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Convinced that reciprocating engines fired by natural gas
will play a major role in the future of distributed energy
but that key technology challenges remain to be addressed,
the United States Department of Energy has set the goal of
a more efficient and cost-effective lean-burn gas engine within
the next five to seven years. The goal for this new era is
a fuel-to-electricity conversion efficiency of at least 50%
(30% higher than what's currently available), NOx emissions
of 0.1 g/bhp/hr. (a 95% reduction, which still will need aftertreatment
to meet tough air-quality standards in such places as California's
South Coast Air Quality Management District), installed capital
costs of $400-$540/kWe and significant reduction in maintenance
costs. The program is called Advanced Reciprocating Energy
Systems (ARES) and so far has the support of the major engine
manufacturers working in concert with the national laboratories
and selected universities to expand the use of reciprocating
engines for distributed-generation (DG) applications.
According to former ARES Program Manager Joe Mavec, the project
was launched in September 2001 and will proceed over three
phases with research on advanced materials, fuel- and air-handling
systems, advanced ignition and combustion systems, catalysts,
and lubricants. Phase I is scheduled for completion during
2004-2005, while the deadline for final Phase III is 2009-2010.
Cummins Power Generation, Caterpillar Inc., and Waukesha Engine
Dresser Inc. have received Phase I grants and are "following
individual research paths," as John Hoeft, director of marketing
for Waukesha, puts it, based on each company's marketing target.
"At Waukesha we're working on the 1-megawatt-size product,"
says Hoeft, "and we're looking at a redesign of our VGF [engine],
our V16 platform to get there."
A
non-nonsense, long-established, and extensively used power-generating
technology that requires fuel, air, compression, and a combustion
source, reciprocating engines fall into two categories: spark-ignited
engines fueled by natural gas and compression-ignited engines
that run on diesel fuel. Gas engines are currently available
in two versions: rich-burn and lean-burn, the latter made
commercially viable when microprocessors made it possible
to efficiently control critical fuel flow and fuel-air gas
mixture plus ignition timing. In a lean-burn engine, excess
air is introduced into the engine with the fuel, which reduces
the temperature of the combustion process, which in turn reduces
by almost half the amount of nitrogen oxide produced compared
to rich-burn engines. And because excess oxygen is available,
combustion is more efficient, producing more power with the
same amount of fuel.
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"Distributed-power applications favor natural-gas technologies
first and foremost because they deliver low air emissions,"
says Caterpillar's Gas Product Marketing Manager Michael Devine.
"Diesel-fueled systems still dominate in standby and short-run
installations, but right now gas is better at combining availability,
price, and environmental compliance. Gas-fueled generator
sets can be on-line and producing power within three to six
months of when they're ordered at a cost that varies from
about $350 to $600 per kilowatt."
Devine says Caterpillar has already hit the market with ARES-style
improvements. "The G3500C engine program and its advanced
gas-engine control module is an offshoot of ARES. The new
control system solves some of the challenges that have typically
affected the efficiency of lean-burn engines, including maintaining
air-fuel ratio and constant emissions control."
Technological
advances aside, choosing a natural-gas learn-burn generator
set from what's now available requires a thorough assessment
of the amount and duration of power to be generated, which
must in turn be balanced against installed cost, engine efficiency,
and emissions control. While large-scale DG applications have
sometimes favored 24/7 cogeneration systems, Devine reports
that smaller industrial users and some utilities are opting
for selective usage, sometimes running as few as 500 hr./yr.
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But Stan Price, project manager for Northern Power Systems
Inc. in San Francisco, CA, wonders about such short-hour applications.
"We try to select equipment so that it runs at least 4,000
to 4,500 hours a year as close to its full rating as possible.
If the capacity factor is below 60%, I begin to wonder whether
the economics are going to make sense for the customer. What's
got to drive the decision to put in a genset for, say, 1,200
hours a year is the fact that loss of power during an interruptible
period is very expensive in terms of lost product. The company
is not just saving money on electricity, they're saving on
product costs."
At Waukesha, Hoeft thinks the choice
of an engine begins with emissions requirements. "Once you
look at kilowatt size, you make your decisions based on the
product mix and meeting the emissions requirements, then on
how much efficiency you want. It's a tradeoff between emissions
and efficiency and first [installation] costs."
Chach
Curtis, vice president of onsite
generation for Waitsfield, VT-based Northern Power Systems,
notes that while lean-burn engines have become the
industry standard - particularly in Europe because they are
typically anywhere from 3 to as much as 10% more efficient
in converting fuel to electricity - there also is a market for
rich-burn engines. "In states like California and New Jersey
and New York and now Massachusetts, both systems are going
to need some kind of aftertreatment. For the rich-burn engines,
it's a cheaper, simpler process. So, in these states, you
have to look at the higher cost of aftertreatment to meet
emissions standards on a lean-burn engine versus how much
additional savings you're going to generate from the higher
electrical efficiency a lean-burn system is going to give
you. Then you have to determine if that's going to pay for
itself in a reasonable timeframe. If not, the customer might
be better off with a rich-burn engine and saving some money
up-front on the emissions equipment.
