EE 394J10 Distributed Technologies
Grid-Microgrids
Interconnection
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© Alexis Kwasinski, 2012
Motivation
• Reasons for connecting a microgrid to a main grid:
• Availability: Highly available power grids may act as an additional
source for micro-grids.
• Operations/stability:
•Direct connection of ac microgrids to a large power grid
facilitates stable operation but only if the power grid acts as a
“stiff” source to the microgrid.
• When using renewable energy sources, a grid connection may
allow reducing the need for energy storage in the microgrid.
• If not all loads in a microgrid are critical, a grid connection may
allow to reduce the investment in local generation.
• Economics:
• Microgrids are typically planned with extra capacity with respect
to the local load. This extra power capacity can be injected back
into the grid in order to obtain some economic benefit.
• Grid interconnection allows to reduce fuel operational costs by
using the grid at night when electricity costs are low.
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Definitions
• Point of common coupling (PCC): it is the point in the electric circuit
where a microgrid is connected to a main grid.
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© Alexis Kwasinski, 2012
Standards
• There are several standards specifying various aspects grid
interconnection of a local power generation source. Arguably the most
important one is IEEE 1547.
• IEEE 1547 has several parts:
• Main body
• IEEE Standard 1547.1 “IEEE Standard Conformance Test Procedures for Equipment
Interconnecting Distributed Resources with Electric Power Systems.”
• EEE Standard 1547.2 “IEEE Application Guide for IEEE Std 1547™, IEEE Standard for
Interconnecting Distributed Resources with Electric Power Systems.”
• IEEE Standard 1547.3 “IEEE Guide for Monitoring, Information Exchange, and Control of
Distributed Resources Interconnected with Electric Power Systems.”
• IEEE Standard 1547.4 “IEEE Guide for Design, Operation, and Integration of Distributed
Resource Island Systems with Electric Power Systems.”
• IEEE Standard 1547.5 has not been issued, yet. Its intended scope is to address issues
when interconnecting electric power sources of more than 10 MVA to the power grid.
• IEEE Standard 1547.6 “IEEE Recommended Practice for Interconnecting Distributed
Resources with Electric Power Systems Distribution Secondary Networks.”
• IEEE Standard 1547.8 has not been issued, yet. Its intended scope is to provide
supplemental support for implementation methods for expanded use of the previous
standards, for example when addressing issues with high penetration of residential PV
systems.
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© Alexis Kwasinski, 2012
Standards
• Main provisions from IEEE 1547:
• The micro-grid must “not actively regulate the voltage at the PCC.”
• The grounding approach chosen for the local area power and energy system (LAPES) must
not create overvoltages that exceed the ratings of the equipment connected to the main grid or
must not affect ground fault protection coordination in the main grid.
• The distributed resources in the LAPES must be able to parallel with the main grid “without
causing voltage fluctuations at the PCC greater than ±5% of the prevailing voltage level of the
Area electric power system (EPS) at the PCC” and flicker must be within acceptable ranges.
• The LAPES must not energized the main grid when the main grid is not energized.
• Each distributed resource (DR) “unit of 250 kVA or more or DR aggregate of 250 kVA or more
at a single PCC shall have provisions for monitoring its connection status, real power output,
reactive power output, and voltage at the point of DR connection.”
• A visible-break isolation device must be located between the main grid and a DR unit only
when required by the main grid provider practices.
• The interconnection system must meet applicable surge and EMI standards.
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© Alexis Kwasinski, 2012
Standards
• Main provisions from IEEE 1547:
• When a fault occurs in the main grid circuit to which a LAPES is connected, then the microgrid local power generation units must stop to power this circuit before reclosure from the main
grid happens.
