IEEE Power & Energy Magazine - May/June 2021 - 75

Local generation can also challenge the detection of
single open-phase conditions, which are commonly detected
using negative- or zero-sequence overvoltage protective
elements. These operating quantities can be reduced in
microgrids with operating local generation because of the
generators' low negative-sequence impedance.

Synchronism and Antiparalleling Protection
In microgrids, synchronism check protection is another critical
component. If two sources in the system are paralleled without synchronization, one or both, along with other equipment, can be damaged.
Based on the system topology, certain breakers or switches
are not intended to be closed if sources are energized on both
sides of an open breaker or switch. In these applications, the
microgrid protection is set to prevent closing if voltage is
present on both sides of an open breaker or switch.

Utility Protection Standard
Progression and Microgrids
Utility feeder protection standards in Ontario were designed
decades ago, predominantly for radial feeders with unidirectional power flow. The basic functions of these protection
systems remain in place today, with modifications mostly
designed to ensure that the utility distribution systems are
not adversely impacted by distributed generation.
Distributed generation projects have developed at a rapid
pace in Ontario since 2005, mainly due to regulatory policy
and economic incentives. Increasing levels of distributed
generation have required distribution utilities to adapt to and
accommodate all types of large and small generators placed
on Ontario utility systems based on the technical and economic advantages of the generators, which, in some cases,
did not align with the technical requirements of the utility.
Many Ontario utilities took the approach of allowing a
limited amount of generation to interconnect on each feeder
or station, considering the technical impacts to circuit capacity, voltage regulation, flicker, short circuit contributions, fault
detection, and isolation. From a protection perspective, there
are many concerns with integrating distributed generation,
including
1) How can it be made certain that generators will be
automatically and quickly isolated from the feeders
before the station breaker recloses?
2) Can traditional overcurrent-based feeder protection
offer acceptable sensitivity and clearing times to endof-line feeder faults, considering the generator short
circuit contributions?
3) How can power quality be assured with generators
connecting anywhere along a feeder and operating on
their own parameters?
As the owners of the distribution system, utilities have
the responsibility of maintaining the safety, reliability, and
efficiency of their assets. These responsibilities have generally led utilities to take a conservative approach to protection
may/june 2021

and control. Generators have had to meet very strict technical requirements, which, in most cases, are expensive
and time-consuming. Direct-transfer trip systems using
dedicated communication paths between the utility supply
substation and the generator are still commonly required
for most generators above 1 MW. An independent, utilitygrade protection relay for passive anti-islanding protection is
often required at the point of common coupling to the utility system, regardless of whether these protection functions
already exist within the generation systems.
In the past five years, there has been greater collaboration
between utilities and power generators with a recognition
that the traditional utility customers' needs are changing and
DERs are becoming commonplace. Projects like the North
Bay CEP microgrid are demonstrating that early and continuing collaboration between DER developers and utilities
can inspire out-of-the-box thinking and joint efforts toward
the development of microgrids and DERs.

Protection System at
the North Bay CEP Microgrid
The North Bay CEP microgrid is a 600-V system. The DERs,
loads, and utility are all interconnected through a single 600-V
switchgear assembly. In Figure 2, CB1-CB9 are all a part
of the same 600-V switchgear; because of this, much of the
microgrid protection system is contained within this switchgear. Each circuit breaker in the switchgear, whether it connects
to a DER (CB3, CB4, CB5, or CB6), a load feeder (CB7, CB8,
or CB9), or the utility (CB1 or CB2), has its own protective
relay that measures the voltage and the current. The protective
relay can also trip or close the breaker when necessary. These
microprocessor-based, multifunction protective relays come
with custom logic capability and use IEC 61850-a standard
for power system communication protocols-Generic ObjectOriented Substation Event (GOOSE) messaging to exchange
discrete signals. GOOSE messaging is defined by IEC 61850
and can be used for high-speed protection communications.
In GOOSE messaging, devices publish a message, and other
devices subscribe to that message. This publish/subscribe
method is used to transmit multiple messages from each relay
to every other microgrid relay in the system.
In addition to the protections provided in the low-voltage switchgear, each DER has its own built-in protection.
The DERs' integral protection is set up by the DER equipment supplier to protect the DER itself. When designing the
microgrid, this built-in protection was considered a backup
to the protection provided in the 600-V switchgear.
Another protective element that exists outside the lowvoltage switchgear is the anti-islanding protection required
by the local utility interconnection. North Bay Hydro Distribution Limited, like most utilities, requires that the DERs
connected to the utility must be disconnected from the utility power system as quickly as possible when a fault or outage occurs on the utility circuit. This ensures that the DERs
will cease contributing fault current so that the fault can
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IEEE Power & Energy Magazine - May/June 2021

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