"A
year ago you could install a lean-burn engine in Massachusetts
without the tougher area-based SCR
[selective catalytic reduction]. And, in California, although
they've extended the incentive program to the end of 2007,
they've lowered the emission requirements in order to qualify."
As
Curtis points out, the only aftertreatment technology currently
on the market to bring lean-burn engines into compliance where
NOx standards are tight is SCR, which some end users are uncomfortable
about utilizing for cost and safety reasons. But because the
major manufacturers are solidly behind lean-burn technology,
they are quick to play down states where higher emission standards
can make compliance costly, and the industry itself is looking
for new aftertreatment technologies to come on-line that will
eliminate the perceived risk of storing and using the ammonia
that's added to a lean-burn engine exhaust stream. "Within
the next two or three years, you're going to see exhaust gas-circulation
technologies emerging for lean-burn [engines] that will bring
them down into compliance," says John Kelly, director of distributed
energy for the Gas Technology Institute
(GTI) in Chicago, IL. But
Ritchie Priddy of Attainment Technologies LLC in New Iberia,
LA, says that time is already here
(see sidebar).
At Caterpillar, Devine agrees that meeting local emissions
standards is one of the factors that needs to be considered
in what he calls "the economic equation" to determine whether
generating your own electricity is competitive against purchasing
power from a utility. "When a user is trying to determine
the cost of operation for a gas engine, they usually think
of the installed first cost of the system, the fuel and maintenance
costs, but they also need to figure the cost of meeting the
local emissions regulations, which can be met either inside
the engine or outside the engine. With rich-burn engines,
there is just enough air to mix with the right amount of required
fuel to make the power required. Given that nitrous oxide
is created in the exhaust stream in the presence of heat,
the higher the temperature and the longer the exposure to
that heat, the more NOx will be created. To minimize exhaust
emissions, a three-way catalyst is then used to convert the
exhaust gas into essentially water and nitrogen. This type
of system is similar to automotive systems used today - you
end up with very high exhaust-gas temperatures, and because
of the way this type of engine consumes fuel, your efficiency
is typically in the 33% to 35% range. A lean-burn engine deals
with most emissions in the engine. You still have the same
amount of fuel introduced into the cylinder to make the required
power, but you're putting excess air into the cylinder with
the fuel. You're distributing the same amount of heat over
a larger volume, so your exhaust-gas temperatures are lower,
greatly reducing the formation of NOx. In areas where very
low exhaust emissions are required, a simple oxidation catalyst
or SCR may be used to meet the local standards. An added benefit
of lean-burn engines is that the lower exhaust-gas temperatures
translate into higher power density, longer maintenance intervals,
and lower owning and operating costs."
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| After installation, a 1.75-MW
cogeneration system at the Chicago Museum of Science and
Industry will provide up to 80% of the museum's heat,
hot water, and electricity. |
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| The Cummins lean-burn generator
set produces up to 1.75 MW/hr. of electricity and 4,000
lb./hr. of steam. |
Herman Van Niekerk, vice president of engineering at Cummins,
agrees that a fundamental difference between rich-burn and
lean-burn engines is that the lean-burn is more fuel-efficient,
but he adds a qualifier. "As the engine gets bigger, the gap
in performance and efficiency gets wider. The newer lean-burns
are 39% efficient or better, while the rich-burns are about
32%. With that sort of efficiency gap, you can afford to do
all sorts of aftertreatments to meet emissions requirements.
But if you get down to 300 kilowatts or less, then the advantage
of having lean-burn over rich-burn is not that great. You
may [gain] two percentage points of efficiency with lean-burn,
but you have the cost of the aftertreatment. I've done several
feasibility studies on lean-burn projects in which a small
unit just doesn't cut it.
"Otherwise it's a purely economical situation.
We run a feasibility study with the data we get from the utility
company - every 15 minutes of use - and from the customer about
his site, including his thermal load profile and if it's a
cogeneration project. Then we'll model an engine on the resulting
load curve and simulate real-life conditions for an entire
year so we will know exactly what will happen if we try to
generate power on the customer's site. This makes it easy
for us to then compare rich-burn and lean-burn engines of
different sizes and from different manufacturers.
"This
process also gives me a financial model, which allows me to
give the customer a full financial-impact study on what it
will take to do the job. Some customers want a simple payback
in two to three years. Others want to borrow the money. Our
program will take the cash flow from construction to ten years
and calculate the return on investment. Customers must be
clear on these questions before any of the modeling work can
be done."
