IEEE Power & Energy Magazine - November/December 2020 - 110

in my view (continued from p. 112)
distr ibution management system
(ADMS) Voices of Experience effort,
DOE researchers found that a surprisingly low number-only a handful-of
utilities in the United States either had or
were considering deploying an ADMS.
An ADMS provides a critical view of the
system and manages conventional utility
resources, such as capacitors, regulators,
transformers, switches, and so on, which
is key to advancing a more resilient and
reliable energy future. All resources need
to be managed concurrently to operate
the grid both safely and reliably.
Without an ADMS to provide visibility into grid conditions, how do you
leverage DERs? To forecast and determine a service need and effectuate that
request to either the distribution system
or wholesale market, a DERMS is a
necessary software and control tool to
integrate into distribution operations.
ADMS deployment not only comes
before the DERMS, but its functionality (power flow model, volt/var management, and so on) must be vetted
prior to DERMS implementation. The
DERMS must be integrated into the
ADMS, allowing a single unified view
of the distribution system; the DERMS
guides the dispatch of all resources,
subject to the total grid operating state
based on grid constraints, switch state,
load, and DER capabilities.
Based on two rounds of requests
for proposals at SDG&E several years
apart, I learned that the distributed,
federated, hierarchical control structure necessary to control large, scalable
quantities of DERs-tens of thousands
to millions-is not currently available
commercially. Only pilot projects or
customized, one-off software solutions
are being used to control small quantities of DERs. The DOE is funding
DERMS R&D through its Grid Modernization Lab Consortium as well as
its Office of Electricity.

Lack of Measurement and
Verification Techniques
Finally, certain measurement and verification techniques must be in place
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to provide compensation for grid services. At the wholesale market level,
the requirements are clear, but DER
aggregators believe that they are too
burdensome, and there are distribution system operating constraints that
impact the aggregation availability. At
the distribution level, without a generator output meter, it is unclear what
the actual response to a request for
service would be. (In 1999, California
investor-owned utilities asked policy
makers to require a generator output
meter, but the request was rejected due
to concerns that the additional requirement would drive up the cost of solar
installations.) While it is possible to
estimate a PV system's power output
based on solar irradiance data and the
panel orientation, in California, solar
panels are oriented in all directions,
including north, based on facility/
property siting constraints.

A Little Bit of History
In the late 1990s, DERs, or distributed
generation (DG) as it was known at
the time, was deployed by larger entities with a significant heat load in
combined heat and power applications.
However, during that time period, PV
systems and microturbines developed
with an inverter (dc-to-ac converter) interface to the grid were also beginning
to be deployed. At the end of 2000,
SDG&E had 32 PV installations totaling 105 kW.
In 1999, the California Public Utilities Commission (CPUC) opened a
rulemaking on DG interconnection
with the goal of reducing barriers, lowering costs, and accelerating adoption.
This inclusive stakeholder effort, codified under Rule 21, resulted in standard
requirements for inverters. Utilities
were required to evaluate DG as an
alternative to traditional "wires" solutions, with vendors offering to supply,
rent, or lease a generator to the utility.
This Rule 21 revision led the parties
involved and a broader group of stakeholders to develop IEEE 1547 and update UL 1741. A key tenet of the stan-

dards was that the DG unit do no harm
under normal operating conditions and
disconnect as quickly as possible under
abnormal conditions. Given the cost of
a PV system at the time, the growth of
installations was expected to be small
for the foreseeable future.
Just a decade later, at the end of
2010, SDG&E had 11,644 PV installations totaling 84,765 kW. We were
beginning to get a good sense of how
DERs impact the grid when there is
widespread deployment.
In 2011, on a rural circuit in San
Diego County, an excellent example
of the impact of DERs on the grid was
discovered. Power quality meters had
been set on the secondary of a primary
metering station at the end of a long circuit, which utilized a small copper conductor for the last line segment. At the
end of the circuit, a 1-MW PV system
was connected. The primary circuit
voltage was observed to fluctuate wildly due to intermittent power production
from this PV system with a legacy inverter as the morning fog burned off.
SDG&E had identified the factors that
determined the impact of a PV system
on the grid and recognized, given the
German experience (which California
was emulating), that it was necessary
to update the Rule 21 interconnection
requirements to incorporate smart inverter functionality to avoid the German 50.2-Hz retrofit experience.
After a 2013 CPUC-sponsored workshop, an effort to update Rule 21 was authorized, and the Smart Inverter Working Group began work on the technical
requirements. This effort resulted in requirements and timelines for implementation and the development of the UL
1741-SA standard to allow for testing to
the new California Rule 21. An update to
IEEE 1547 was initiated and approved,
leveraging the California work. IEEE
1547.1, the test standard for smart inverters, has also been approved and will be
published soon. I expect this to set off
another round of work to harmonize all
of the standards. The key point of the
1547 standard was that the DER unit
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