POWER May 2014 - 53

RENEWABLES
ash, which can result in slagging on water wall
surfaces. Biomass ash with a high potassium
or sodium content can significantly foul heat
transfer tubes in the upper furnace region.
Due to biomass having a lower energy
density than most coals, introducing significant
amounts of biomass fuel into a furnace
can result in increased flue gas velocity and,
potentially, more tube erosion in the closespaced
primary superheater and economizer
tube bundles. Excess tube corrosion can occur
with high-chlorine biomass fuels, especially
those with a dry-basis chlorine content
of 0.18% or greater.
Ash-Handling Equipment. Dry ash-handling
systems can benefit from the relatively
low ash content of biomass. However, biomass
ash that contains high levels of calcium
and magnesium can encourage cementation
in wet ash systems.
Another potential problem concerns power
plants that sell their fly ash for concrete
use. Currently, the ASTM C618-12a standard
for fly ash used in concrete does not allow the
introduction of biomass ash to the mix. In addition,
the chemical requirements of ASTM
C618-12a may not allow biomass ash to be
classified as Class N, C, or F fly ash.
In one biomass cofiring study at large coal
power plant, it was quickly discovered that if
the utility must pay to have its ash landfilled,
as opposed to selling nearly all of its ash, the
differential cost to the plant was a loss of
more than $5 million per year.
Emissions Controls. At biomass cofiring
levels of 10% or less by heat input,
most electrostatic precipitators (ESPs) can
successfully collect biomass ash. However,
some biomass produces ash that has either a
very high or very low resistivity, thus making
it difficult to collect.
This is often the case in studies at power
plants designed for high-sulfur coals, and significant
levels of biomass cofiring may require
either ESP upgrades or chemical injection.
Furthermore, unless the furnace combustion
and milling systems are well tuned for both
the coal and biomass, boiler fly ash unburned
carbon can greatly increase. This is a problem
for two reasons. First, high levels of unburned
carbon can change the ash resistivity and increase
ash re-entrainment after being collected
in the ESP. Second, biomass ash with high
amounts of unburned carbon can accumulate
in hoppers or in fabric filter baghouses, leading
to sometimes destructive fires.
Although biomass combustion often reemissions,
selective catalytic
duces NOX
reduction (SCR) catalysts can be very sensitive
to heavy metals and alkaline earth elements
contained in biomass. If the biomass
in question includes a significant amount of
post-industrial waste, it can sometimes conMay
2014 | POWER
tain arsenic, lead, cadmium, potassium, and
other items harmful to catalyst life. Where
high levels of ammonia slip are encountered
with either an SCR or a selective noncatalytic
reduction system, biomass ash can agglomerate
and form tenacious deposits on air heaters
downstream (Figure 6).
Flue gas desulfurization scrubbers are not
normally sensitive to biomass ash, unless the
ash contains excessive amounts of chlorine.
Some herbaceous biomass ash can contain
more than 0.5% chlorine, whereas many
scrubbers have a fuel-based chlorine limit of
less than 0.2%.
Greenhouse Gas Emissions. Biomass
fuel is rarely 100% carbon neutral, and calculating
the life-cycle GHG emissions from
biomass cofiring or conversion can be quite
difficult, especially when one considers all of
the possible feedstocks.
The planting and growing cycle, fertilizer
use, harvesting, transportation, milling and
processing, and transportation to the power
plant all contain numerous assumptions that
will differ from study to study. A review of
12 studies published in the past three years
regarding the net change in GHG emissions
at cofiring facilities found that the carbon
neutrality of biomass fuels ranged from 40%
to 96.5%. Clearly, a life-cycle assessment is
required for any proposed biomass cofiring
or conversion scheme.
Engineered Biomass Fuels
Most biomass fuels suffer from three fuel
properties that limit their use at existing coalfired
power plants: low energy density, high
moisture content, and poor grindability. All
of these limitations can be addressed via the
use of engineered biomass fuels. Engineered
biomass fuels can be created by many different
processes-including torrefaction, steam
exploding, and processing with waste heat-
but the net results are very similar.
Typically, a large amount of moisture is
driven off the fuel, significantly increasing
the heating value, while the chemical structure
of the fuel itself is altered such that the
biomass becomes more friable and easy to
grind in a coal mill. Some processes even
promise sulfur, chlorine, and heavy metal removal
as part of the upgrading.
The primary drawbacks to engineered
biomass fuels are their price and availability.
Availability is a function of the market being
in its infancy, and price is a result of both
handling the fuel twice and the energy and
materials used in the upgrade process. Unfortunately,
in most cases, engineered biomass
products cannot compete with coal without
some special legal, environmental, or political
incentive at work.
EPRI's O'Connor is bullish on upgraded
www.powermag.com
biomass. " Torrefied, steam-exploded, and
other upgraded biomass products can usually
be burned at existing coal-fired power
plants with relatively minor modifications.
The problem is operating cost-finding an
upgraded biomass which can meet environmental
goals economically. " But, O'Connor
cautions, " ensuring sustainable biomass is the
critical thing. A lot of the pellet production
is from waste wood or wood unsuitable for
other uses. Biomass resource planning needs
a sound strategy for sustainability to keep the
process as carbon-neutral as possible. "
Can Biomass Blossom?
Although several potential pitfalls have been
discussed in this article, few should be considered
fatal flaws in a plan for biomass cofiring
or biomass conversion. Though it is true
that cheap natural gas currently dampens the
enthusiasm for biomass, many power plants
have no suitable gas supply options. Furthermore,
many power plants located in remote
regions or on island nations operate in circumstances
where even engineered biomass
fuel is less expensive than imported fossil
fuels. Some power plants are located near
plentiful biomass sources, and others have
the ability to produce their own fuel.
So, despite the pitfalls, the net effect is that
biomass use is increasing for electrical generation,
even in the U.S. According to FERC,
219 MW of biomass capacity were added in
2013. Should a GHG emissions or carbon tax
be levied in the future, or the price of gas increase
significantly, then using biomass may
be an option a utility can't ignore. ■
-Una Nowling, PE (nowlinguc@bv.com)
is a project manager and technology
lead for fuels at Black & Veatch. She
has worked on fuels-related issues and
analyses at more than 550 different units
over 20 years, specializing in coal, natural
gas, and biofuels. She is also an adjunct
professor of mechanical engineering at
University of Missouri-Kansas City.
53
6. Air heater fouling. High levels of
ammonia slip can agglomerate biomass ash
on air heater baskets. Controlling ammonia
distribution to the furnace or selective catalytic
reduction system is critical for avoiding
this problem. Source: Black & Veatch
http://www.powermag.com
POWER May 2014

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