A
case in point is a large automobile manufacturer headquartered
in Torrance, CA, that elected a simple payback, Van Neikerk
says. The company installed a combined heat and power system
that uses a Cummins 1.2-MW natural gas-fired generator with
a 250-ton Trane absorption chiller. Modeling convinced decision-makers
that a CHP unit was environmentally and economically responsible,
says Garth Sellers, manager of national facilities services.
"We knew that we wanted to generate power, especially with
the cost of energy in California. We also knew we wanted to
use the byproduct of heat. Eventually we determined that we
could use the heat in an absorption chiller to produce air
conditioning, which we needed. We generate enough electricity
to fully supply our central plant in Torrance during the summer
months. During the winter months and in the evenings and on
weekends, we supply several other buildings on campus. Our
goal is to run the generator at 100% load, 98% of the time."
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At Northern Power, Pace points out that there are advantages
to cogeneration besides what's obvious. "Being an official
cogenerator based on the Public Utility Code [means] that
you can apply for incentives, and most utilities have a special
gas tariff rate for cogeneration, which in some cases is significantly
less than the tariff for normal boiler heating gas. But one
thing you have to be careful of is the quality of waste heat
you need. Some processes use 150 psi of steam, and recip engines
are not good matches for waste heat at 150-pound steam because
they don't have the required amount of waste heat at a high
enough temperature. Some manufacturers are more restrictive
than others as to how hot they allow certain waste heat streams
to be. Some will limit water-jacket heat to 185¡, others will
let it go up to 210¡, and some [will let it go] as high as
240¡. So understanding the basic energy balance of the engine
and the quality of the heat is important in understanding
how you match that specific engine to the process."
"From our perspective at GTI," says Kelly, "although heat
recovery helps, the really big impact on decision-making is
the electricity cost in the region. That's the number-one
driver. With utilities having peak and off-peak rates, if
you manage the situation correctly, you can be very economical.
At GTI, for example, we run 9 a.m. to 6 p.m. every day, and
the payback on our system is maybe four and a half years.
We believe this is the optimum solution because it also takes
care of the electrical utility. When we're not running at
night, they get to sell their base, but we're shaving their
peak."
"Whether
you're only going to run at peak periods depends on what your
nighttime rates are and what your fuel costs are," says Van
Niekerk. "If you can generate cheaper than what you would
otherwise pay for electricity - if you compare both thermal
and electric - you always run the genset 24/7, and it pays every
time. Because even if you only save a penny per kilowatt-hour,
on a megawatt unit, that's almost $100,000 a year. Because
deciding when to run or not is a really tight calculation,
at Cummins we also provide a real-time monitoring and analysis
system that will actually look at fuel costs and at electrical
rates and then advise the customer during off periods to stop
the generator until fuel prices come down."
Except
for waste heat, all of these factors were figured into decision-making
when the research and development operation of a major global
manufacturing company based outside of Chicago decided on
self-generation. According to its facilities manager, the
company was experiencing major problems with quality and reliability
in the power it received from its local utility. During summer
hot spells, the load could be down by as much as 15%. The
company already had installed its own internal distribution
network for power it bought off the grid and its own double-redundant
diesel-powered system for backup at its corporate data center.
Once the decision was made to generate power on-site, the
company brought in Nicor Solutions, which helped develop the
onsite power plant, eventually built the facility, and then
leased it to the client, who runs it on a typical peak-shaving
profile, 9 a.m. to 6 p.m. The company chose two Waukesha VHP
5904-LTD 1- to 25-kW gensets but left enough room in the building
that houses them to add a third unit. "We chose Waukesha,"
says the facilities manager, "primarily because of their availability
in the market, because of their operating history, and [because
of] the fact that they're a relatively simple and straightforward
engine. In my mind, other new technology being offered hadn't
been proven. We also liked the fact that the company is relatively
close in case anything happens." Keeping track of fuel costs
is critical to efficient operation. "I'm always looking two
years ahead, and when I see that the price of gas in 2006
is reasonable, I buy a contract and lock in the price. A lot
of people do this, but they don't constantly monitor the market.
We have settled into a procedure, which takes me a minute
each morning to look at where our electricity prices are and
then at what our natural-gas prices are, and then we make
a determination: Does it make sense for me to buy energy,
leave my plant idle, and sell my natural gas, or does it make
sense to generate electricity on-site?"
