Utilizing microturbines to produce heat and energy from wastewater treatment plant sludge
Wastewater treatment plants are
looking for ways to utilize the biogas they produce to generate their own power
and heat while reducing their methane emissions. Possibly creating a closed
loop, where both the offsite electricity and methane emissions become
obsolete.
Methane is generated in the
anaerobic digester, a solids management system that reduces both the volume and
toxicity of sludge. Sludge originates in the plant’s primary and secondary
clarifiers, where microorganisms consume bacteria under aerobic conditions and
then settle out, respectively. Waste-activated sludge from the secondary
clarifier is a slurry, at 2–4% solids, and requires additional treatment or
disposal.
According to a November 2008 study
by BCC Research, the North American and international market for sludge
treatment is growing. One method of treating waste-activated sludge is anaerobic
digestion, where sludge is processed into methane, carbon dioxide
(CO2), and nutrient-laden solids that can be suitable as soil
amendments.
The process is this: Anaerobic
digester vessels are airtight and maintained at a biologically comfortable
90+˚F. Initially, organics in the sludge are converted to volatile fatty acids.
Next, methane-producing bacteria use the volatile solids as substrate to produce
biogas, a composite of gases that largely include methane and CO2. To
a lesser extent, biogas includes nitrogen, oxygen, hydrogen, hydrogen sulfide,
and siloxanes.
For better or worse, biogas is
comprised of 50% methane. The EPA estimates that in 2006, wastewater treatment
plants produced 4% of the anthropogenic, human-made, methane emissions,
generating the equivalent of 23.9 teragrams of carbon dioxide (Tg CO2
Eq) or, in terms of emissions, 23.9 million metric tons of CO2. This
level has remained relatively constant since 1990. With respect to methane
produced as part of managing waste in the US, wastewater treatment plants fall
between landfills that create 125.7 Tg CO2 Eq, and composting that
generates 1.6 Tg CO2 Eq annually.
With a heating value of 1,000 Btu
per cubic foot (Btu/cf) alone, or approximately 600 Btu/cf when mixed with the
other components of biogas, biogas can easily be flared to destroy the methane.
But flaring doesn’t utilize the potential energy. By employing technologies such
as microturbines, plants can harness the energy of biogas while reducing carbon
emissions.
How They Do It
Microturbines convert methane to
useful heat and electricity using turbo charger technology, akin to that of a
jet engine. The expansion of high-pressure gas is used to turn a generator and
produce electricity. In the case of Capstone microturbines, the compressed gas
is comprised of anaerobic digester gas mixed with air, which is expanded and
combusted using a single shaft, rotating on air bearings. The single shaft
design requires no lubricating oil or coolant.
The stack emission from the
microturbine has an exhaust temperature of approximately 530˚F, making it more
than suitable for utilizing combined heat and power (CHP). The stack emissions
are run through a heat exchanger to produce hot water. Hot water, in turn, is
used to maintain the warm temperature needed in the digester. Excess hot water
can also be used to heat onsite buildings. By providing its own heat, and
possibly heat needed elsewhere onsite, the plant’s overall draw on the grid and
dependency for offsite fuel is reduced. Another advantage of microturbines is
that they can provide operational power during brownouts or more extended power
outages.
Microturbines join a cast of other
technologies that make use of the thermal and energy benefits of methane,
including boilers, reciprocating engines, and fuel cells, with fuel cells and
microturbines being the most avant-garde.
There are benefits to using
microturbines over other types of technology, namely emissions and flexibility.
“They are the cleanest combustion technology,” says Jim Crouse, executive vice
president of sales and marketing for Capstone Turbine Corp. “Any wastewater
treatment that’s digesting sludge is a potential candidate. They should have
enough gas to run a 30-kilowatt
turbine. But, would it make sense economically?
“The nice thing about
microturbines is that they are scalable,” he goes on to say. “They come in
30-kilowatt, 65-kilowatt, and 200-kilowatt sizes, and can be used as an array.
Looking at fuel cells, the smallest is about 200 kilowatts.”
Crouse also mentions that, while
combustion engines come in smaller sizes, there are emission issues that could
make them more costly.
