IEEE Power & Energy Magazine - November/December 2020 - 112

in my view

Tom Bialek

distributed generation
leveraging for grid services

IN THE PAST TWO DECADES, SIGnificant progress has been made to
deploy distributed energy resources
(DERs) in California. The Golden State
(as California is nicknamed) now has
a much more open planning process
where DERs can be utilized for grid
services. With the tools and processes
already instituted and given the quantity
and size of the aggregated deployment,
many people believe DERs should be
providing these services and enabling
utilities to defer large quantities of traditional infrastructure investment.
The reality is that this is not happening yet because leveraging DERs
for grid services is not as simple as
flipping a switch. There are many technical challenges that we as an industry
must first overcome.
During my quest for answers as to
why DERs have not yet reached their
full potential, I identified some but
not all of the technical gaps that must
be filled: device interoperability, device and system cybersecurity, unique
identifiers for DERs, communication
networks, participation decisions, the
development of DER management
systems (DERMSs), and measurement
and verification techniques. Certainly,
there are many other potential nontechnical challenges, such as developing
provider business models and restructuring legacy compensation and incentives to focus deployment on locational
grid needs.
Digital Object Identifier 10.1109/MPE.2020.3014750
Date of current version: 16 October 2020

112

ieee power & energy magazine

Grid Challenges
Associated With DERs
Interoperability Issues
San Diego Gas and Electric (SDG&E)
engineers observed device interoperability issues while attempting to utilize
photovoltaic (PV) systems with smart
inverters to provide voltage regulation
service. In our testing lab, two different
inverters of the same model and manufacturer performed differently when
tested. In another instance, different energy storage devices responded to charge
and discharge requests in very different
ways. When running predefined operating schedules, we also observed that
some devices returned to a home state
first before adjusting to the newly scheduled set points. Finally, customized interfaces are required to communicate to
each device and control it.

Cybersecurity
Based on a review of installed DER
systems in SDG&E's service territory
where I live and work, 58% of all systems utilize an inverter from only two
manufacturers. Both leverage the cloud
and a customer's Internet connection to
monitor and provide firmware updates,
and the commands within the inverter
utilize Modbus protocols. As the aggregate numbers increase, so do the
number of attack vectors. In California, there are approximately 8,000 MW
of rooftop PVs installed. Device and
system cybersecurity are critical as the
grid is operated in a high-penetration
DER environment.

Lack of a Unique Identifier
For a DER to provide a service, a request must be made that uniquely
identifies the location of the device expected to perform that service. IEEE
Standard 2030.5 for common smart inverter profile implementation provides
a structure and method for locating devices to service transformers; however,
the provisioning of this identification
method has not yet been included as
part of new system interconnections.

Legacy Inverters
Until 8 September 2017, all DER installations had a legacy inverter designed without critical communications and testing
requirements in mind and were installed
under some version of a net energy metering (NEM) tariff. In California, the
phase 2 communication requirement that
allows for manufacturer attestation, not
an end-to-end test, was in place 22 June
2020. This creates two -issues for utilizing existing DERs for grid services. First,
with a NEM tariff that compensates energy exported to the grid at the full retail
rate, there is little incentive for customers
to do anything else. Second, even if customers would, how would/could they accept a voltage regulation service request,
for example, if they do not have a tested
smart inverter?

Slow Adoption of Critical
Management Platforms
While participating in the U.S. Department of Energy's (DOE's) advanced
(continued on p. 110)
november/december 2020

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