IEEE Electrification Magazine - March 2020 - 25

The choice of DER
transformer
configuration is
arguably one of the
more commonly
overlooked microgrid
considerations
for three-phase,
four-wire systems.

electric utility systems effectively
control field devices, such as capacitors and voltage regulators, which
have delays associated with their
operation. However, due to the traditional centralized architecture of
electric power systems in general,
effective real-time control of renewables is challenging due to the time it
takes for changed field conditions to
be identified within the centralized
control system. In such cases, by the
time the centralized system is ready
to issue the operating command, the
field operating conditions have
changed. The issued operating command does not optimize the performance of the subject DER, which has led to work on
localized control systems and operations. To provide
localized control, secure local data access, interoperability,
and distributed intelligence are key enabling factors for
faster adoption of DERs and optimized control.
One of the biggest challenges with microgrid operation and control is the design of a reliable and secure
protection scheme that operates in both grid-connected
and islanding modes. Due to the low fault currents,
which are limited to 1.2-1.5 per unit (p.u.), bidirectional power flows and dynamic changes within the
microgrid, implementing a traditional overcurrent feeder protection scheme can result in a less secure and
reliable solution. Implementing an IEC 61850 standardbased protection scheme based on the sample values
and GOOSE messaging using merging units can also
offer some advantages. Changing load conditions, DER
availability, and varying power flow direction constantly
affect the available fault current levels and further
increase the complexity of implementing secure and
reliable protection and a control scheme.
Since 2015, Duke Energy has designed, built, commissioned, and been operating the Mount Holly Microgrid in
North Carolina. This microgrid has an ac-coupled battery
energy storage system (BESS), photovoltaic (PV) farm, dccoupled BESS, natural gas generator, and microturbines.
The microgrid transitions between grid connected-mode
and island-mode operation using seamless transition
algorithms that Duke Energy developed and is also
capable of operating from a black start. This article summarizes some of the lessons learned from field implementation of the Mount Holly microgrid, including the
design and configuration of a grounding transformer,
transformer inrush current mitigation, islanding-detection techniques, seamless islanding, grid resynchronization, black-start versus seamless-transition design,
microgrid protection and control schemes, and uninterruptable power supply (UPS) challenges. Mount Holly is
designed to comply with IEEE Standard 1547.

Lesson 1: DER Transformer
Configuration

The choice of DER transformer configuration is arguably one of the more
commonly overlooked microgrid
considerations for three-phase, fourwire systems. Size, harmonics, and
shielding are all critical design factors for a microgrid transformer.
Reviewing numerous papers that
show the proposed microgrid oneline diagrams indicates many DER
transformer configurations within
the microgrids with a YGND-Δ transformer configuration. Even though
this topic has been covered in the
report published by the IEEE Working
Group D3 "Impact of Distributed Resources on Distribution Relay Protection," it requires further attention.
Choosing the DER's transformer configuration drives
the design of the microgrid protection and control
scheme; in brief, implementing a proper transformer
configuration is critical to operate the microgrid reliably
and securely. Although it is widely used in DERs, the
YGND-Δ transformer configuration is not the most desirable due to its negative impact on feeder protection and
control schemes, challenges with microgrid protection
and control in islanded mode, overvoltages within the
microgrid during the faults, challenges with open phase
conditions, and ferroresonance. Figure 1 shows the
Mount Holly microgrid, which has been implemented
and operational since 2015. The microgrid is located
approximately 4.5 mi from the substation and connects
to the 12.47-kV distribution feeder.
For the fault simulation, all DERs at the microgrid site
were first removed and the phase A line-to-ground (LG)
fault was placed upstream from the point of interconnection (POI) recloser and the simulation showed the fault
current to be 1.0 p.u.. Next, DERs at the microgrid site were
added to the simulation [PV rated at 100 kilovolt amperes
(kVAs) and BESS rated at 650 kVA] with DER YGND -Δ transformer configuration and the fault simulation was repeated. Results of this analysis are shown in Figure 2.
As can be seen from the graph, the value of the fault
current, as seen by the substation feeder relay, decreases as
the size of the DER increases when the DER is installed with
the YGND -Δ transformer configuration. As a cumulative
effect, the relay protection scheme is desensitized and,
depending on the size of the DER and fault location, the
substation breaker may not trip for an LG fault. The size of
the DER was increased in successive fault simulations, with
the result that a DER sized at 1.8 megavolt amperes (MVAs)
or larger causes the upstream relay at the midpoint recloser
to not detect the fault and, therefore, not trip. During an LG
fault, the YGND -Δ transformer provides the additional path
for zero-sequence fault current, so not all fault currents (IF)

IEEE Elec trific ation Magazine / MARCH 2 0 2 0

IEEE Electrification Magazine - March 2020

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