Capstone has named its
microturbines, using the prefix CR for Capstone Renewable. They are designed to
operate specifically on digester or landfill gas and require no emission
management systems. The units are relatively small—the size of a
refrigerator—and are comparatively quiet, at 65 dBA (decibels weighted for the
human ear), less noise than a diesel truck.
Upstream of the
Microturbine
The key to microturbine operation
is upstream gas conditioning. The better the conditioning, the less likely it is
that a microturbine will have operational problems. According to Capstone,
microturbines may easily handle hydrogen sulfide (H2S) concentrations
of close to 70,000 ppm by volume; however, other equipment in the treatment
train can’t. Anaerobic digester gas must be treated, or conditioned, before
entering the microturbine, not just because of the H2S, but other
components and conditions as well.
In a nutshell, digester gas is
saturated with moisture and contains H2S and organic silicon
compounds called siloxanes that wreak havoc on equipment. Some parameters must
be addressed, less they damage the microturbine; other parameters because they
impact the gas conditioning system. Following is a rundown of anaerobic digester
gas parameters that have to be accounted for before the gas goes to the
microturbine.
Moisture. Moisture is removed from
the gas stream to prevent failure of siloxane removal systems, and to prevent
condensate from forming downstream and reducing the energy content of the gas.
Typically, moisture is removed using a knockout drum, suction scrubber,
de-mister, ambient air cooler, or chiller.
 |
Photo: Capstone
Capstone microturbines operate on digester or landfill gas, requiring no emission or management systems. |
Pressure. The pressure of gas
exiting the anaerobic digester is typically low—approximately 10 inches of
water. A compressor is needed to ramp up the pressure to between 55 psi and 80
psi that is required by the microturbine. It’s common to combine the compressor
with a chiller to remove moisture and increase pressure in one unit operation.
The inlet pressure required by the microturbine is inversely related to the heat
value of the digester gas. The lower the heat value, the higher the pressure
needed. The 55 and 80 psi needed relate to heat value of 350 Btu/cf and 850
Btu/cf, respectively.
Hydrogen Sulfide. In addition to
being a potential odor or health and safety issue, H2S can impact the
media used to remove siloxanes. Various removal methods are used and include
either media, chemical, or biological treatment. Treatment using media, such as
an iron sponge, is typical when conditioning anaerobic digester gas.
Siloxanes. Siloxanes are an
expensive component to remove, but even more expensive not to. Siloxanes are
used in deodorants, cosmetics, and lubricants that find their way to the waste
stream and subsequent biogas. When combusted, siloxane forms silica dust,
clogging, coating, and pitting of the microturbine. The most common method of
removing siloxanes is to run digester gas through a fixed-bed media made of iron
or carbon.
Gas conditioning equipment comes
on its own skid with individual components selected based on site-specific
conditions. The importance of gas conditioning is appreciated more now than
years ago.
Jan Scott and Dave Broihahn are
owners of Unison Solutions, in Dubuque, IA. The pair has years of experience in
distributed energy, but now specialize in gas conditioning for different
microturbine applications. “There’s never been a gas stream we couldn’t clean,”
says Broihahn. When it comes to what types of gases prove to be more
challenging, he says, “gas from a landfill or a wastewater treatment
plant—either one could be worse; it’s site specific.”
Proper gas conditioning can make
the difference as to whether a system operates or not, and it doesn’t come
cheap. In a report prepared by Resource Dynamics Corporation for the Department
of Energy, typical costs for a gas conditioning system designed to remove
siloxanes ranged between $150,000 and $300,000, for microturbine systems ranging
in size from less than 60 kW to greater than 300 kW, respectively. For smaller
systems, siloxane treatment can be cost prohibitive. For a system under 60 kW,
the estimated price for siloxane treatment ranges between $3,000 and $5,000 per
kilowatt. For a system larger than 300 kW, the same removal treatment costs
approximately $1,000 per kilowatt. It’s estimated that up to half of the cost of
a gas conditioning system is for siloxane removal alone.