• The interconnection system must be able to measure relevant indicated voltages and
frequencies at the PCC or the point of connection of DR and disconnect within a given allowed
time all local power generating units in the micro-grid when these measured voltages or
frequencies fall within a range specified in a table in this standard. For example, when
voltages fall below 50 % of the base voltage, the LAPES must disconnect its DR within 0.16
seconds (one 60 Hz cycle). The time extends to 2 seconds for voltages between 50 and 88 %
of the base voltage. Disconnection must occur within 1 second if measured voltages are
between 110 and 120 % of the base voltage and within 0.16 seconds if the voltage exceeds
120 % of the base voltage. For frequency measurements, any DR of 30 kW or less must
disconnect 0.16 seconds if the measured frequency is above 60.5 Hz or below 59.3 Hz. The
same disconnect time applies for DR of more than 30 kW when the frequency exceeds 60.5
Hz, but for the lower range at these power levels disconnect within 0.16 seconds must occur if
the frequency falls below 57 Hz, whereas disconnection is adjustable between 0.16 and 300
Hz if the frequency falls between 59.8 and 57 Hz.
• Reconnection of a LAPES to a main grid may occur at least 5 minutes after voltages and
frequency fall within indicated required ranges.
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© Alexis Kwasinski, 2012
Standards
• Main provisions from IEEE 1547:
• Reconnection of a LAPES to a main grid may occur at least 5 minutes after voltages and
frequency fall within indicated required ranges.
• A microgrid must “not inject dc current greater than 0.5% of the full rated output current” at
the PCC.
• Harmonic current injection by the LAPES into the main grid measured at the PCC must not
exceed certain levels both in total and for given harmonic order ranges. The total demand
distortion must not be more than 5 % of the local main grid “maximum load current integrated
demand (15 or 30 minutes) without the DR unit, or the DR unit rated current capacity,”
whatever is greater. Base of this same base current, harmonic content for harmonics with an
odd order below 11 must not exceed 4 %. If the odd harmonic order is between 11 and 17 the
limit is 2 %, whereas this limit falls to 1.5 % for odd harmonics with an order between 17 and
23 and 0.6 % for odd harmonics with an order between 23 and 35. For odd harmonics with an
order above 35, the harmonic content with respect to the indicated current must not exceed
0.3 %. For even harmonics their content limits are a quarter of those indicated for the odd
harmonic orders.
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© Alexis Kwasinski, 2012
Standards
• Other important provisions from IEEE 1547.6 about network
protections (NP) on the grid’s side:
• The presence of DR should not:
- “cause any NP to exceed its fault-interrupting capability.”
- “cause any NP to operate more frequently than prior to DR operation.”
- “prevent or delay the NP from opening for faults on the network feeders.”
- “delay or prevent NP closure.”
- “require the NP settings to be adjusted except by consent of the area EPS
operator.”
- “cause an islanding condition within part of a grid network.”
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© Alexis Kwasinski, 2012
Interconnection methods and technologies
• Interconnection methods:
• Directly through switchgear
• Power electronic interfaces
• Static switches
• Directly through circuit breakers:
• Relatively simple and inexpensive
• Slow (3 to 6 cycles to achieve a complete disconnection).
• Since electrical characteristics on both sides of the circuit breakers
must be the same, then, electrical characteristics on the micro-grid
side are dependent on the grid characteristics. For example, use of
a circuit breaker implicitly limits the micro-grid to have, at least
partially, an ac power distribution system in order to match the grid’s
electrical characteristics.
• Power flow through the PCC cannot be controlled
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© Alexis Kwasinski, 2012
Interconnection methods and technologies
• Directly through circuit breakers:
• Example of one of such systems:
• Use of static switches:
• Usually based on SCRs in antiparallel configuration to allow
bidirectional power flow
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© Alexis Kwasinski, 2012
Interconnection methods and technologies
• Use of static switches:
• They are costlier and more complex than using circuit breakers.
• Usually, conventional circuit breakers are still used to provide a
way to achieve full galvanic isolation. A Bypass switch is also added
for maintenance reasons.
