IEEE Power & Energy Magazine - July/August 2019 - 81

Electrification, where energy used for a service is changed from a
nonelectric source of energy to electricity, holds significant promise
for increasing EE and reducing carbon footprints.
systems that are used on the BPS must have standards to
comply with applicable laws, regulations, and operating
practices. A fundamental underpinning is that an EMS/
SCADA system has monitoring and control of key electric
system components so that the operating states of transmission lines, substations, and generation can be directly known
and managed. Rules are in place for monitoring and control
and must be implemented for any type of generation attached
to the BPS, including wind and solar. A well-managed EMS/
SCADA system operating on the BPS is largely deterministic with a manageable level of randomness. It is critical that
existing rules be maintained and enhanced where needed for
generation that is attached to the BPS.
The situation is very different for the distribution grid.
There is continued growth in the quantity and aggregate
capacity of renewable distributed generation interconnected to
utility distribution systems; these include intelligent electronic
devices (IEDs) such as microprocessor-based relays, reclosers
and switches, voltage regulator and capacitor bank controllers, smart meters, and advanced sensors (including voltage,
current, and combined voltage/current sensors for active/
reactive power metering, power quality meters, temperature,
irradiance, and wind speed sensors, along with phasor measurement units). These smart grid technologies could help
improve metering and operational observability in distribution networks with DERs. Generally, local laws and guidelines do not require that the utility be provided with monitoring and control for each device. Some utilities have SCADA
implemented in the distribution system that can provide deterministic results; however, the inability to monitor and control individually distributed generation plants has resulted in
distribution operations that are increasingly dynamic in areas
with high penetration of these devices. The development of
new software solutions that model the uncertainty associated
with the output variability of distributed generation will be
required through close work and partnerships with the utility
industry, vendors, R&D organizations, and government.
With a high penetration of DERs, the traditional EMS
applications at control centers will require adequate
observability/visibility for generation resources normally
not directly presented in today's operation model or behind
the equivalent load zones. Under the interoperability requirement, EMSs shall be able to monitor/control DERs in the
same fashion that traditional generators are monitored today,
i.e., through/from a DER aggregator/facilities or hierarchically via interaction with distribution management systems
(DMSs) and DER management systems (DERMSs). EMS
july/august 2019

applications may also need to include suitable distribution
system models to account for DER effects, a task that could
require extensive computational resources and SCADA
infrastructure enhancement. DMSs and DERMSs will address
operation and dispatch control issues at the DER point of
interconnection and provide reliable, operational data support to BPSs' EMSs. DMSs will not need to model and monitor DER facilities and also assess distribution load models
near the DERs to ensure adequate local power flow and voltage profiles.
Accurate monitoring of the fast system dynamics introduced by renewables and DERs is vital for the safe, secure, and
reliable operation of modern and future T&D grids. Deploying GPS-based synchrophasor technology enables improved
visibility because it records voltage and current at high rates of
30-120 times/s (much faster than existing SCADA systems)
and can very accurately compute and time-synchronize
parameters, such as phase angle and frequency, across the
grid as well as power quality parameters. Tools that use synchronized measurements have been implemented globally to
improve the reliability, performance, and security of power
systems. In addition to wide-area monitoring, protection,
and control, their use is expanding to distribution system
applications including state estimation with DERs, intentional islanding, and emergency response during natural
disasters. Achieving cost-effective DER visibility and control will depend upon the use of public Internet or existing
utility communications systems, which pose regulatory and
security challenges.
Monitoring and controlling smart inverters via DMSs,
DERMSs, and/or EMSs will help mitigate impacts on the grid
and enhance DER hosting capacity (HC) of distribution systems and allow electric utilities and end users to take advantage of DER benefits. DER HC is expected to become an
important constraint for distribution systems around the world
in the next decade, as shown in Figures 4 and 5. In this regard,
utilizing smart inverter functions defined by IEEE 1547-2018,
such as volt-var control (VVC) and volt-watt control (VWC),
are expected to play a vital role in helping utilities manage
DER proliferation. Smart inverter control and implementing
VVC and VWC can help enhance HC for a variety of security-related criteria, including thermal and voltage constraints.
Additional criteria must be considered when evaluating HC,
such as protection, power quality, and reliability.
As monitoring and controlling power delivery systems
becomes more pervasive, the volume of data to be collected, processed, and analyzed will grow significantly.
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IEEE Power & Energy Magazine - July/August 2019

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