Heat + Electricity =
Money
Like other CHP units, the output
of a microturbine is heat and electricity, but the efficiency for both isn’t the
same. Its efficiency is often compared to that of fuel cells—another no-emission
form of CHP.
According to Capstone, fuel cell
technologies can produce electricity at 40% to 45% efficiency. High-stack
temperatures in fuel cell stacks allow heat to be recovered at approximately 80%
efficiency. Microturbines can achieve 80% efficiency for heat recovery, but when
it comes to producing electricity, the efficiency drops closer to 26%.
“If you are not using all the
thermal energy, then fuel cells are more electrically efficient,” says Crouse.
He says in most applications, when both heat and electrical power are generated,
the overall efficiency is the same.
The combined efficiency was
determined for the Village of Essex Junction, VT. Two 30-kW microturbines were
installed at the 3.3-million gallon per day (mgd) treatment plant. In 2003, the
total system efficiency, including heat and power, was over 80%. Translated, the
system saved 412,000 kWh—equivalent to 36% of the plant’s annual power demand,
or $37,000.
Savings were seen in Wisconsin as
well. The 18.4-mgd-sized Sheboygan wastewater treatment plant installed 10 30-kW
microturbines in 2003. “In 2007, the microturbines provided 1.7 megawatts of
electrical energy that was used onsite,” explains Dale Doerr, wastewater
superintendent for the City of Sheboygan. The savings valued out to
$114,000.
Originally, the anaerobic digester
gas at the Sheboygan plant was used as boiler fuel that provided heat to the
digester. Digester gas also fueled an engine that drove a 500-horsepower
influent pump. At the time, only 25% of the digester gas was flared. Doerr was
on the lookout for ways to reduce the plant’s environmental impact and outside
power demand.
Since installation of the
microturbines, piping has been revised at the plant. Heat is used to maintain
the temperature of the digester along with onsite buildings; both are benefits
during cold Wisconsin winters.
When considering different CHP
options, Doerr wasn’t tempted to incorporate fuel cells into the plant’s system.
“At the time, fuel cells were not economically feasible,” he says. “They cost
50% to 100% more, so we ruled them out. Since then, we haven’t really delved
into it.” (It’s important to note that the microturbines were part of a
larger-scale opportunity offered by Alliant Energy, the area’s utility provider.
)
“We had three boilers here that
were nearly 30 years old,” continues Doerr. “One failed, and we were going to
replace all three, but then we came into the microturbine project that would
allow us to produce heat and electricity.”
As a result, only two new boilers
were installed at the plant, and under a separate project, the 10 30-kW
microturbines were added. Alliant Energy paid for the microturbines up front, a
cost of $1 million to install. Alliant also pays the plant for the biogas it
produces. In return, the plant purchases electricity from the utility. In 2013,
the plant will have the opportunity to buy the microturbines from Alliant for
$100,000.
There are other financial benefits
the plant has seen. “We retain all of the renewable energy credits, and that
earned us $6,000 in 2007,” says Doerr. “We also saved $57,000 in natural gas,
and Alliant paid $27,000 for the biogas. That’s a total of $90,000 in 2007.”
“The city initially invested
$200,000, and we recovered that in about two years,” he adds. Doerr believes
that because Alliant paid for the microturbines, their return on investment will
be longer, possibly six years.
Side-by-Side Comparison
An Oregon wastewater treatment
plant benefited from a project to compare the installation and performance of a
fuel cell and microturbines running on anaerobic digester gas. Gary Odt is
senior engineer at the City of Portland, Columbia Wastewater Treatment Plant. At
100 mgd, it’s the largest treatment plant in the state.
Through a joint project of the
National Association of State Energy Officials and the City of Portland, and
support from the US Department of Energy, Odt monitored and evaluated the
installation and performance of one 220-kW fuel cell and four 30-kW Capstone
microturbines.
The purchase price for the four
microturbines was approximately $300,000. Add to that an installation cost of
$46,000. An Oregon Business Energy Tax Credit brought the final price down to
$309,000 or $2,575 per kilowatt. With all four microturbines operating enough
electricity, they can be generated to supply power to 60 to 75 single-family
homes. When completely utilized, the digester gas avoided purchasing $187 per
day of electricity.
