Electric Grid Modeling for Distribution Generation Applications
2012 M.Eng. thesis, McGill University
Written by Michael Nicholas George
Chapter 1:
Introduction
Economic and technological trends have shifted the very concept of the electric power system from tightly controlled, top-heavy unidirectional energy pipelines to systems that are more distributed – both in terms of actual generation capability and in terms of market control. This has posed a huge challenge to the control and protection schemes of these vast networks, most of which are designed and coordinated for conventional power systems with large-scale, centralized generation. With the electric power system becoming more and more decentralized, many researchers and engineers have been working to manage the implementation of distributed energy resources into the existing power grid. Technologies like distributed generation, local energy storage, demand-side response, and the associated means for coordination and communication are being developed in an effort for conventional power systems to evolve into “smart grids” that will handle a variety of multidirectional power flows between many independent parties.
Because distributed generation (DG) sources must comply with dedicated interconnection guidelines, it is necessary for DG impact studies to be conducted in order to assess the effects the DG’s will have on the area electric power system upon connection. The goal of this thesis is to outline a methodology to simplify a utility’s distribution feeder into a representative model that is as simple as possible but with the characteristics preserved that are relevant for power flow studies and transient analysis for events that occur in faults, fault protection actions, and DG response to faults.
1.1 - Distributed Generation
Large-scale generation projects are less likely nowadays to have the political and financial resources to see fruition. The increasing prevalence of environmental concerns associated with CO2 emissions, safety and sustainability of nuclear power, environmental effects of large-scale hydroelectric projects, etc. provide a realm of uncertainty that lingers over any generation company trying to secure capital for a large power plant. In addition, the expansion of transmission networks has been slowed by the financial uncertainties associated with deregulation.
In the meantime, a variety of technologies have focused the spotlight of power systems research and development efforts to local power systems (i.e. distribution level). Distributed generation, energy storage systems, and advanced metering have the potential to give consumers more control over their consumption – and perhaps production – thereby granting a more active role to consumers in the electricity marketplace.
The trend is towards the development of self-reliant local networks that depend less on both the transmission systems and large-scale power producers. It is hoped that this decentralization will not only make power systems more resilient and make electricity markets more competitive, but also defer or eliminate the need for capital-intensive, politically sensitive, large-scale generation and transmission projects in the future.
A conventional power system is composed of three distinct levels of operation – generation, transmission, and distribution. The generation system is responsible for producing electric power from a particular energy source like coal, natural gas, nuclear power, or hydroelectric power. Because these generation facilities are generally very large and environmentally intrusive, they are typically located in remote areas far from urban centers. Transmission lines provide the connection between these large, centralized generation facilities and load centers. Spawning from these transmission lines are distribution networks that handle low-voltage power and connect to loads like factories, businesses, and homes in order to rovide power from the transmission line directly to the consumers as needed. Because of the delicate balance necessary to constantly match supply to demand, these power systems are highly centralized and strictly coordinated.
Distributed generation (DG) is a paradigm of electric power systems placing power generation capability at the distribution level. Individually, these generators are small in power output, compared to those used in the conventional system. Because of this difference in scale, they do not have the significant negative environmental impact of larger, conventional power generators; thus, it is possible to place these sources closer to load centers where they are needed. The small size and modularity of these sources enable widespread accessibility of potential generation to consumers, who can then sell their own generated power into a market on the power system. This improved competition gives consumers more choice on where their power comes from and how much they are willing to pay for it. DG also decreases reliance on the conventional centralized power sources for electricity, which has the potential to improve access for remote areas where bulky and costly transmission lines are unable to reach. In addition, because power near a given DG source is generated locally, less of the power delivered to the load from the DG source is wasted by transmission losses and other conversion losses. Figure 1-1 illustrates the difference between a conventional power system and one containing several distributed generators throughout.
Figure 1-1: Conventional power system structure vs system with distributed generation
1.2 - Distribution Systems
Distribution systems deliver electrical power from the high-voltage transmission system to individual buildings and other consumption sites. A substation will interface the distribution system with the transmission system. Primary feeders radiate outward from substations to load centers; distribution transformers reduce the voltage from distribution voltage to utilization voltage; and secondary networks distribute energy from the distribution transformer to individual customers. Figure 1-2 illustrates these parts of a distribution system. This paper focuses on benchmarking specifically at the primary feeder level.
