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.