Effectively monitoring and managing the distribution system using today’s advanced DMS applications involves a sophisticated electrical model that is more complex than those needed for static, balanced transmission systems.

Real-time power flow and load estimation for an unbalanced, three-phase network must incorporate telemetered data from a variety of sources on the system, along with information from GIS and planning models. Data from sources such as AMI, line sensors, and an array of intelligent controls (breakers, switches, capacitors, regulators, etc.) must all be processed quickly and efficiently to allow the system to react in real-time to changing system conditions.

The system must always be able to accurately represent the state of the network at any given time, as the distribution automation and analysis functions and applications all rely on this network model.

The PRISM DMS also utilizes this model to allow the system dispatcher to perform ad-hoc load flow queries on the system.

To facilitate creation of the distribution model, the PRISM DMS includes DASmap—a powerful GIS import and model creation tool that enables utilities to automatically create the real-time database, system model and operational displays from GIS and engineering model source data.

DASmap even supports incremental updates from the GIS, simplifying the change synchronization process significantly.

Smart Grid distribution management and distribution automation functions and applications all rely on an accurate model of the state of the network.

Rather than each application determining the network state or network topology, the Topology Processor (TP) calculates the current real-time state to be used by all of the applications as well as by the user interface to colorize the network maps.

Topology processor begins with the static model “as-built”’ connectivity of the network imported from the GIS.

The update from the GIS is the source definition of the connectivity and serves to define the network structure. TP dynamically updates the connectivity by adding the telemetered and manually updated state of the switching devices in the network in order to calculate the ‘topology’. Other applications such as Real-time Redline enable the operator to apply cuts and jumpers which represent temporary of emergency network changes that affect connectivity and therefore topology.

Every system application dynamically adapts to the topology changes in real-time.

Switching order creation applications which generate switching steps in order to meet various objective functions will likewise dynamically adapt to the real-time topology changes.

Topology Processor maintains in real-time the network configuration based on the network connectivity model and dynamic switch statuses.

The function produces the visual and modeled topology of energized and de-energized sections or areas of the distribution system for display and analytical purposes. In addition, it provides visual features such as colorization to distinguish devices that are supplied from different feeders. In the event of a loop created in the distribution network due to switch operations, the function will provide visual indications to highlight all branch devices on the loop and alert the dispatcher.

The feeder network with real-time switch status is calculated to show the current state of the feeder’s topology. Each feeder is colored to show the extent of the circuit.

The PRISM Fault detection, isolation and restoration (FDIR) application is designed for automated fault handling on distribution systems with radial or open loop configurations.

The distribution system can consist of feeder sections with three phases, two phases or single phase. It provides the following fundamental control functions:

• Detect and isolate feeder faults (phase to phase and phase to ground faults)
• Automatically restore service to the feeder sections upstream of the fault (Primary Restoration)
• Provide a switching sequence that can be activated by the dispatcher to automatically restore service to the feeder sections downstream of the fault (Secondary Restoration)
• Provide a switching sequence that can be activated by the dispatcher to automatically connect the de energized feeder sections to available alternative sources if faults appear on the substation side of the feeder breaker.
• Provide a switching sequence that can be activated by the dispatcher to return the distribution system to its pre fault configuration when previously faulted feeder sections become available for service.
• The feeder fault detection and isolation function of the FDIR software can be automatically initiated when a feeder breaker trip signal is received. If the breaker has reclosing relays, FDIR will not start execution until it detects subsequent failures of fast reclosing of the feeder breaker to clear the fault.

When the presence of a fault in the feeder is detected, FDIR will identify the fault location by logically analyzing the real time data from the RTUs on the faulted feeder, automatically isolate the faulted feeder section if the related line switches are in remote control mode. After ensuring the fault isolation, FDIR starts to make the primary restoration by re-energizing the feeder sections upstream of the fault. The total time for FDIR to complete all the necessary actions from the moment the fault is detected to the display of feeder re-energization data at the dispatcher console is normally less than 30 seconds.

The function of fault detection and isolation is executed in parallel by FDIR. While single faults occurring simultaneously on several different feeders, they can be handled in a parallel manner and each one can be completed in a few seconds. There is no hard limit on the number of single faults on different feeders occurring simultaneously for FDIR to process at the same time.

The primary objective of the Integrated Volt/VAR Control (IVVC) function is to reduce electric feeder losses while minimizing distribution voltage within acceptable operating limits.

