Connecting generators to the grid is technically involved
and expensive, so much so that the price tag and impact assessment
can be deal-killers. Resulting interconnection charges, notes
Robert Lasseter, professor emeritus of electrical engineering
at the University of Wisconsin, "can sometimes run as
much as the distributed generation [DG]" itself, and
this is obviously prohibitive. To be allowed a connection,
a generator must also comply with the Institute of Electrical
and Electronics Engineers' (IEEE) standard P1547, which
requires automatic and rapid disconnection in the event of
the grid experiencing a fault. Naturally, this is a great
inconvenience to the DG owner.
Lasseter is part of a major initiative that's now working
hard to solve and perhaps forever alter—dramatically—the
connective relationship between DG and utilities. Throughout
2004 his Wisconsin laboratory was the site for proving the
needed breakthrough technology. Lasseter is participating
in a group called the Consortium for Electric Reliability
Technology Solutions (CERTS), a major R&D initiative formed
six years ago to find ways to improve the nation's electric
power systems. CERTS members include Lawrence Berkeley National
Laboratory, Oak Ridge National Laboratory, Pacific Northwest
National Laboratory, the National Science Foundation's
Power Systems Engineering Research Center, and Sandia National
Laboratories. Their work is currently being funded by grants
from the US Department of Energy (DOE) and the California
Energy Commission's (CEC) Public Interest Energy Research
One primary focus—potentially the most revolutionary
for DG—is the group's emerging technology and design
concept for electrical microgrids. First, by way of definition,
a microgrid consists of two or more DG resources on a feeder
connectable to a main grid; this allows it to run either in
parallel or independently of the grid. Similar configurations
in various flavors have existed on campuses and military bases,
etc., for some time, of course, but CERTS's innovation
promises to extend microgrid versatility dramatically. CERTS
has published several white papers about its model, from which
some of the following report is adapted.
Enjoying Common Connections
Lassiter summarizes the CERTS concept. Instead of having multiple,
separate DG-to-grid connections, each governed by IEEE P1547,
all DG resources are tied together on their own new feeder,
which is then linked to the grid at a single point of common
coupling (PCC). The main grid is no longer directly exposed
to the individual DG voltages and outputs; instead, the feeder,
with its "microscources" of DG power—now comprising
the microgrid—presents itself to the main grid "as
a single, very well-behaved dispatchable load," says
Lasseter. A microgrid might thus incorporate several or even
dozens of DG resources and many loads—and yet, he reiterates,
"instead of each having to be independently grid-connected,
they are all part of the microgrid, which has a single connection."
Moreover, he adds, at this PCC, newly emerging automatic
switching technology will mean, "We have the ability
to intentionally island [disconnect] and reconnect."
Here, the chief advantage for DG is a kind of permissible
circumvention of IEEE P1547 and its automatic shutdown requirement.
Instead of forcing DG to cease making power whenever the grid's
voltage begins wavering, all the microgridded DG can keep
running, because they're on their own detachable feeder.
That feeder or microgrid islands at the PCC, thereby protecting
the main grid from any errant voltage coming from the DG.
The latter may continue running without interruption—obviously,
a great convenience for the owner. After the grid problems
ease, the microgrid can then seamlessly reconnect.
Benefits of CERTS's innovative approach actually accrue
to both the main grid operator and the microgrid community
(see Benefits for Power Customers on page 24).
Given the numerous operational advantages of CERTS microgrids,
the IEEE is also now writing a new standard—dubbed P1547.4
and expected to be issued sometime in 2005— which will
propagate appropriately updated rules on how microgrids and
other resources may island.
Surmounting Several Challenges
How exactly will DGs on a microgrid be strung together? In
order to answer this, it's first useful to be aware of
three technical challenges posed and how the CERTS design
How to Disconnect and Reconnect Seamlessly
Disconnection isn't a new problem for DG, of course,
but because a faultless and smooth transition is so critical
to the microgrid concept, certain switch-system modifications
were deemed necessary. The Wisconsin lab developed a proprietary
static switch device employing "back-to-back SCRs [silicon-controlled
rectifiers or thyristers] with local logic to re-synch them,"
Lassiter notes. The results meet EPRI quality power standards.
