagrams with associated time counters. These parameters were entered into the control systems of the selected generator in Power Factory software to achieve an EMT simulation that closely approximates real-world conditions.

The transient analysis was performed at peak demand for the year in which the second Pichacay generator was commissioned (2020) with a head-end demand of 5.90 MW and 0.870 MVAR. These demand values were applied by re-scaling the feeder loads while ensuring that the Pichacay power plant was disconnected during this process.

A single-phase short-circuit fault was applied immediately downstream of the CENSO 1 recloser (44730) on line LMTA_146163 with a fault resistance of Rg = 0 Ohms. The maximum single-phase short-circuit current at this location was determined to be 1703 A with generation and 1771 A without generation. Based on the fault current magnitude, the recloser tripping time (44730) was calculated to be 32 ms (refer to Table 9). At the Pichacay substation, recloser tripping was executed 150 ms after islanding, utilising anti-islanding protections (vector jump and ROCOF). Using these tripping times as a reference, two scenarios were generated: one without generation and one with maximum generation. In the first scenario, a single-phase fault occurs at the specified location without generation, and the sequence of events is described below:

• Single-phase fault at 0.050 s from the start of the simulation.
• Trip of CENSO 1 recloser (44730) at 0.032 s into the fault (0.082 s in total).

The voltage and current results of the fault are presented in Figure 9. The results of the fault are presented in Figure 9. The voltage at the point of analysis without generation before the fault is at 1.022 p.u., and after the fault it rises to 1.193 p.u. for two cycles, and finally when the fault is cleared by tripping the recloser, the voltage drops immediately. The current, during the fault, presents values up to 5588 p.u., which is expected in this analysis.

In the second scenario, a single-phase fault occurs at the described point with generation from both units, i.e., with 1.72 MW. In this case, the sequence of events is as follows:

• Single-phase fault 0.050 s after the simulation has started.
• Trip of recloser CENSO 1 (44730) at 0.032 s after the fault (0.82 s in total).
• Trip at Pichacay 0.150 s after islanding.

The results of the fault are presented in Figure 10. The voltage at the point of analysis, with the contribution of the DGS, before the fault is at 1.027 p.u., and after the first event it goes to 1.223 p.u. and 1.216 p.u. After the second event, the voltage presents values of 1.359 p.u., 1.309 p.u., 1.248 p.u., etc., with a slight decreasing slope due to the effect of DG. Finally, with the third event, the tripping of the Pichacay circuit breaker clears the fault completely. The current during the fault presents values up to 5492 p.u., which is expected in this case study.

6. Analysis of Results and Discussion

This study identifies the critical conditions for fault events by evaluating various scenarios, including different types of faults at multiple points along the feeder. To adhere to regulatory requirements, the analysis was conducted over a five-year horizon, incorporating growth projections for the feeder and potential power transfers. The synthesised data serve to determine the feasibility of integrating DGS into the proposed MVDN.

The findings suggest that integrating DG into an MVDN enhances the voltage profile along the feeder, resulting in improvements of 1.03% and 2.7%, as reported in Table 4. These results align with those documented by Bulatov [4].

This study further evaluates the behaviour of feeder power flows with particular attention to technical losses. Such losses are inherently challenging to mitigate, as they depend on the physical characteristics of the MVDN infrastructure. DG reduces the current flowing through the distribution network, especially in locations near the feeder head-end, achieving both energy and economic savings by minimising technical losses, particularly in medium-voltage system cabling. The reduction in feeder power losses due to DG integration translates into economic savings. Using a reference tariff of 0.10 USD/kWh, projected savings are estimated at USD 16,230.00 annually. While the feeder is not continuously in this condition, the potential for DG to enhance grid efficiency is evident. Kesici’s analysis yields similar findings [2], although his study includes reactive generation, and Ma Yiwei [3] also reaches analogous conclusions.

