Distribution management system

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A distribution management system (DMS) is a collection of applications designed to monitor and control the electric power distribution networks efficiently and reliably. It acts as a decision support system to assist the control room and field operating personnel with the monitoring and control of the electric distribution system. Improving the reliability and quality of service in terms of reducing power outages, minimizing outage time, maintaining acceptable frequency and voltage levels are the key deliverables of a DMS. Given the complexity of distribution grids, such systems may involve communication and coordination across multiple components. For example, the control of active loads may require a complex chain of communication through different components as described in USpatent 11747849B2  

Contents

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.

Overview

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.

DMSs access real-time data and provide all information on a single console at the control centre in an integrated manner. Their development varied across different geographic territories. In the US, for example, DMSs typically grew by taking Outage Management Systems to the next level, automating the complete sequences and providing an end to end, integrated view of the entire distribution spectrum. In the UK, by contrast, the much denser and more meshed network topologies, combined with stronger Health & Safety regulation, had led to early centralisation of high-voltage switching operations, initially using paper records and schematic diagrams printed onto large wallboards which were 'dressed' with magnetic symbols to show the current running states. There, DMSs grew initially from SCADA systems as these were expanded to allow these centralised control and safety management procedures to be managed electronically. These DMSs required even more detailed component/connectivity models and schematics than those needed by early OMSs as every possible isolation and earthing point on the networks had to be included. In territories such as the UK, therefore, the network component/connectivity models were usually developed in the DMS first, whereas in the USA these were generally built in the GIS.

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).

Why DMS?

DMS Functions

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:-

Network Connectivity Analysis (NCA)

Distribution network usually covers over a large area and catering power to different customers at different voltage levels. So locating required sources and loads on a larger GIS/Operator interface is often very difficult. Panning & zooming provided with normal SCADA system GUI does not cover the exact operational requirement. Network connectivity analysis is an operator specific functionality which helps the operator to identify or locate the preferred network or component very easily. NCA does the required analyses and provides display of the feed point of various network loads. Based on the status of all the switching devices such as circuit breaker (CB), Ring Main Unit (RMU) and/or isolators that affect the topology of the network modeled, the prevailing network topology is determined. The NCA further assists the operator to know operating state of the distribution network indicating radial mode, loops and parallels in the network.

Switching Schedule & Safety Management

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 Pemit 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.

State Estimation (SE)

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 Applications (LFA)

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 (VVC)

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.

In the legacy grid, there are three primary tools for carrying out voltage management: Load Tap Changers (LTCs), voltage regulators, and capacitor banks. LTCs and voltage regulators refer to transformers with variable turns ratios that are placed at strategic points in a network and adjusted to raise or lower voltage as is necessary. Capacitor banks manage voltage by “generating” reactive power, and have thus far been the primary tools through which true Volt/VAR control is carried out. These large capacitors are connected to the grid in shunt configuration through switches which, when closed, allow the capacitors to generate VARs and boost voltage at the point of connection. In the future, further VVC might be carried out by smart inverters and other distributed generation resources, which can also inject reactive power into a distribution network. A VVC application helps the operator mitigate dangerously low or high voltage conditions by suggesting required action plans for all VVC equipment. The plan will give a required tap position and capacitor switching state to ensure the voltage stays close to its nominal value and thus optimize Volt-VAR control function for the utility.

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.

Load Shedding Application (LSA)

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.

Fault Management & System Restoration (FMSR)

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 (LBFR)

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)

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.

Various predictive models have been developed for load forecasting based on various techniques like multiple regression, exponential smoothing, iterative reweighted least-squares, adaptive load forecasting, stochastic time series, fuzzy logic, neural networks and knowledge based expert systems. Amongst these, the most popular STLF were stochastic time series models like Autoregressive (AR) model, Autoregressive moving average model (ARMA), Autoregressive integrated moving average (ARIMA) model and other models using fuzzy logic and Neural Networks.

DLF provides data aggregation and forecasting capabilities that is configured to address today's requirements and adapt to address future requirements and should have the capability to produce repeatable and accurate forecasts.