The controls used to achieve these objectives are transformer Load Tap Changers (LTCs), substation and feeder capacitor bank controls plus substation and feeder voltage regulators.

Inherently the IVVC function improves energy conservation by reducing load demand in both peak and non-peak periods of operation of the distribution system. The load demand reduction is achieved through minimizing the power loss while maintaining voltage as low as possible without violating distribution voltage constraints. IVVC attains power loss reduction by setting transformer taps and by controlling capacitor banks while feeder voltages are kept above the low limit through a coordinated adjustment of voltage regulators. In order to determine an optimum control strategy without adjusting and readjusting the controls, which interact with each other, a real time three-phase unbalanced distribution Load Flow is used. The Load Flow is used to determine reactive power requirements at various capacitor bank locations as well as for the entire feeder under different iterations of the scenario.

In the process of capacitor bank control, individually operable capacitors on the feeder are identified by topology tracing from a feeder breaker downstream. Feeder loads are estimated to calculate voltage, branch flows, and power factors. The branch flows at capacitor locations are analyzed so that the capacitor banks are sorted in descending order based on their branch reactive power flows. The capacitor with the largest branch reactive power is selected as a control candidate. Its impact on feeder voltages is calculated and checked against the limits. If any constraint is violated, this capacitor bank will be passed over and the next capacitor is processed. Otherwise, a control command is issued to operate this capacitor bank. For example a capacitor needs to be operated if there exists a significant amount of lagging reactive power flow on the feeder breaker. Likewise, it needs to be turned off if there is a large amount of leading reactive power flow on the feeder breaker. The decision can be made through a series of load flow calculations. Finally, to verify if a given capacitor operation violates any voltage constraints, the changes in voltage and power factor are calculated considering the effect of the capacitor operation.

To prevent unbalance switching of a capacitor bank, a verification procedure is followed to check if any switch operation has failed. If so, this capacitor bank will be disabled for future control and an alarm is issued to notify the dispatcher. The above process is repeated until distribution loss is minimized or no capacitor is available for control. The disabled capacitor bank can be re-enabled by the dispatcher once it has been repaired and is ready for use. Defined rules are applied to determine the control action for each capacitor bank, considering maximum number of control operations, minimum on, or minimum off times and an adjustable dead band to prevent unnecessary controls.

The Optimal Capacitor Placement (OCP) application is a study mode function that directly connects to the DASdb and the RTDB.

The objective of OCP is to minimize feeder losses while maintaining the capacitor bank voltages and power factors within given limits. The optimal capacitor placement starts from a base case that may be derived from the real time operational condition or a DPF saved case. The user has the capability to specify which capacitor banks can be relocated and which cannot, as well the network buses that can be located with capacitor banks. OCP will then determine both the best locations of the capacitor banks and the optimal on/off status of the capacitor banks needed to meet the specified optimization objective.

All ‘Cuts’ and ‘Jumpers’ placed on the system are marked by an icon on the map for easy identification.

Similar to the Optimal Switch Plan application, the Intelligent Switching (ISW) application provides the capability to generate various switch plans for both planned and unplanned operational situations.

It is expected that these switch plans will be generated on an ad hoc basis by the dispatcher, or generated as scheduled switching operations.

The switch plans generated will observe all violations and criteria as in the OSW application. The primary switching operations to be supported by ISW are:

• Return-to-Normal: generate a switch plan which will return the system to its normal feeder topology
• Outage Plan and Scheduling: generate a switch plan which will produce an isolation and restoration plan for outage scheduling and device maintenance
• Restoration: generate a switch plan which will restore de-energized line segments and loads
• Cold Start: generate a switch plan which will match the load to the generation
• In each case whenever it is not possible to restore all un-faulted network section due to violations, the application will provide options that allow consideration of constraint relaxation. When appropriate, the operator can accept a plan based on a selected constraint relaxation.

The Optimal Switching (OSW) application is designed to generate recommended switch plans to reconfigure a distribution system in order to meet a specified optimization objective with regards to operation.

Optimal Switching meets specified optimization objectives:

• Minimum losses: minimize the network power loss for the current or a selected network loading condition by reconfiguring the available switch operations
• Minimum feeder voltage drops: achieve the flattest voltage profile while maintaining the lowest end-of-line voltage still within operating limits
• Phase balancing: provide a switching plan to switch individual phases in order to shift the normally open point per phase in order to balance the phases
• Load Balancing: provide a switching plan to balance the load equally between feeders within the area of analysis

For each objective, the optimal solution is obtained while enforcing the following operational constraints:

• Respect operating limits of feeder voltages
• Respect operating limits of branch device currents
• Operating limits of transformer voltages and currents
• No interruption of customer loads
• No loss of customer loads
• Minimum number of switch operations
• Minimum number of ineffective switch operations
• In-rush current for cold load pick up
• The available switching devices that are studied include feeder line switches, tie-switches, breakers as well as reclosers. The Optimal Switching application also advises the user of any possible loop conditions.

