Improving Outage Management With Smart Grid Technologies

by Tim Taylor, ABB Inc.

Modern, computer-based outage management systems (OMSs) using connectivity models and graphical user interfaces have been in operation for some time. An OMS typically includes functions such as trouble-call handling, outage analysis and prediction, crew management and reliability reporting. Connectivity maps of the distribution system assist operators with outage management, including partial restorations and detection of nested outages.

Today’s OMS is a mission-critical system. At some utilities, hundreds of users can use it simultaneously. It integrates information about customers, system status and resources such as crews, providing a platform for operational decision support.

Integrated OMSs provide value in several ways. They provide means for faster fault identification and assist in reducing interruption duration, leading to improved reliability performance. More efficient assignment and tracking of field personnel leads to reduced operating costs.

Customer satisfaction increases through reduced outage times and the capability to give customers better information about outages, such as causes, extent and restoration time estimates. OMSs also improve internal and external reliability reporting and can lead to improved coordination of planned and unplanned work.

Recent discussion and activities centered on the emerging smart grid have prompted questions about how smart grid technologies can improve outage management processes.

Let’s examine three ways that outage management will interact with the smart grid:


  1. integration of advanced metering infrastructure (AMI) data in OMSs,
  2. the use of advanced applications for supporting outage management, and
  3. the integration of supervisory control and data acquisition (SCADA) with distribution management systems (DMS) and OMSs.


The Integration of AMI Data in OMSs

AMI is a key component of many distribution organizations’ smart grid plans. Business cases are being built on the premise that AMI systems with the right functionality can improve system operations.

How can AMI data be leveraged for improved outage management? Interfaces between AMI/meter data management (MDM) and the OMS already have been developed. Work continues to enhance the functionality, but already there are several ways AMI data can improve the outage management process.

First, if the AMI meters and communications are so equipped, the OMS can receive a last-gasp or outage notification message from the meter when it loses voltage (that is, a customer outage event has occurred.) That way the OMS is notified of any customer outages, even if the customer doesn’t report it.

Receiving outage notification messages is in addition to phone calls from customers reporting outages. These messages are particularly useful when no one is at a property where an outage occurred or when people there are asleep. The outage notification message can reduce customer interruption times and result in a more efficient dispatch of repair crews.

Second, with the proper interface between the OMS and AMI system and the right communications infrastructure and meter, a message can be sent from the OMS to query if a meter is in service. This is sometimes referred to as “pinging the meter.” The meter can be pinged directly, assuming the AMI communications permits it, or the MDM can be pinged to determine the status of a meter. The meter can be pinged either by a customer service representative or an operator.

A value in pinging is that many customer outage reports are results of problems on customer sides of meters. Utilities commonly report that 50 to 67 percent of single-customer-call outages are results of problems on the customer side of meters and not the responsibility of distribution organizations. If personnel can ping a meter to determine it has voltage despite a customer’s reports of no power, responding troubleshooters and crews could save time and vehicle miles.

Another value in meter query is in the ability to potentially perform outage scoping, or define the outage area by pinging select meters. This can lead to a faster definition of the outage area.

A third area in which interfaces between OMSs and AMI systems can provide value is through restoration notifications. They provide confirmation to distribution operators that customers have been restored downstream of a particular protective device. Restoration notification can be done through a restoration notification message transmitted from the restored meter to the OMS or through pinging of meters that presumably have been restored. The value of restoration notifications is that when all customers have not been restored because of a nested outage within the larger outage area, field personnel can be notified of additional problems before they leave the area.

Improved ways of using AMI infrastructure for improved outage notification still are being explored. In addition, the use of other AMI data in DMS applications, such as interval demand data and voltage violations, is being investigated.

Advanced Applications for Supporting Outage Management

As distribution organizations have become more interested in increasing asset utilization and reducing operational costs, advanced DMS applications have been developed. These include load allocation and unbalanced load flow analysis; switch order creation, simulation, approval and execution; overload reduction switching and capacitor and voltage regulator control.

Two specific examples of advanced applications that reduce customer outage durations are the fault-location application and the restoration switching analysis application.

The fault-location application estimates the location of an electrical fault on the system. This is different than estimating the protective device that actually opened, which typically is done based on the pattern of customer outage calls or through change in a SCADA status point. The location of the electrical fault is where the short-circuit fault occurred, whether it was a result of vegetation, wildlife, lightning or something else.