Standards Based Integration

In any integrated energy delivery utility operation model, there are different functional modules like GIS, Billing & metering solution, ERP, Asset management system that are operating in parallel and supports routine operations. Quite often, each of these functional modules need to exchange periodic or real time data with each other for assessing present operation condition of the network, workflows and resources (like crew, assets, etc.). Unlike other power system segments, distribution system changes or grows every day, and this could be due to the addition of a new consumer, a new transmission line or replacement of equipment. If the different functional modules are operating in a non-standard environment and uses custom APIs and database interfaces, the engineering effort for managing shall become too large. Soon it will become difficult to manage the growing changes and additions which would result in making system integrations non- functional. Hence utilities cannot make use of the complete benefit of functional modules and in some cases; the systems may even need to be migrated to suitable environments with very high costs.

As these problems came to light, various standardization processes for inter application data exchanges were initiated. It was understood that a standard based integration shall ease the integration with other functional modules and that it also improves the operational performance. It ensures that the utility can be in a vendor neutral environment for future expansions, which in turn means that the utility can easily add new functional modules on top of existing functionality and easily push or pull the data effectively without having new interface adapters.

IEC 61968 Standards Based Integration

IEC 61968 is a standard being developed by the Working Group 14 of Technical Committee 57 of the IEC and defines standards for information exchanges between electrical distribution system applications. It is intended to support the inter-application integration of a utility enterprise that needs to collect data from different applications which could be new or legacy.

As per IEC 61968, a DMS encapsulates various capabilities like monitoring and control of equipment for power delivery, management processes to ensure system reliability, voltage management, demand-side management, outage management, work management, automated mapping and facilities management. The crux of IEC 61968 standards is the Interface Reference Model (IRM) that defines various standard interfaces for each class of applications. Abstract (Logical) components are listed to represent concrete (physical) applications. For example, a business function like Network Operation (NO) could be represented by various business sub-functions like Network Operation Monitoring (NMON), which in turn will be represented by abstract components like Substation state supervision, Network state supervision, and Alarm supervision.

IEC 61968 recommends that system interfaces of a compliant utility inter-application infrastructure be defined using Unified Modelling Language (UML). UML includes a set of graphic notation techniques that can be used to create visual models of object-oriented software-intensive systems. The IEC 61968 series of standards extend the Common Information Model (CIM), which is currently maintained as a UML model, to meet the needs of electrical distribution. For structured document interchange particularly on the Internet, the data format used can be the Extensible Markup Language (XML). One of its primary uses is information exchange between different and potentially incompatible computer systems. XML is thus well-suited to the domain of system interfaces for distribution management. It formats the message payloads so as to load the same to various messaging transports like SOAP (Simple Object Access Protocol), etc.

Related Research Articles

In electrical engineering, the power factor of an AC power system is defined as the ratio of the real power absorbed by the load to the apparent power flowing in the circuit. Real power is the average of the instantaneous product of voltage and current and represents the capacity of the electricity for performing work. Apparent power is the product of root mean square (RMS) current and voltage. Due to energy stored in the load and returned to the source, or due to a non-linear load that distorts the wave shape of the current drawn from the source, the apparent power may be greater than the real power, so more current flows in the circuit than would be required to transfer real power alone. A power factor magnitude of less than one indicates the voltage and current are not in phase, reducing the average product of the two. A negative power factor occurs when the device generates real power, which then flows back towards the source.

<span class="mw-page-title-main">Power outage</span> Loss of electric power to an area

A power outage is the loss of the electrical power network supply to an end user.

<span class="mw-page-title-main">Electrical substation</span> Part of an electrical transmission, and distribution system

A substation is a part of an electrical generation, transmission, and distribution system. Substations transform voltage from high to low, or the reverse, or perform any of several other important functions. Between the generating station and consumer, electric power may flow through several substations at different voltage levels. A substation may include transformers to change voltage levels between high transmission voltages and lower distribution voltages, or at the interconnection of two different transmission voltages. They are a common component of the infrastructure. There are 55,000 substations in the United States.