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Devine agrees that equipment and operating costs have to
be balanced against what he calls "power reliability and power
quality," and any bottom-line economic assessment must consider
added costs, such as standby charges, exit fees, and additional
incremental costs, for interconnection. He points to industrial
operations, such as Kuntz Electroplating Inc. in Kitchener,
ON, where seconds-long interruptions in utility-supplied power
stopped production for as long as an hour. The company also
was experiencing voltage disruptions during periods when high-demand
equipment came on-line, and the resulting damage in solid
state processing control could cause repairs that could shut
down production lines for as long as 45 minutes. To solve
these problems, Kuntz installed five Cat G3516 generator sets
for a 4.075-MW capacity. When the system is operating at the
rated load, it carries roughly 65% of the plant's total electrical
load; control switchgear sheds noncritical loads in case of
utility power interruptions. The company also recovers heat
from engine exhaust and jacket water/oil cooler circuits to
help satisfy a process heat load of 18 million Btu /hr. for
parts cleaning and electroplating tanks.
Caterpillar
also is working with utilities, such as Herber Light and Power
(HL&P), a municipal electric utility in Herber City, UT,
to install its own DG systems rather than rely on customers
to pick up peak-time power demands. Devine explains, "When
power shortages hit California in the summer of 2000, HL&P
was prepared. By increasing run time on its distributed-generation
resources, which consisted of natural-gas- and diesel-engine-driven
generator sets, HL&P avoided purchasing wholesale power
at prices that rose from the typical $20 per megawatt-hour
to as high as $200 per megawatt-hour at peak-demand hours.
After the crisis passed, HL&P took further steps to protect
reliability and stabilize prices, investing in three new advanced
gas-fueled generator sets rated at a combined 5.52 megawatts.
With those new units on-line as of July 2002, the distributed-generation
facility has nine gas and two diesel units delivering 11.97
megawatts of capacity. It provides economical load following
year-round and shields HL&P customers against future swings
in wholesale power prices. In case of a major wholesale supply
interruption, the facility could carry a substantial share
of HL&P's load, keeping the majority of its customers
in service."
Houston,
TX-based Atmos Power Systems (APS) designs and installs plants
for peak shaving, shoulder, and interruptible load applications.
"Historically," says APS Vice President Larry Moore, "utility-provided
power during peak- and shoulder-load operations has always
been the most expensive due to demand charges. APS builds
the power-generating facility and offers its customers long-term
leases that allow them to build an equity position in the
generation plant during the term of the contract." One of
APS's clients is a food-processing operation in the Southeast
where a large portion of the facility's electricity portfolio
was on an interruptible basis, which meant that the utility
had the right, given notice, to reduce power demand by a certain
amount. In the face of increasing demands on the utility that
supplied its power, the company wanted to firm up its power
delivery and reduce high demand charges.
"The decision we
had to make," says the company's energy manager, "was [this]:
Do we continue to take interruptible power, or do we take
the interruptible part of our portfolio and make it firm?
But under most utilities, the real benefit of interruptible
power versus firm power is that you don't pay the high demand
charges. So in effect the demand portion is much cheaper.
So we weighed the increased cost of firming up our interruptible
service against the cost of turning those generators. In effect
we were firming up our power because we had generation on-site."
APS
installed a 20-MW plant using 12 Cummins QSV lean-burn generator
sets, which environmentally were permitted to operate 1,200
hr./yr., and then leased the plant to the customer. Power
is generated at 13,800 V and is connected directly to the
customer's substation. The company's energy manager acknowledges
that leasing the facility rather than bearing the capital
cost of building the plant was attractive but that the company
hasn't completely ruled out buying the lease.
With
these kinds of numbers, Moore says APS is enthusiastic about
the DG market, which he also predicts will include a combination
of utilities and end users. "Utilities benefit from DG power
plants installed in areas of system weakness," says Moore,
"by being able to defer capital budget items to upgrade their
transmission infrastructure."
Besides
emissions, Moore thinks that noise management and equipment
maintenance are two factors that have to be considered from
the get-go. "In these kinds of lightly loaded applications,
the life expectancy of a system like we put in with the 12
Cummins gensets is 40 years, after which the engines will
be overhauled and allowed to operate for another 40 years.
The key is proper maintenance, which Cummins supplies. The
only thing we require of our customers is that someone walk
through and do a periodic check once a day to make sure everything
is running smoothly, that there's no oil on the floor, no
antifreeze. This has the added benefit that, if five years
down the road the customer decides they want to purchase the
power plant, they have people who are qualified and know how
it works and are familiar with its operating history."
GTI
recommends that anyone considering distributed energy develop
maintenance specifications and put them out to bid at the
same time they bid the project. Van Niekerk describes Cummins's
"bumper-to-bumper" guarantee as "a fixed feed per kilowatt-hour.
The customer knows exactly what it's costing him to generate
electricity. For a penny or a quarter of whatever that number
is per kilowatt-hour, we provide full warranted maintenance
and a monitoring system, which automatically calls out so
everybody knows what's going on and if there are any problems."
Journalist PENELOPE GRENOBLE
O'MALLEY is a frequent contributor to environmental
publications.
DE - March/April 2004
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