IEEE Power & Energy Magazine - January/February 2020 - 21

Utilities are adopting newer nonwires alternatives,
such as applications of energy storage at both the T&D level
to serve customers at a competitive rate.
of trouble-call management and coordinating maintenance
with new projects. Utilities must make distribution operations
into a more formal set of operational functions as a result of
the introduction of new sensors and controls, advanced metering infrastructure (AMI) and its associated headend systems,
supervisory control and data acquisition (SCADA) applications to the distribution system, demand response, and timeof-use rates. New sets of systems supporting the new technologies are also required, as discussed in the following sections
(also see "New Systems Definitions").

Meter Data Management Systems
The meter data management system (MDMS) is designed to
store and manage data collected from electric meters. Before
smart meters, data were collected and entered manually. With
the advent of smart meters, measuring energy consumption is
now done automatically, in addition to other services, such as
remote service connect/disconnect and measurements of voltage,
current, harmonics, time-of-day use, and other key parameters.
The MDMS imports the data from the headend, validates them, checks for errors, and then processes the data
before making them available for billing and other analysis.
As smart meters become more prevalent, data are used for
customer billing and a wide variety of other applications,
including outage management, asset management, and analysis of utility operations.

Outage Management System
A significant portion of North America's distribution networks
is still not telemetered. As a result, utilities depend on customers to report outages; customers need to call and report outages
for the utility to gain situational awareness. An outage management system (OMS) automatically collects and analyzes
calls and then determines probable device failures and outage
locations. By using this information, utilities can reduce the
time to identify, prioritize, and resolve network incidents, and
effectively communicate with their customers, field personnel,
and regulators.
From a value perspective, an OMS allows the utility to
reduce the duration of outages (as measured by the System
Average Interruption Duration Index and the Customer Average Interruption Duration Index). An OMS can also improve
a utility's customer communication before, during, and after
outages and achieve greater operational efficiency by reducing
staffing and overtime required at dispatch centers and for storm
restoration activities. In several implementations, MDMSs and
their headend systems are being integrated with OMSs so that
january/february 2020

outages can be more automatically identified instead of solely
relying on customers to call and report their outages.

Geographic Information Systems
Geographic information systems (GISs) are designed to capture, store, manipulate, analyze, manage, and present all types
of geographically referenced data. In simplest terms, GISs
merge cartography, statistical analysis, and database technology. Fundamental to a GIS is its ability to store and correlate
disparate types of data from a variety of devices (transformer,
switch, wood pole, cross arm, and so forth), including ID, location (GPS coordinates), characteristics, and connectivity with
their geospatial rendering. The GIS provides vital information
for modeling and improving operational situational awareness.
From a system operations perspective, the GIS is a foundational system designed (among other things) to deliver as-built
static and physical data to the OMS, advanced distribution
management systems (ADMSs), and other similar systems
that depend on an accurate representation of various power
system components in the field and their connectivity.

Advanced Distribution Management System
An ADMS provides a software platform for automating
outage restoration and optimizing the overall reliable and

New Systems Definitions
* Advanced metering infrastructure can be defined
by the ability to remotely read meters. Over time,
as the meters also became smart, these systems allowed the utility to perform other functions (e.g., remote connect/disconnect) from a central location.
* Supervisory control and data acquisition is a core
capability of transmission and distribution operational systems that allows the operator from a control center to remotely operate devices in the field.
It also brings in field data to the control center.
* The System Average Interruption Duration Index is
the average outage duration for each customer at a
utility and is generally measured in minutes during
the course of a year.
* The Customer Average Interruption Duration Index is the average duration that a customer would
experience at the utility and is also measured in
minutes during the course of a year.

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IEEE Power & Energy Magazine - January/February 2020

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