Electric power systems as we know them began developing in
the early 20th century. Initially, generating plants were associated only with
local loads that typically consisted of lighting and electric transportation.
If anything in the system failed — generating plant, power
lines, or connections — the lights would quite literally be “out.” Customers
had not yet learned to depend on electricity being nearly 100% reliable, so
outages, whether routine or emergency, were taken as a matter of course.
As reliance on electric power grew, so did the need to find
ways to improve reliability. Generating stations and power lines were
interconnected to provide redundancy, and higher voltages were used for longer
distance transportation of electricity.
Points where power lines came together or where voltages
were transformed came to be known as “substations.” Substations often employed
protective devices to allow system failures to be isolated so that faults would
not bring down the entire system, and operating personnel were often stationed
at these important points in the electrical system so that they could monitor
and quickly respond to any problems that might arise. They would communicate
with central system dispatchers by any means available — often by telephone —
to keep them apprised of the condition of the system. Such “manned” substations
were normative throughout the first half of the 20th century.
As the demands for reliable electric power became greater
and as labor became a more significant part of the cost of providing electric
power, technologies known as “supervisory control and data acquisition,” or
SCADA for short, were developed to allow remote monitoring and even control of
key system parameters. SCADA systems began to reduce and even eliminate the
need for personnel to be on-hand at substations.
Early SCADA systems provided remote indication and control
of substation parameters using technology borrowed from automatic telephone
switching systems. As early as 1932, Automatic Electric was advertising
“remote-control” products based on its successful line of “Strowger” telephone
switching apparatus.
Another example (used as late as the 1960s) was an early
Westinghouse REDAC system that used telephone-type electromechanical relay
equipment at both ends of a conventional twisted-pair telephone circuit.
Data rates on these early systems were slow. Data were sent
in the same manner as rotary-dial telephone commands at 10 bps, so only a
limited amount of information could be passed using this technology.
Early SCADA systems were built on the notion of replicating
remote controls, lamps, and analog indications at the functional equivalent of
pushbuttons, often placed on a mapboard for easy operator interface. The SCADA
masters simply replicated, point for point, control circuits connected to the
remote (slave) unit.
During the same time frame as SCADA systems were developing,
a second technology — remote teleprinting, or “Teletype” — was coming of age,
and by the 1960s had gone through several generations of development.
The invention of a second device — the “modem”
(MOdulator/DEModulator) — allowed digital information to be sent over wire
pairs that had been engineered to only carry the electronic equivalent of human
voice communication.
With the introduction of digital electronics it was possible
to use faster data streams to provide remote indication and control of system
parameters. This marriage of Teletype technology with digital electronics gave
birth to remote terminal units (RTUs), which were typically built with discrete
solid-state electronics and could provide remote indication and control of both
discrete events and analog voltage and current quantities.
Beginning also in the late 1960s and early 1970s, technology
leaders began exploring the use of small computers (minicomputers at that time)
in substations to provide advanced functional and communication capability. But
early application of computers in electric substations met with industry
resistance because of perceived and real reliability issues.
The introduction of the microprocessor with the Intel 4004
in 1971 opened the door for increasing sophistication in RTU design that is
still continuing today. Traditional point-oriented RTUs that reported discrete
events and analog quantities could be built in a fraction of the physical size
required by previous discrete designs.
More intelligence could be introduced into the device to
increase its functionality. For the first time RTUs could be built to report
quantities in engineering units rather than as raw binary values. One early
design developed at Northern States Power Company in 1972 used the Intel 4004
as the basis for a standardized environmental data acquisition and retrieval
(SEDAR) system that collected, logged, and reported environmental information
in engineering units using only 4 kilobytes of program memory and 512 nibbles
(half-bytes) of data memory.
While the microprocessor offered the potential for greatly
increased functionality at lower cost, the industry also demanded very high
reliability and long service life measured in decades, conditions that were
difficult to achieve with early devices. Thus the industry was slow to accept
the use of microprocessor technology in mission-critical applications.
By the late 1970s and early 1980s, integrated
microprocessorbased devices were introduced, and these came to be known as
intelligent electronic devices, or IEDs.
Early IEDs simply replicated the functionality of their
predecessors — remotely reporting and controlling contact closures and analog
quantities using proprietary communication protocols. Increasingly, IEDs are
also being used to convert data into engineering unit values in the field and
to participate in field-based local control algorithms. Many IEDs are being
built with programmable logic controller (PLC) capability and, indeed, PLCs are
being used as RTUs and IEDs to the point that the distinction between these
different types of smart field devices is rapidly blurring.
Early SCADA communication protocols were usually proprietary
and were also often kept secret from the industry. A trend beginning in the
mid-1980s has been to minimize the number of proprietary
communication practices and to drive field practices toward
open, standards-based specifications.
Two noteworthy pieces of work in this respect are the
International Electrotechnical Commission (IEC) 870- 5 family of standards and
the IEC 61850 standard. The IEC 870-5 work represents the pinnacle of the
traditional point-list-oriented SCADA protocols, while the IEC 61850 standard
is the first of an emerging approach to networkable, object-oriented SCADA
protocols based on work started in the mid-1980s by the Electric Power Research
Institute (EPRI) that became known as the Utility Communication Architecture
(UCA).