In electrical engineering, particularly power engineering, voltage regulation is a measure of change in the voltage magnitude between the sending and receiving end of a component, such as a transmission or distribution line. Voltage regulation describes the ability of a system to provide near constant voltage over a wide range of load conditions. The term may refer to a passive property that results in more or less voltage drop under various load conditions, or to the active intervention with devices for the specific purpose of adjusting voltage.

<span class="mw-page-title-main">Recloser</span>

In electric power distribution, automatic circuit reclosers (ACRs) are a class of switchgear designed for use on overhead electricity distribution networks to detect and interrupt transient faults. Also known as reclosers or autoreclosers, ACRs are essentially rated circuit breakers with integrated current and voltage sensors and a protection relay, optimized for use as a protection asset. Commercial ACRs are governed by the IEC 62271-111/IEEE Std C37.60 and IEC 62271-200 standards. The three major classes of operating maximum voltage are 15.5 kV, 27 kV and 38 kV.

An energy management system (EMS) is a system of computer-aided tools used by operators of electric utility grids to monitor, control, and optimize the performance of the generation or transmission system. Also, it can be used in small scale systems like microgrids.

<span class="mw-page-title-main">Switchgear</span> Control gear of an electric power system

In an electric power system, a switchgear is composed of electrical disconnect switches, fuses or circuit breakers used to control, protect and isolate electrical equipment. Switchgear is used both to de-energize equipment to allow work to be done and to clear faults downstream. This type of equipment is directly linked to the reliability of the electricity supply.

Electric power quality is the degree to which the voltage, frequency, and waveform of a power supply system conform to established specifications. Good power quality can be defined as a steady supply voltage that stays within the prescribed range, steady AC frequency close to the rated value, and smooth voltage curve waveform. In general, it is useful to consider power quality as the compatibility between what comes out of an electric outlet and the load that is plugged into it. The term is used to describe electric power that drives an electrical load and the load's ability to function properly. Without the proper power, an electrical device may malfunction, fail prematurely or not operate at all. There are many ways in which electric power can be of poor quality, and many more causes of such poor quality power.

Advanced Distribution Automation (ADA) is a term coined by the IntelliGrid project in North America to describe the extension of intelligent control over electrical power grid functions to the distribution level and beyond. It is related to distribution automation that can be enabled via the smart grid. The electrical power grid is typically separated logically into transmission systems and distribution systems. Electric power transmission systems typically operate above 110kV, whereas Electricity distribution systems operate at lower voltages. Normally, electric utilities with SCADA systems have extensive control over transmission-level equipment, and increasing control over distribution-level equipment via distribution automation. However, they often are unable to control smaller entities such as Distributed energy resources (DERs), buildings, and homes. It may be advantageous to extend control networks to these systems for a number of reasons:

The Common Information Model (CIM) is an electric power transmission and distribution standard developed by the electric power industry. It aims to allow application software to exchange information about an electrical network. It has been officially adopted by the International Electrotechnical Commission (IEC).

<span class="mw-page-title-main">Phasor measurement unit</span>

A phasor measurement unit (PMU) is a device used to estimate the magnitude and phase angle of an electrical phasor quantity in the electricity grid using a common time source for synchronization. Time synchronization is usually provided by GPS or IEEE 1588 Precision Time Protocol, which allows synchronized real-time measurements of multiple remote points on the grid. PMUs are capable of capturing samples from a waveform in quick succession and reconstructing the phasor quantity, made up of an angle measurement and a magnitude measurement. The resulting measurement is known as a synchrophasor. These time synchronized measurements are important because if the grid’s supply and demand are not perfectly matched, frequency imbalances can cause stress on the grid, which is a potential cause for power outages.

Electrical power system simulation involves power system modeling and network simulation in order to analyze electrical power systems using design/offline or real-time data. Power system simulation software's are a class of computer simulation programs that focus on the operation of electrical power systems. These types of computer programs are used in a wide range of planning and operational situations for electric power systems.