The microturbine and fuel cell
were installed in 2003, but the fuel cell was decommissioned after five years.
“The fuel cell was extremely high maintenance,” says Odt. “It failed and would
have been extremely expensive to replace. We weren’t generating that much
electricity, so we couldn’t justify replacing it.”
When evaluating the efficiency of
the microturbine, the plant reported that it had an electrical efficiency of
27%, and a combined heat and power efficiency of 80%. The plant also uses two
internal combustion engines and boilers that can run on digester gas or natural
gas. During the warmer summer months, the needed heat for the digester is
provided solely by the digester gas. But during the winter months, natural gas
can be brought in if needed. Influent to the plant comes from combined sewers,
cold runoff combines with residential wastewater. The influent temperature is a
far cry from the 98˚F the digester needs.
Sailing’s Not Always
Smooth
Even with the successes plants
have had using microturbines, implementing CHP at wastewater treatment plants
isn’t always easy. Scott and Broihahn understand the frustrations some operators
have experienced.
“With the early microturbine
installations, there were a lot of failures,” says Broihahn. “The process of
cleaning the gas was not sufficient because of gas conditioning problems. Or
sometimes it was just the microturbines. Now there are over 4,000 microturbines
installed. The early generation had bugs, but the fourth generation is
technically improved.”
“The turbine products and the air
systems are much better,” adds Scott.
The Sheboygan plant experienced
some problems, but Doerr is an advocate of the microturbine systems. “Three of
the turbines have had continual problems, but the rest have been OK,” he says.
“Some of the units are early-made models; they have different types of engines.”
He believes it is the older engines that are having the problems.
One lesson learned at the facility
included how the location of the equipment could be affected by ammonia gas. A
chiller unit is used to cool the gas and remove the moisture. “It was in a
balcony-type location,” says Doerr. “The vapors have ammonia that ate away at
the tubing, and we had to replace the chiller system.”
Even at the Columbia plant, the
microturbines weren’t without complications. After coming online in April 2003,
they were shut down in August of the same year and didn’t come back online until
October 2004. Problems stemmed from moisture in the gas. The majority of
problems experienced at the plant centered on gas conditioning, with siloxane
deposits and moisture leading to higher-than-expected fuel preparation and
maintenance costs.
Because of plant renovations, the
microturbines have been taken out of service at the Columbia plant. Odt believes
overall the microturbines ran well enough and, if they don’t come into play in
the plant upgrades, will likely be used at one of the city’s smaller plants.
Looking Ahead
As the country looks to become
more energy efficient, more utilities want to provide their own electricity and
are considering various options.
With 40% of the plant’s operating
costs going to power, energy savings is a big driver for Doerr. “My goal is, by
the time I retire in eight years, to be able to produce all of our energy
onsite,” he says.
To accomplish this, Doerr has two
other green energy projects underway. Solar panels are planned for the
200,000–square foot roof surfaces at the plant and a hydropower project on the
shore of Lake Michigan.
“It’s estimated that we could
produce 2.1 MW of solar power on the flat roofs,” he continues. “The sewers are
over 100 years old, and when it rains there is a lot of leakage. The flows can
go up from 11 mgd [million gallons per day], to as high as 64 mgd. With all the
pumps running, the demand is 1.1 megawatts.”
Doerr acknowledges that it
wouldn’t be likely that the 2.1 MW produced by solar power could be used at the
same time demand is highest, because of weather conditions. The benefit would
come because power added to the grid when the sun is shining could be bought
back at a lower rate when it’s raining. The solar project is planned for 2012
and 2013.
He also visited Germany in search
of hydroturbine options and found energy being garnered from elevations as low
as 25 feet. Doerr is planning to utilize the elevation difference between the
plant and Lake Michigan. “We’re 50 feet above the lake,” he says. “It could
provide 10% of our electrical energy. There is money in the budget, and we plan
to install it in 2010.”
With the microturbines in place
and solar and hydropower planned, it’s likely Doerr will meet his onsite energy
goal.