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© Alexis Kwasinski, 2012
Interconnection methods and technologies
• Use of static switches:
• They allow for many open/close operations
• They act much faster than conventional circuit breakers (in the
order of half a cycle to a cycle). Sometimes IGBTs are used instead
of SCR because IGBTs tend to be faster than SCRs and their
current is inherently limited.
• Still power flow cannot be controlled.
• There are some conduction losses in the devices.
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© Alexis Kwasinski, 2012
Interconnection methods and technologies
• Power electronic interfaces:
• It is the costlier option but it is also the most flexible one.
• Allow for power distribution architecture characteristics on both
sides of the PCC to be completely different.
• Both real and reactive power flow can be controlled.
• Reaction times to connection or disconnection commands are
similar to those provided by static switches, although in the case of a
power electronic circuit, it response also depends on its dynamic
performance, given by its controller, topology, and internal energy
storage components characteristics.
• Still, in many cases, a circuit breaker will still be required at the
grid-side terminal of the power electronic interface with a LAPES in
order to provide a way to physically disconnect the micro-grid from
the grid.
• Also, similarly to static switches, the presence of a power electronic
circuit will lead to some power losses not found in the approach
using mechanical interfaces.
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© Alexis Kwasinski, 2012
Grid-connected inverter control
• Consider the following configuration in which it is assumed that we can
control both real and reactive power can be controlled at the inverter
(this is not always the case).
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Grid-connected inverter control
• With a small voltage drop in the grid impedance (so the voltage at the
PCC, va is fixed and cannot be regulated by the inverter:
VGVINV  RINV cos   X INV sin    VG2  RINV
PINV 
QINV 
RINV 2  X INV 2
VGVINV  X INV cos   RINV sin    VG2  X INV
RINV 2  X INV 2
• The inverter impedance depends on the inverter output filter
parameters and the inverter controller.
• In most typical applications, for low frequencies the inverter impedance
is mostly resistive. Hence,
VGVINV sin 
V V cos   V 2 
PINV , R 
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G
INV
G
QINV , R  
RINV
© Alexis Kwasinski, 2012
RINV
Grid-connected inverter control
• If the inverter is controlled as in most PV grid-tied inverters so their
power factor is close to 1, then
QINV , R  0    0
Hence,
PINV , R 
VG VINV  VG 
RINV
• If due to the output filter or the controller parameters the inverter
presents an inductive equivalent series impedance, then
PINV , X 
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VGVINV sin 
X INV
QINV , X 
VGVINV cos   VG2 
© Alexis Kwasinski, 2012
X INV
Grid-connected inverter control
• Condition for unity power factor
QINV , X  0  VINV cos   VG
• Consider the following triangle based on the above condition:
VINV
Vx

VG
Then
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VINV
 VG2
VX
sin  

VINV
VINV
and
PINV , X 
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2
VG VINV
 VG2
X INV
© Alexis Kwasinski, 2012
Islanding
• In IEEE Standard 1547.4 an intentional island is said to be the result
of “intentional events for which the time and duration of the planned
island are agreed upon by all parties involved.”
• There are several reasons why intentional island operation of a microgrid may occur, but a common one is a preemptive disconnection from
the grid in anticipation of a power outage on the main grid side caused
by an event that can be anticipated, such as an incoming hurricane or
storm, or wildfires. The advantage of this intentional islanding operation
instead of waiting for the outage in the main grid to occur in order to
switch the LAPES to operate in islanding mode is that an intentional
islanding allows for a controlled transition that prevents potential failures
or quality issues in the micro-grid.
• Two phases can be distinguished in islanded operation:
• transition from grid connected to island operation
• operation isolated from the grid.
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© Alexis Kwasinski, 2012
Islanding
• During the transition into island operation it is important that:
• voltage disturbances are quickly dampened and that protection
schemes both inside the LAPES and in the grid are not affected.
