In recent years, utilization of electrical energy increased exponentially and customer requirement and quality definitions of power were changed enormously. As electric energy became an essential part of daily life, its optimal usage and reliability became important. Real-time network view and dynamic decisions have become instrumental for optimizing resources and managing demands, leading to the need for distribution management systems in large-scale electrical networks.
Most distribution utilities have been comprehensively using IT solutions through their Outage Management System (OMS) that makes use of other systems like Customer Information System (CIS), Geographical Information System (GIS) and Interactive Voice Response System (IVRS). An outage management system has a network component/connectivity model of the distribution system. By combining the locations of outage calls from customers with knowledge of the locations of the protection devices (such as circuit breakers) on the network, a rule engine is used to predict the locations of outages. Based on this, restoration activities are charted out and the crew is dispatched for the same.
In parallel with this, distribution utilities began to roll out Supervisory Control and Data Acquisition (SCADA) systems, initially only at their higher voltage substations. Over time, use of SCADA has progressively extended downwards to sites at lower voltage levels.
The typical data flow in a DMS has the SCADA system, the Information Storage & Retrieval (ISR) system, Communication (COM) Servers, Front-End Processors (FEPs) & Field Remote Terminal Units (FRTUs).
In order to support proper decision making and O&M activities, DMS solutions should support the following functions:
The various sub functions of the same, carried out by the DMS are listed below:-
In territories such as the UK a core function of a DMS has always been to support safe switching and work on the networks. Control engineers prepare switching schedules to isolate and make safe a section of network before work is carried out, and the DMS validates these schedules using its network model. Switching schedules can combine telecontrolled and manual (on-site) switching operations. When the required section has been made safe, the DMS allows a Permit To Work (PTW) document to be issued. After its cancellation when the work has been finished, the switching schedule then facilitates restoration of the normal running arrangements. Switching components can also be tagged to reflect any Operational Restrictions that are in force.
The network component/connectivity model, and associated diagrams, must always be kept absolutely up to date. The switching schedule facility therefore also allows ''patches'' to the network model to be applied to the live version at the appropriate stage(s) of the jobs. The term ''patch'' is derived from the method previously used to maintain the wallboard diagrams.
The state estimator is an integral part of the overall monitoring and control systems for transmission networks. It is mainly aimed at providing a reliable estimate of the system voltages. This information from the state estimator flows to control centers and database servers across the network.[1] The variables of interest are indicative of parameters like margins to operating limits, health of equipment and required operator action. State estimators allow the calculation of these variables of interest with high confidence despite the facts that the measurements may be corrupted by noise, or could be missing or inaccurate.
Even though we may not be able to directly observe the state, it can be inferred from a scan of measurements which are assumed to be synchronized. The algorithms need to allow for the fact that presence of noise might skew the measurements. In a typical power system, the State is quasi-static. The time constants are sufficiently fast so that system dynamics decay away quickly (with respect to measurement frequency). The system appears to be progressing through a sequence of static states that are driven by various parameters like changes in load profile. The inputs of the state estimator can be given to various applications like Load Flow Analysis, Contingency Analysis, and other applications.
Load flow study is an important tool involving numerical analysis applied to a power system. The load flow study usually uses simplified notations like a single-line diagram and focuses on various forms of AC power rather than voltage and current. It analyzes the power systems in normal steady-state operation. The goal of a power flow study is to obtain complete voltage angle and magnitude information for each bus in a power system for specified load and generator real power and voltage conditions. Once this information is known, real and reactive power flow on each branch as well as generator reactive power output can be analytically determined.
Due to the nonlinear nature of this problem, numerical methods are employed to obtain a solution that is within an acceptable tolerance. The load model needs to automatically calculate loads to match telemeter or forecasted feeder currents. It utilises customer type, load profiles and other information to properly distribute the load to each individual distribution transformer. Load-flow or Power flow studies are important for planning future expansion of power systems as well as in determining the best operation of existing systems.
Volt-VAR Control or VVC refers to the process of managing voltage levels and reactive power (VAR) throughout the power distribution systems. These two quantities are related, because as reactive power flows over an inductive line (and all lines have some inductance) that line sees a voltage drop. VVC encompasses devices that purposely inject reactive power into the grid to alter the size of that voltage drop, in addition to equipment that more directly controls voltage.