How to Compensate for the Big Power Loss During Islanding
When the microgrid islands, power from the main grid quickly
detaches; this means DG must rev up and counteract that lost
power. But DG isn't typically capable of doing this quickly
enough. The solution? Stored DC power and even stored AC power.
Each energy resource on the microgrid, whether AC- or DC-powered,
outputs to a DC bus before being inverted (to 60 Hz grid-quality
AC, at each voltage source) for energizing the microgrid.
This power inversion rectifies the output and makes the diverse
sources compatible. Positioned along the DC buses, assorted
innovative storage devices can be applied, such as lead-acid
batteries (now with greatly increased storage density and
extended lifetimes); supercapacitors with very high discharge
rates able to handle quick load shifts; and superconducting
magnetic energy storage, which pass current along without
losses and store energy within a superconducting electromagnetic
coil. Advances in all of these methods enable quick energy
bursts from storage. On the AC side, similar quickly dischargeable
storage has been developed, primarily with extremely high-rpm
flywheels. In any event, these technologies enable the microgrid
to compensate with bursts of power as needed, within a few
cycles, until the DG prime movers can power up fully—in
about ten or twenty seconds. Meanwhile, rapid load-shifting
is also likely to take place, again automatically.
How to Stabilize Voltage of Many Generators on One Feeder
Solving this turned out to be the most difficult part, Lasseter
recalls. Voltages tend to sag variably, due to distances between
machines and fluctuating currents, loads, and impedances.
DGs then begin to "feed off against each other,"
he says, and try to compensate—causing instability.
To solve this problem, automatic voltage and power wattage
regulators were added, enabling machines to adjust to shifting
loads and keep the voltage steady. CERTS researchers had to
build "droop" into the voltage controls, he recalls,
"So they won't fight with each other or couple to
Already built into a number of DG products are advanced power
electronics. These include the inverters just mentioned, automated
controls for load-following and power flow, and differential
current circuit breakers. Some or all of these elements are
incorporated, for instance, into Capstone microturbines and,
reportedly, in the Honeywell 75-kW Parallon, as well as in
generator products from Bowman and Turbec. Controls respond
to local frequency and voltage readings, adjusting appropriately
to maintain balance while load-following. Such a generator,
explains Lasseter, "automatically ‘rethinks'
itself without requiring communication" from a dispatcher.
Capstones, in particular, use automated controls to operate
in sync when they're arrayed with each other in series
(i.e., forming a kind of "proto"-microgrid). Advanced
electronics also support many photovoltaic (PV) products and
To enable these built-in electronics to do higher-level interactive
functions on a future microgrid, the onboard controllers will
need to be somewhat beefed up and modified. But the essentials
are already in place for maintaining flow on the feeder, regulating
voltage at each source, and even power compensating during
islanding. Controls will also need to operate in two new distinct
modes, grid-connected and islanded. Assorted control software
and PLC modifications are already reportedly being prepared
by one or two manufacturers. In any case, increasingly automated
DG capable of self-adjusting in harmony with local resources
and signals, will be critical to DG's microgridded future
During trial runs of a basic working simulation at the Wisconsin
lab, smart PLCs and automatic onboard controls "proved
out the system behavior" as Lassiter hoped. "That
it's truly ‘plug and play' doesn't have
to be tested," he reports: "It's working."
Real-World Demo Coming Soon
Quite soon it will all be working in an actual application.
Groundbreaking for the first prototype microgrid, largely
inspired by CERTS concepts, occurred in Waitsfield, VT, in
late 2004. Completion is expected sometime in mid 2005, reports
Jonathan Lynch, chief technology officer of the firm that
is building it, Northern Power Co., also of Waitsfield. Northern
Power, a subsidiary of Distributed Energy Systems Corp., has
extensive experience in DG, having installed more than 800
power systems for industry and governments worldwide.