• When the transition is completed it is important that
• the micro-grid has sufficient local power generation and energy
storage in order to ensure that loads are powered with the agreed
quality level. For example, in ac micro-grids it is important that
distributed resources are able to provide real and reactive power to
the specified load range. This is particularly important in order to
avoid loss of stability if there are large motors in the LAPES that
require significant amounts of reactive power during startup
• Also for ac micro-grids, their control systems must be able to
regulate both voltage and frequency within acceptable ranges. In dc
micro-grids, neither frequency regulation nor reactive power
generation are issues to consider.
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© Alexis Kwasinski, 2012
Islanding
• Eventually, it can be anticipated that the micro-grid would be
connected to the main grid again. Grid connection of dc micro-grids or
ac micro-grids with a power electronics interface with the main grid
tends to be simpler than the case of ac micro-grids connected to the
main grid through circuit breakers, contactors, or static switches
because in the dc micro-grid and the ac micro-grid with a power
electronics interface cases reconnection control resides only in this
power electronic interface. That is, the controller in this power electronic
interface would controlled in order to realize on its grid side some
voltage waveform so its amplitude, frequency and phase angle are
within specified limits to allow reconnection.
• In the other ac micro-grid cases—those directly connected to the main
grid though mechanical switchgear or static switches—reconnection is
more complicated because there is no possibility of directly controlling
the voltage waveforms at the PCC. In this case, ensuring that the
voltage, frequency and phase angle are within acceptable limits depend
on how the LAPES distributed resources are controlled.
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© Alexis Kwasinski, 2012
Islanding
•According to IEEE Standard 1547.4 these approaches can be
distinguished in this case of ac micro-grids in order to achieve a
successful reconnection:
• Active synchronization: In this approach, the LAPES controller matches the voltage
signal on the PCC micro-grid side to those of the PCC on the grid side immediately
before closing the islanding devices, such as a circuit breaker. Implementation of this
approach requires measuring these three voltage signal parameters—amplitude,
frequency and phase angle—on both sides of the PCC. A communications channel in
order to exchange information between the micro-grid and the main grid is also
necessary. This need for sensing and communications may lead to a higher failure rate
as the sensing and communications subsystems may become a single point of failure.
• Passive synchronization: In this approach a device is used to monitor the voltage at
both sides of the PCC and allows the LAPES to connect to the main grid only when the
voltage signal on the LAPES side is within some given required range of the main grid
analogous voltage parameters. Like the active synchronization approach, passive
synchronization requires sensing and communications, leading to the same potential
reliability concerns. In addition, this method may be slower than active synchronization.
• Open transition: This approach is more basic than the other two, because the method
involves connecting both ends of the PCC after interrupting disconnecting the LAPES
load. Once the micro-grid is connected to the grid then this load is brought back online.
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© Alexis Kwasinski, 2012
Islanding
• According to IEEE Standard 1547.4, un-intentional islanding
operations are “inadvertent events that are typically initiated by loss of
area EPS or equipment failure, and the DR island system may be
automatically sectionalized from the area EPS by protective equipment.”
• Once the island has been established, the same considerations that were
considered for the intentional island condition applies to the un-intentional island.
• Contrary to the case of intentional islanding, during an un-intentional island it is
not possible to prepare the LAPES for such transition, such as verifying that there is
sufficient local generation to sustain a stable operation powering all loads. Hence,
in case it is expected that local generation capacity may be insufficient to sustain
the load during un-intentional islands, black start functions or standby generators
with transfer switches have to be allocated within the LAPES.
• Once the issue in the main grid that led to loss of service to the micro-grid feeder
is solved, it may be of interest to reconnect soon the main grid to the micro-grid.
However, such connection cannot occur until the voltage and frequency of the grid
are stable and within acceptable ranges. In order to ensure meeting such
requirement, a delay of up to five minutes may be provided between the time power
is restored at the PCC from the main grid and the time reconnection to the LAPES
is established.
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