<span class="mw-page-title-main">Smart grid</span> Type of electrical grid

The smart grid is an enhancement of the 20th century electrical grid, using two-way communications and distributed so-called intelligent devices. Two-way flows of electricity and information could improve the delivery network. Research is mainly focused on three systems of a smart grid – the infrastructure system, the management system, and the protection system. Electronic power conditioning and control of the production and distribution of electricity are important aspects of the smart grid.

An outage management system (OMS) is a computer system used by operators of electric distribution systems to assist in restoration of power.

<span class="mw-page-title-main">Electric power system</span> Network of electrical component deployed to generate, transmit & distribute electricity

An electric power system is a network of electrical components deployed to supply, transfer, and use electric power. An example of a power system is the electrical grid that provides power to homes and industries within an extended area. The electrical grid can be broadly divided into the generators that supply the power, the transmission system that carries the power from the generating centers to the load centers, and the distribution system that feeds the power to nearby homes and industries.

IEC 60870 part 6 in electrical engineering and power system automation, is one of the IEC 60870 set of standards which define systems used for telecontrol in electrical engineering and power system automation applications. The IEC Technical Committee 57 have developed part 6 to provide a communication profile for sending basic telecontrol messages between two systems which is compatible with ISO standards and ITU-T recommendations.

<span class="mw-page-title-main">Electrical grid</span> Interconnected network for delivering electricity from suppliers to consumers

An electrical grid is an interconnected network for electricity delivery from producers to consumers. Electrical grids consist of power stations, electrical substations to step voltage up or down, electric power transmission to carry power long distances, and lastly electric power distribution to individual customers, where voltage is stepped down again to the required service voltage(s). Electrical grids vary in size and can cover whole countries or continents. From small to large there are microgrids, wide area synchronous grids, and super grids.

IEC 61968 is a series of standards under development that will define standards for information exchanges between electrical distribution systems. These standards are being developed by Working Group 14 of Technical Committee 57 of the International Electrotechnical Commission. IEC 61968 is intended to support the inter-application integration of a utility enterprise that needs to collect data from different applications that are legacy or new and each has different interfaces and run-time environments. IEC 61968 defines interfaces for all the major elements of an interface architecture for distribution management systems (DMS) and is intended to be implemented with middleware services that broker messages among applications.

IEC 61334, known as Distribution automation using distribution line carrier systems, is a standard for low-speed reliable power line communications by electricity meters, water meters and SCADA. It is also known as spread frequency-shift keying (S-FSK) and was formerly known as IEC 1334 before IEC's most recent renumbering. It is actually a series of standards describing the researched physical environment of power lines, a well-adapted physical layer, a workable low-power media access layer, and a management interface. Related standards use the physical layer, but not the higher layers.

A Distribution Transformer Monitor (DTM) is a specialized hardware device that collects and measures information relative to electricity passing into and through a distribution transformer. The DTM is typically retrofitted onto pole top and pad mount transformers. A pole top or pad mount transformer commonly powers anywhere from 5-8 homes in the US and is the last voltage transition in stepping down voltage before it gets to the home or business. The conventional placement of Distributed Temperature Monitoring (DTM) devices is typically observed at the terminals of transformers. However, there are instances where these devices are directly affixed to the secondary power lines. DTM apparatus commonly comprises precision-centric sensors, either of the non-piercing or piercing variety, in addition to communication modules integrated onboard for seamless data transmission. Adequate provisions for power supply are also incorporated within the DTM setup. The captured data from the DTM unit is relayed to a central data collection engine and/or the established Supervisory Control and Data Acquisition (SCADA) / Meter Data Management (MDM) system, where pertinent information pertaining to the transformer is stored and made accessible to users. Often, analytical platforms come into play to decipher the data gleaned and reported by the DTM, thereby enhancing the comprehension of the acquired information.

References

  1. Yih-Fang Huang; Werner, S.; Jing Huang; Kashyap, N.; Gupta, V., "State Estimation in Electric Power Grids: Meeting New Challenges Presented by the Requirements of the Future Grid," Signal Processing Magazine, IEEE, vol.29, no.5, pp.33,43, Sept. 2012