Beyond maintaining a stable voltage profile, VVC has potential benefits for the ampacity (current-carrying capacity) of power lines. There could be loads that contain reactive components like capacitors and inductors (such as electric motors) that strain the grid. This is because the reactive portion of these loads causes them to draw more current than an otherwise comparable, purely resistive load would draw. The extra current can result in heating up of equipment like transformers, conductors, etc. which might then need resizing to carry the total current. An ideal power system needs to control current flow by carefully planning the production, absorption and flow of reactive power at all levels in the system.
Electric Distribution Systems have long stretches of transmission line, multiple injection points and fluctuating consumer demand. These features are inherently vulnerable to instabilities or unpredicted system conditions that may lead to critical failure. Instability usually arises from power system oscillations due to faults, peak deficit or protection failures. Distribution load shedding and restoration schemes play a vital role in emergency operation and control in any utility.
An automated Load Shedding Application detects predetermined trigger conditions in the distribution network and performs predefined sets of control actions, such as opening or closing non-critical feeders, reconfiguring downstream distribution or sources of injections, or performing a tap control at a transformer. When a distribution network is complex and covers a larger area, emergency actions taken downstream may reduce burden on upstream portions of the network. In a non-automated system, awareness and manual operator intervention play a key role in trouble mitigation. If the troubles are not addressed quickly enough, they can cascade exponentially and cause major catastrophic failure.
DMS needs to provide a modular automated load shedding & restoration application which automates emergency operation & control requirements for any utility. The application should cover various activities like Under Frequency Load Shedding (UFLS), limit violation and time of day based load shedding schemes which are usually performed by the operator.
Reliability and quality of power supply are key parameters which need to be ensured by any utility. Reduced outage time duration to customer, shall improve over all utility reliability indices hence FMSR or automated switching applications plays an important role. The two main features required by a FMSR are: Switching management & Suggested switching plan
The DMS application receives faults information from the SCADA system and processes the same for identification of faults and on running switching management application; the results are converted to action plans by the applications. The action plan includes switching ON/OFF the automatic load break switches / RMUs/Sectionalizer . The action plan can be verified in study mode provided by the functionality . The switching management can be manual/automatic based on the configuration.
Load balancing via feeder reconfiguration is an essential application for utilities where they have multiple feeders feeding a load congested area. To balance the loads on a network, the operator re-routes the loads to other parts of the network. A Feeder Load Management (FLM) is necessary to allow you to manage energy delivery in the electric distribution system and identify problem areas. A Feeder Load Management monitors the vital signs of the distribution system and identifies areas of concern so that the distribution operator is forewarned and can efficiently focus attention where it is most needed. It allows for more rapid correction of existing problems and enables possibilities for problem avoidance, leading to both improved reliability and energy delivery performance.
On a similar note, Feeder Reconfiguration is also used for loss minimization. Due to several network and operational constraints utility network may be operated to its maximum capability without knowing its consequences of losses occurring. The overall energy losses and revenue losses due to these operations shall be minimized for effective operation. The DMS application utilizes switching management application for this, the losses minimization problem is solved by the optimal power flow algorithm and switching plans are created similar to above function
Distribution Load Forecasting (DLF) provides a structured interface for creating, managing and analyzing load forecasts. Accurate models for electric power load forecasting are essential to the operation and planning of a utility company. DLF helps an electric utility to make important decisions including decisions on purchasing electric power, load switching, as well as infrastructure development.
Load forecasting is classified in terms of different planning durations: short-term load forecasting or STLF (up to 1 day, medium-term load forecasting or MTLF (1 day to 1 year), and long-term load forecasting or LTLF (1–10 years). To forecast load precisely throughout a year, various external factors including weathers, solar radiation, population, per capita gross domestic product seasons and holidays need to be considered. For example, in the winter season, average wind chill factor could be added as an explanatory variable in addition to those used in the summer model. In transitional seasons such as spring and fall, the transformation technique can be used. For holidays, a holiday effect load can be deducted from the normal load to estimate the actual holiday load better.
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