Since nearly all electricity consumers are connected to the distribution network as their means of receiving electrical power, the distribution system is the most expansive level of a power system. Topologies vary widely among each other and are a function of their geographic environment and consumer demand profiles. However, most distribution networks share several common features, many of which are useful in the development of the benchmark feeder model.
Most distribution feeders share many common characteristics, such as voltage classes, loading capabilities, feeder lengths, and more. The primary voltage classes are 5, 15, 25, and 35 kV. The 15 kV class voltage level is the most popular, comprising more than 80% of all distribution circuits in the US.
These networks generally spawn feeders ranging from 5 to 25 km in length with three-phase branches and single-phase lateral lines branching from a three-phase main line. Typical loading is 4-6 MVA on most 15 kV circuits. Higher-voltage circuits handle correspondingly higher loading; for instance, 35 kV feeders typically carry 10-16 MVA. Only large power consumers (e.g. large businesses and factories) are connected to the primary network. Most consumers are served by secondary networks whose voltage is stepped down by distribution transformers from the primary network. Common secondary voltages for three-phase, grounded-wye services are 277 V or 120 V (phase-to-neutral). Table 1-1 highlights some of the parameters for a typical distribution system.
Other distribution network characteristics may depend more heavily on the specific configuration and geographical features present. For three-phase balanced systems, impedances in overhead lines range from 0.11 - 0.76 Ω per thousand feet. The current capacity for these lines typically ranges from 60 - 1500 A, depending on the conductor material, cross-sectional area, stranding, and temperature. The substations range in size from 5 MVA for small rural substations to beyond 200 MVA for urban substations.
Power systems supply a broad range of loads, whose quantities can vary according to urban density, customer type (i.e. residential, commercial, or industrial), usage patterns, etc. Rural areas might have a load density of 10 kVA/mi2, whereas a dense downtown core may demand around 300 MVA/mi2. A house’s power consumption may peak in the realm of 10-20 kVA, and a nearby factory might peak at around 5 MW. Proper perspective on power quantities is important to consider, especially considering the relative power contributions of the proposed DG units.
Because distribution systems, by nature, cover a large geographical area, they are exposed and vulnerable to faults. Most faults involve a short circuit between phases or between phase and ground. In order to protect the distribution system from damages associated with large fault currents, a number of protective devices are installed in a coordinated fashion to form a protection scheme for the network. The main objectives of these protection schemes are to minimize the duration of a fault and to minimize the impact of these faults on consumers. Secondary objectives are as follows:
Eliminate safety hazards as quickly as possible.
Limit service outages to the smallest possible segment of the system.
Protect consumers’ equipment.
Protect the system from unnecessary service interruptions and disturbances.
Disconnect lines, transformers, and other equipment that are faulted.
Figure 1-2: One-line diagram of a typical distribution system
Table 1-1: Typical distribution system parameters
Protective devices applied to distribution systems include relay-controlled circuit breakers, automatic circuit reclosers, fuses, and automatic line sectionalizers. These devices are coordinated with each other in order to provide backup protection (in case of the failure of a protective device to interrupt the fault current) and to minimize the area affected by faults in the network.
The majority of Canadian primary distribution systems operate as a radial network. Radial networks allow for easy fault detection and clearing by the protection system. Because power flow to any given load is constricted to only one path at any time, the line impedance provides a natural limiter to fault currents, especially when they are located far from the substation. Radial systems also help voltage control and ease the analysis and prediction of power flows throughout the distribution network. To ensure a higher degree of reliability for critical loads, tie points are often installed that connect the load to alternate feeder paths, in the case of a fault in the connected feeder. Alternate feeder paths can be constructed that provide parallel means for loads to receive power from the substation, as long as these paths remain open (disconnected), except in the case of a contingency. In order for a system to be radial, all loads must be connected to the substation with only one path.
1.3 - Integrating Distributed Generation
One consequential aspect of distributed generation arises from the ownership and control of DG sources. Most often, DG sources are not owned by the utility; yet, they may introduce any combination of positive and adverse effects on the local electric power system. As the penetration levels of DG increase, so do the probability of such events, as well as the extent of their impact on the power system.
The transformer configurations used throughout the primary distribution system, as well as the configuration of the transformer interfacing the DG with the system, affects the interaction between the DG and the distribution system. This is most evident during faults and imbalance conditions, during which improper transformer configurations may cause significant overvoltage, ferroresonance, and compromises in the sensitivity of fault protection. Choosing the correct transformer configuration for the DG interconnection depends on the distribution system characteristics, as well as the size and type of DG being implemented.
