IEEE Power & Energy Magazine - July/August 2019 - 50

Substation automation functions and any other functions that
do not operate in absolute real time, including equipment
monitoring, will become services in the substation edge device.
and reliably support changing power flows and operating scenarios. New types of analytic applications may be required to
coordinate storm response when the distribution system is also
a source, to do better network modeling that allows dynamic
line loading, and even to perform local state estimation for
operations and dynamic protection. Developing and adding
these new applications as software services are the only costeffective and timely ways to provide them.
This version of the substation of the future shows protection and substation automation as standalone devices, as in
today's substations. However, this cannot continue. Substation automation functions and any other functions that do
not operate in absolute real time, including equipment monitoring, will become services in the substation edge device.
As distribution circuits become strong sources because of
DERs and become more networked, distribution protection
will adopt transmission protection techniques, such as line
differential and teleprotection schemes. Relay settings will
be more dynamic at both the transmission and distribution
level. Relays must operate reliably for the different network
conditions and levels of short circuit current resulting from
variable resources coming online and offline. Faults must
be identified and cleared correctly, even in the presence
of declining system inertia and decreased system stability
clearing times. The only cost-effective and timely manner to
meet these needs will be to roll out new protection schemes
as a software service so that protection will become a realtime application in the substation edge device.

Next Steps
The substation of the future is both fully digital and digitally
enabled for applications running as software services. The
substation of today is not. It is important to understand the
steps to go from the substation architecture of today to one
of the future. In a practical manner, this requires two separate steps.
One step is to go fully digital. Communications between
substation gateways and zone devices, for example, protective relays and bay control units, are already digital. The
complete digital substation means implementing process
buses, which are distributed input/output (I/O) devices for
protection and control and substation automation. A process bus digitizes the interfaces to all primary equipment,
including binary status and control points for circuit breakers and power transformers, and all analog data, such as currents and voltages from instrument transformers. Communications used in this process are defined by the IEC 61850
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standard. Going fully digital by implementing process bus
is a step that can be taken today. The technology needed
is widely commercially available, and going fully digital
provides many benefits today in terms of both capital and
operating expenses.
The other step is to be digitally enabled using a substation
edge device that supports a software services architecture.
This concept is shown in Figure 3. Such devices, designed
for applications in utility substations, are becoming available in the market. Substation edge devices will first implement standard substation gateway functions, and then they
will support other new power system and control applications as they are developed. Future versions will support the
addition of a real-time operating system so that protection
functions can be created as applications. Therefore, all application processing in a substation will be a software service
in the substation edge device, centralizing protection, automation, monitoring, and analytics. The next step is to start
defining the necessary new applications and system operating conditions while evaluating substation edge devices as
they become available.

Process Bus
The goal of a digital substation is maximum flexibility and
adaptability. To make this possible, it is necessary to separate the control functions, including protective relaying, from
the primary equipment being controlled. The way to do this
is process bus, where analog values are converted to digital
sampled values at the primary equipment, and these sampled
values, along with status and control signals, are transmitted
through a communications channel to protection equipment.
Digitization takes place in simple I/O devices integrated
into primary equipment using the data models and message
formats of the IEC 61850 standard. Process bus facilitates
flexibility and adaptability because the basic data for state,
status, and control of the substation are available on the process bus network. Any device or application connected to
this network can subscribe to the data without impacting
other devices or applications and without connecting to the
primary equipment.
The reason to use the IEC 61850 standard for communications is to provide a future-proof digital substation architecture that can be easily configured, updated, and maintained.
The configuration of a process bus system is easily verified
through standard tools, as the data models provide a selfdescription of the data being sent. The majority of messages
are event driven, using a multicast publish-subscribe model.
july/august 2019

IEEE Power & Energy Magazine - July/August 2019

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