Northern Power has designed this first-of-its-kind microgrid
to serve itself and its nearby corporate neighborhood, called
Mad River Park, a light commercial and industrial center in
a semi-rural setting. Electric power service is currently
provided by the Washington Electric Cooperative (WEC) of East
Montpelier. WEC is a collaborative partner with Northern and
stands to benefit from the grid's mix of additional clean,
renewable, and low-emissions generation. Northern Power also
does R&D on renewable energy and hydrogen technology,
and some of the activities on the new microgrid will be quasi-experimental;
it's being supported by a DOE assisting grant of $600,000.
Northern's initial array of resources will consist of
propane-fueled reciprocating engines, microturbines, a photovoltaic
array, and a small wind turbine. Integrated with these are
storage devices. The fuel-burning generators will cogenerate
usable heat and power for maximal efficiency. And later on,
Lynch notes, other important cutting-edge technologies will
be tested, such as multi-fueled Stirling engines, fuel cells,
and advanced storage batteries.
Cumulative power output will reach around 350 kilowatts initially—enough
to support loads from five Mad River commercial and industrial
facilities and 12 nearby homes currently served by WEC.
As for design specifics, says Lynch, the power sources will
be separated on a single feeder at distances of at least 100
yards. Automated electronic controls on the inverters will
do the "heavy lifting" of voltage and power balancing.
The systems are pre-programmed with algorithms developed and
tested at the Wisconsin lab. Because Mad Rivers' microgrid
system is a prototype, it will apply additional voltage regulators
for protection. Also, once it's operational, its fluctuations
will be closely watched as loads and outputs are varied under
real load conditions, and experimentally, to see what happens.
Power coming from the local WEC substation will also be monitored
(automatically); a protective relay at the PCC will detect
undesirable events. If grid conditions warrant, a fast disconnection
switch will open. The microgrid will island and continue operating
on its own, so that microgrid clients will enjoy uninterrupted
power. Actually, notes Lynch, several modes of operation are
possible with the sophisticated switch, including full islanding
to insulate the neighborhood from voltage sags or spikes on
the main grid, as well as variable kinds of parallel connection.
Future Commercial Applications
Northern Power hasn't announced formal marketing plans
yet, but potential opportunities for these ultra-functional,
highly beneficial microgrids are obvious. Lynch envisions
them serving, for example, as attractive alternatives for
new commercial/industrial parks where utility-line extension
is often costly. Microgrids might also power remote villages
in the developing world, "or in any other area where
you don't have a strong utility, or you can't rely
on it, or it doesn't exist," he says. Bypassing
the need for a centralized, multi-megawatt generator, communities
that are favorably sited in sunny, windy areas could easily
tap these networks to create all or nearly all renewables-based
Moreover, new kinds of business relationships can readily
be foreseen. For example, a commercial power system operator
might buy and run a microgrid-based DG network, but not necessarily
be an end user itself. Rather, it would act as a "mini-utility"
for a special niche. Another obvious scenario would be that
of utilities adopting microgrid technology themselves, perhaps
then partnering with cogen owners collaboratively.
Other intriguing but as-yet unanswered questions arise: How,
for example, would peak-shaving economics be affected if the
DG resources are microgridded and running all the time rather
than optimized? And how might a cogeneration site share its
power with its microgrid neighbors? Lynch points out that
these and other technical, regulatory, and commercial issues
remain virgin territory for markets and adopters to explore.
From a researcher's standpoint, Lasseter sums up by
noting that more demonstration sites would be nice to have,
especially in collaboration with utilities. As of late 2004,
CERTS was already evaluating proposals from three such prospects,
and has intentions of selecting and implementing one sometime
in 2005. The CEC, he notes, will provide a generous grant
of about $3 million to build a full-scale microgrid at an
unnamed California site. Other potential partners for CERTS'
energy solution might include business and industrial parks,
campuses, military bases and office buildings-specifically,
says Lasseter, those with loads up to half a megawatt at 480
volts (i.e., for testing a 500-kva transformer) and which
are able to use waste heat. A prospective microgrid could
likely integrate an existing energy management system, too,
Finally, part of the rollout process that's now under
way involves demonstrating or at least probing the potential
commercial value. CERTS, Lasseter says, "is talking with
potential partners to take it to the next level."
La Mesa, CA–based writer DAVID ENGLE specializes in
DE - March/April 2005