Finding the location of an electrical fault can be difficult for crews, particularly on long extents of conductor not segmented by protective devices. Fault location tends to be more difficult when troubleshooters or crews are hindered by rough terrain, heavy rain, snow and darkness. The more time required to locate the fault, the more time customers are without power.

ABB’s fault-location algorithm uses the as-operated electric network model, including the circuit connectivity, location of open switches and lengths and impedances of conductor segments, to estimate fault location. Fault current information such as magnitude, predicted type of fault and faulted phases are obtained by the DMS from intelligent electronic devices such as relays, recloser controls or RTUs.

After possible fault locations are calculated within the DMS application, possible fault locations are geographically presented to the operator on the console’s map display and in tabular displays. If a geographic information system (GIS) land base has been included, such as a street overlay, an operator can communicate to the troubleshooter the possible location including nearby streets or intersections. This information helps crews find faults more quickly. As business rules permit, upstream isolation switches can be operated and upstream customers can be re-energized more quickly, resulting in much lower interruption durations.

The DMS fault-location application uses the electrical DMS model and fault current information from IEDs to improve outage management. Progress Energy Carolinas’ experience with the ABB fault-location application shows a significant reduction in System Average Interruption Duration Index (SAIDI) over the six years since the application has been in operation.

A second advanced application that improves reliability performance indices is restoration switching analysis. This application can improve the evaluation of all possible switching actions to isolate a permanent fault and restore customers as quickly as possible.

Upon the occurrence of a permanent fault, the application evaluates all possible switching actions and executes an unbalanced load flow to determine overloaded lines and low-voltage violations if the switching actions were performed. The operator receives a summary of the analysis, including a list of recommended switching actions. Similar to the fault-location application, the functionality uses the DMS model of the system but improves outage management and reduces the Customer Average Interruption Duration Index (CAIDI) and SAIDI.

The restoration switching analysis application is particularly valuable during heavy loading and when the number of potential switching actions is high. Depending on the option selected, the application can execute with the operator in the loop or in a closed-loop manner without operator intervention.

In closed-loop operation, the restoration switching analysis application transmits control messages to distribution devices using communications networks such as SCADA radio, paging or potentially AMI infrastructure. Such an automated isolation and restoration process approaches what many call the “self-healing” characteristic of a smart grid.

Integrated SCADA/DMS/OMS

Integration of DMS/OMS with SCADA is an increasing trend. While the inclusion of SCADA breaker-open operations in OMSs have been used for outage detection, recent business challenges have driven a more comprehensive integration between the systems. Available functionality now includes the transfer of status/analog points from SCADA to the DMS/OMS; the sending of supervisory control and manual override commands from the DMS/OMS to the SCADA; an integrated user interface running on the same operator console and integrated single sign-on for users.

Benefits of integrating SCADA with DMS/OMS include:


  • Improved operations by close integration of DMS applications with distribution SCADA,
  • Increased operator efficiency with one system, eliminating the need for multiple systems with potentially different data,
  • Integrated security analysis for substation and circuit operations to check for tags in one area affecting operations in the other,
  • Streamlined login and authority management within one system,
  • One network model for OMS and DMS analysis, and
  • Consolidated system support for DMS/OMS and distribution SCADA.


A common objective of distribution organizations is improved situational awareness and control of distribution systems, particularly during storm response. By providing access to hundreds of thousands–or in the future, millions–of points, SCADA can provide valuable data to the operators and advanced applications in storm scenarios. This will include the use of decentralized intelligence in substations and feeders for reconfiguring the system automatically in case of faults. Such systems will need to be coordinated and monitored by a centralized system. The benefits will include faster identification of outage areas, improved awareness of the system state and improved management of resources in the storm restoration.


Tim Taylor is the business development manager of DMS for ABB Inc. He has been with ABB for 14 years in engineering, consulting and business development roles. Taylor has performed distribution planning studies for companies around the world and has developed and taught courses on distribution planning and engineering. He is a senior member of IEEE with a master’s degree in electrical engineering from North Carolina State University and an MBA from The University of North Carolina at Chapel Hill. E-mail him at

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