DG can have a number of effects on power quality throughout the distribution system and nearby consumers. Undesired harmonics can be both generated and absorbed by DG’s, depending on the circumstances. These harmonics can damage both the distribution system and the DG itself through overheating of transformers or heating in the generator. Several types of DG can contribute significantly to voltage flicker, which can lead to irritating fluctuations in light in lamps, televisions, computer monitors, etc. at loads near fluctuating DG sources.
Because power systems have traditionally contained all generators at the generation level, these systems are designed on the basis of one-way power flow – from generators, through transmission lines, to distribution networks, and then out to loads. DG disrupts this one-way convention, because it introduces power sources at the distribution and load levels.
The voltage regulation scheme of the distribution system can be affected by these changes in power flow directionality. Voltage regulation equipment, such as transformer tap changers, in-line regulators, and switched capacitor banks, are placed and controlled in the system under the assumptions of radial power flow and, subsequently, a steady voltage drop that is a function of the distance along the feeder from the substation. The changes in voltage profile along the feeder that result from DG complicate the manner in which voltage regulation equipment operate. In addition, the interaction of regulating equipment and the
DG’s own voltage control mechanisms may cause conflicting compensation measures between the control devices that lead to undesirable cycling of regulation devices and further impacts on power quality as a result.
Changes in power flow directionality also affect power system protection schemes, which are also designed on the basis of one-way power flow from the substation. When a fault occurs on a distribution feeder, a coordinated system of fuses, reclosers, and relays works together to locate the fault on the feeder, determine whether or not to isolate it, isolate it, and restore severed connections after the fault has been cleared. This coordination is well-established and is based on the radial layout of the system.
The introduction of DG sources on these feeders complicates this procedure of fault response. When a lasting fault occurs in a feeder, the system’s protection mechanisms isolate it by closing the fuse that is upstream (towards the transmission system) and closest to the fault, thereby leaving as much as possible of the feeder upstream from the fault unaffected. Conventionally, the faulted section is left isolated and without power until it is cleared, either automatically or by service crews. However, problems arise if DG sources are located on this faulted section. Islanding is such a power system state, in which part of a distribution network is isolated from the rest of the network, yet continues to be supplied with power from DG sources located within the isolated network itself. Figure 1-3 shows an example of an island situation, in which the section highlighted in red is isolated from the rest of the system by the open protective switch, yet continues to receive power from the local DG.
Figure 1-3: Islanding in a distribution network
This condition brings about several problems, including the following:
Lack of regulation of voltage and frequency, which is usually provided by the rest of the power system.
Danger to utility line workers who are trying to repair line that continues to be energized by DG.
Danger to the public due to the utility’s inability to easily de-energize damaged lines.
Potential damage to DG units if the island is no longer synchronized with the power system at the instant of reconnection.
Interference with manual or automatic service restoration procedures for neighbouring loads.
Islanding can sometimes be done intentionally in order to facilitate microgrids, particularly in cases where increased reliability and backup power are desired precisely at the facility where the DG unit is installed.
However, the considerable amount of engineering effort, control functionality, and communications infrastructure necessary for this type of operation do not yet exist beyond the scope of the DG/load bus, and further consideration must be given when trying to operate local islands comprising multiple DG’s.
Therefore, current IEEE and state standards seek to minimize the possibility of island formation and to immediately dispel these islands by disconnecting all DG units on the islanded portion of the distribution system [5]. In most cases, DG’s are expected to detect an island and disconnect themselves from it within 500-1000 ms of the island occurrence in order to avoid out-of-phase reconnection by the acting protection devices. Such a loss of synchronism between the DG and the system can result in large currents to the generators and adverse impacts on the protection scheme elsewhere in the system.
Because of the risks mentioned above posed by inadvertent islanding, it is crucial for a DG-penetrated system to be able to detect the occurrence of such an island and respond appropriately within the given timeframe. A variety of islanding detection mechanisms has been developed that seek such indications in order to detect and respond to the occurrence of an island.