The PRISM dispatcher distribution load flow (DLF) is used as a dispatcher query tool for ad-hoc load flow queries, as a planning tool for in-depth network analysis, and as a basis for many advanced distribution analysis / automation applications such as Short Circuit Analysis, Switch Order Optimization, Fault Detection Isolation and Restoration, etc.

The PRISM distribution load flow operates from the same network model as that created by DASmap for all advanced applications.

The PRISM distribution load flow is implemented to compute phase voltage magnitudes for each feeder or network node as well as phase and neutral currents for each branch (line, switch and transformer). The active and reactive losses on each branch, as well as accumulated total and per phase losses for each substation and feeder can also be computed. The PRISM DLF model is implemented utilizing Ybus Gauss solution method that uses sparse Ybus matrix and equivalent current injections to solve distribution network equations. This method has been proven to have rapid convergence rate and less memory usage for distribution networks. The PRISM distribution load flow model applies three-phase sequence model that converts unbalanced three phases into positive, negative and zero sequence phases. After the power flow solution, sequence phases will convert back to three regular phases.

PRISM DMS provides two different analysis modes: Real-time and Study.

Each mode is independent of the other mode, i.e., changes made by one user in one analysis mode do not affect the other user in study mode. In study mode the user can operate various devices and observe the effect on the system through topology processor or by running a load flow and viewing the results. This is a powerful tool that can be used to study the effects on the system of various system modifications or switching operations. The results of the load flow are colorized and displayed on the operator interface for a quick study, or for more detailed analysis the results can be viewed in a tabular form and exported. Scope of analysis by DPF can be divided into the following categories:

• Study Scope I: Entire System, where all nodes in all feeders and in all substations are analyzed
• Study Scope II: Substation, where only the nodes on the feeders of the selected substation are analyzed
• Study Scope III: A group of substations where only the nodes on the feeders of the substations in the selected group are analyzed
• Study Scope IV: Feeder, where only the nodes on the selected feeder are analyzed

Short Circuit Analysis (SCA) calculates fault current sources to fault points, using programmable criteria for theoretical or reconstructed situations and scenarios. SCA uses the same solution algorithm as Distribution Power Flow (DPF), representing all loads, capacitor banks and short circuit faults as constant impedances. Source voltages behind the internal impedances are calculated based on the DPF solution.

When a fault occurs in an SCA context, the fault impedance will connect from the fault location to ground, or to another phase, depending upon the fault type. The positive–, negative– and zero–sequence networks are created, and the fault current is computed using the DPF.

SCA offers an array of controls and user–programmable conditions:

• Study scope (study voltage level)
• Fault locations (substation, feeder, node/device)
• Faulted phases (any combination of single–, two– and three–phase to phase, and phase to ground)
• Fault types
• Fault impedance
• Zero pre–fault currents

Protection Coordination (PCN) provides the system operation engineer and dispatcher a tool to review, edit or analyze the protective device settings.

The protective devices include relays, reclosing relays and fuses. PCN presents to the dispatcher the actual “time-current” curves of protective devices along the feeder for graphical analysis and manipulation based on known fault currents.

Load Estimation (LE) is a function used to estimate individual loads on a feeder based on load classes, load type, load curve, and load measurements.

• The Load Class specifies the nature of a load, such as residential, commercial, or industry load. It is used to divide the feeder load into several components, each of them having the same nature or class
• The Load Type specifies the characteristics of a load in terms of its relationship between its real and reactive power. There are two different load types: conforming and non–conforming. A conforming load uses power factor as a fixed ratio between its real and reactive power; while a non–conforming load defines its real and reactive power by its “load versus time” curves respectively
• Load measurements are telemetered load values through the SCADA system. They can be either an individual load measurement or a branch load flow measurement

In the Load Estimation function, individual loads on each node are calculated by two methods:

• Static Load Estimation (SLE): individual loads are identified through the ownership between loads and the feeders carrying those loads
• Dynamic Load Estimation (DLE): the real–time branch flow measurements are used to adjust load values obtained by static load estimation to produce dynamic load estimation