The determination of the optimal size and location of DG units, focusing on nodes with higher power losses, is explored in [46]. Application of the PLI method demonstrated that integrating DG units reduced both active and reactive energy losses by 39.62% and 41.88%, respectively, while also enhancing the voltage profile from 0.91 p.u. (base case) to 0.96–0.97 p.u. In [47], four types of PV systems are integrated to home users into the distribution network. When PV systems supplied 50% of the feeder’s electricity demand, power loss reduction reached 1%. At peak generation, voltage increased by less than 0.5%, while during the remainder of the day, voltage levels returned to their previous values. In contrast, the integration of DG with 1.72 MW, as evaluated in the present case study, yields a 2.4% reduction in power losses at peak demand and mitigates voltage drop by 1.64%. The phase current is reduced by 35.78%. The minimum voltage at peak demand increases from 12.62 to 12.83 kV (nominal voltage of 12.7 kV). Moreover, the contribution of the generation system to the short-circuit current is minimal: less than 4% in the worst-case scenario. Protection coordination requires minimal adjustments for optimal operation. It is worth noting that the technical improvements observed in this study are constrained by the relatively low power generation capacity and the fixed project location. Therefore, the advantages and challenges of DG integration into power grids are highly context-dependent, necessitating individualised analysis for each specific case.

Short-circuit currents determine the withstand capability of system components. The increase in these currents due to DGS integration is minimal, with the three-phase short-circuit current (Ik LLL) exhibiting a maximum variation of 2.4% (Table 9), which is largely influenced by the project’s distance from the feeder head-end (18 km) [48]. For protection coordination, the proposed methodology satisfies both protection and selectivity requirements (Supplementary S2 and S3), covering overload faults and direct faults, ensuring the safety and reliability of the distribution network.

In the transient voltage analysis, the inclusion of the Pichacay generation unit results in high transient voltage values at the point of analysis when the DGS is islanded. Specifically, transient voltage levels depicted in Figure 10 exceed 130% for two cycles. According to the CBEMA curve presented in Figure 1, this event falls outside the curve’s defined limits, indicating a high probability of damage to electronic equipment during such conditions [20]. It is important to emphasise that this study considers the worst-case scenario—namely, a single-phase fault with an earth resistance of 0 Ohms—despite the low probability of such a fault occurring.

The study’s insights regarding the integration of DG into the MVDN are valuable for understanding both the technical and economic implications of such systems. The results indicate that the inclusion of DG contributes to overall grid stability, enhances voltage profiles, and reduces power losses. However, the benefits of DG integration must be assessed on a case-by-case basis, as the specific characteristics of each grid, including generation capacity and geographic factors, can significantly influence the outcomes. The economic savings and technical improvements highlighted in this work underscore the importance of a strategic approach to integrating DG into distribution networks, considering both regulatory requirements and operational feasibility. Future research should focus on exploring advanced coordination schemes and adaptive protection settings to further enhance the benefits of DG integration while mitigating any adverse impacts on grid operation.

7. Conclusions and Recommendations

In this paper, the integration of biogas DG is demonstrated to significantly enhance the voltage profile within the studied feeder, elevating the quality of service for end-users. Through this incorporation of electricity generation, transmission losses are effectively curtailed, while short-circuit currents are mitigated to remain within prescribed operational thresholds.

In the conducted case study, the introduction of a 1.72 MW generation capacity during peak demand periods yields tangible benefits. Notably, power losses are reduced by 2.4%, and voltage drop is attenuated by 1.64%. Moreover, a substantial decrease of 35.78% in phase currents is observed. This integration also results in the elevation of the minimum peak demand voltage from 12.62 to 12.83 kV (against a nominal voltage of 12.7 kV). Notably, the contribution of the generation system to short-circuit currents remains below 4% even under the most challenging conditions. Moreover, minimal adjustments are required to ensure the optimal coordination of protections, ensuring uninterrupted system operation.

Concerning the transient fault analysis, our findings reveal that the voltage values are outside the upper part of the CBEMA quality curve for a short period during a single-phase fault with generation, which could cause damage to the electronic equipment connected to the grid. However, it is important to note that the probability of encountering a single-phase grounding fault with a resistance of 0 Ohm remains minimal.