1.4 - Existing Distribution System Benchmarks
CIGRE (International Council on Large Electric Systems) Task Force C6.04.02 proposed a set of benchmarks for distribution networks specifically geared towards DG integration. It distinguishes between three different types of networks to be looked at – low-voltage urban distribution systems, medium-voltage rural distribution systems, and high-voltage transmission networks. Because many potential DG units are in the form of wind turbines, solar cell arrays, and other renewable energy projects that are often located in rural communities, this thesis will focus on a benchmark that models a medium-voltage (MV) rural distribution system. CIGRE’s MV rural distribution network benchmark is derived from a German MV distribution network that supplies a small town and surrounding rural area. The network is rated at 20 kV and is fed from a 110 kV transformer station; however, the benchmark’s parameters (e.g. voltage rating, load sizes) may be adapted according to regional standards. The benchmark network was designed in order to study the impact of DG on the following:
Power flow in MV distribution lines
Voltage profile throughout the MV distribution network
Power quality issues, including harmonics, flicker, frequency fluctuations, and voltage fluctuations
Small-signal stability
Voltage stability
Protection against faults
In Canada, Natural Resources Canada’s CANMET Energy Technology Centre is developing its own set of benchmarks for application in Canadian systems. It classifies distribution systems into three types – urban, suburban, and rural – according to the length of the feeder main, types of protection devices used, types of laterals, load density, and voltage levels. These benchmarks are valid for North American systems, which differ from European systems in the structure of the primary and secondary distribution systems, distribution transformer sizing, and grounding practices.
Because of the numerous challenges associated with DG integration, there are a variety of research topics devoted to reimagining distribution-level planning and operation with more system intelligence, system control, and coordination schemes. In order to provide a consistent platform with which to simulate and verify the proposed techniques for DG integration, benchmark distribution systems have been developed.
IEEE published a series of benchmark distribution feeders in order to make available a common data set with which to compare the performance of different distribution simulation programs. These programs were designed for steady-state analysis of unbalanced three-phase radial feeders. Because this work focused on steady-state analysis, applications of this feeder modeling work and the associated simulation programs were focused on planning, reliability and security, and economic analyses.
The proliferation of DG has shifted the motivations of recent benchmarking efforts towards interconnection of these sources into existing networks, along with the complications posed in planning, coordination, and control. These call for a set of benchmark feeders that is better tailored to capture the phenomena associated with DG interconnection studies.
1.5 - Modeling Tools
This project utilizes two different commercial software platforms – a distribution system analysis program (DSAP) and an electromagnetic transients program (EMTP) – in order to construct and validate the distribution system models for simulation and analysis. Each of the programs is designed for analysis of the system within a specified context. Comparison of the same power system between these programs allows for a more complete understanding of the system, as well as cross-validation of the feeder reduction and benchmarking procedure.
The DSAP is designed for planning studies and for the steady-state simulation of electrical distribution network behaviour under different operating conditions and scenarios. It performs analyses such as load flow calculations, short-circuit studies, and network optimizations on balanced or unbalanced systems built with any combination of phases and configurations. The data gathered on the feeder system described in this thesis is in the format of a DSAP model.
The EMTP is a program designed to simulate electromagnetic, electromechanical, and control system transients in multiphase power systems. It is capable of modeling oscillations from these types of phenomena ranging in duration from microseconds to seconds. It is typically used in switching and lightning surge analysis, insulation coordination, shift torsional oscillations, ferroresonance, and power electronics applications in power systems. Simulation options include frequency scans, steady-state solutions, time-domain solutions, and statistical analysis. Because it performs simulations in the time domain, it can be used to portray and analyze phenomena that a standard DSAP does not capture.
1.6 - Objectives and Scope
The objective of this thesis is to describe a methodology that can be used to obtain a simplified rural distribution feeder model credible enough to accommodate DG impact studies and, more specifically, power flow, short circuit, and islanding studies. The relevant timescale of these studies is defined by the time required for DG’s to react to an islanding event, which is typically on the order of 0.5 to 1 second, assuming the presence of high-speed reclosing in the local power system. High-speed reclosing is assumed to be present, since it does not only impose constraints on the islanding protection scheme but may also have adverse effects on synchronous DG’s because of the possibility of out-of-phase reclosing. If high-speed reclosing is not present, islanded DG disconnection times may be extended to the range of 2 seconds. This electromechanical type of transient analysis is called for here in order to accurately portray the relevant effects from the dynamics of the DG’s and their interaction with the feeder’s protection scheme.
This work is concerned with the characteristics of the distribution network itself, not the details of the DG itself. It deals with rural distribution feeders and is confined to analyzing the primary feeder level of the distribution network, including laterals. This encompasses lines and equipment at the distribution level between the substation transformer and distribution transformers.
It should be noted that this thesis does not aim to establish a universal benchmark, but rather to provide the tools for utilities and researchers to generate their own benchmark that is more specifically applicable to an existing system.