www.PowerEngineeringInt.com 29 Power Engineering International June 2017
availability and effectiveness. Lastly, removal
of SO3 prior to the air pre-heater reduces
the back-end acid gas condensation
temperature. With a consistent, well-designed
DSI system in place, the air pre-heater can
return more heat to the boiler, improving heat
rate and overall effciency.
A relatively new strategy is to move the
hydrated lime injection location upstream
of the SCR. In this application, hydrated
lime allows the SCR to operate at lower
temperatures by removing the SO3 that would
otherwise react with ammonia to form ABS
inside the catalyst layers.
This allows the SCR to continue operation
during low load conditions. Plugging of
the SCR due to hydrated lime has not been
evident and catalyst deactivation has also
not been observed.
With new SO2 emission limits varying between
100 and 220 mg/Nm3 for many coal-fred
boilers in the EU, controls will be required to
reduce current SO2 emissions. Technologies
available include semi-dry and wet FGDs,
or dry sorbent injection systems. Each has
advantages and disadvantages.
DSI is an easily retroftted, low capital
cost system that is capable of relatively high
(>90 per cent) SO2 removal, especially with a
fabric flter. DSI employs SBC, trona, or hydrated
lime as sorbents of choice depending upon
local availability and removal levels required.
Operating costs of a DSI system have shown
to be comparable to other FGD systems in the
Hydrated lime is typically used for lower
SO2 removal levels (<50 per cent). However,
newer, enhanced hydrated lime products
injected prior to a fabric flter have shown the
ability to reach moderate to high levels of SO2
reduction (70–80 per cent). This performance
comes with higher injection rates compared
to the sodium-based sorbents.
In Europe, SBC is the most available sodium
sorbent for DSI. The material is delivered with
a relatively large particle size to ease the
handling and storage process. Therefore, it
must be milled prior to injection to be effective.
UCC’s patented VIPER Mill was engineered
specifcally for this application in order to
reduce particle size, maximize surface area
and promote effcient sorbent usage without
heating or damaging the product. The blow-
through design simplifes the equipment
requirement and allows one blower to convey
the material from the silo through the mill to
With SBC, temperature is very important.
Temperatures below 135°C will cause the
SBC to remain crystalline with very few pores.
Temperatures above 345°C cause the SBC
particles to soften, which reduces its porosity
and therefore reactivity.
Between those temperatures, the product
is highly porous and reactive with SO2.
Depending on boiler type, coal type and
system operation, the proper temperature for
SBC frequently is found post air pre-heater.
SBC injection with a fabric flter can achieve
greater than 90 per cent SO2 removal.
Alternatively, trona is a sodium-based,
naturally occurring mineral that can be
applied in a similar manner. Large deposits
are found in Turkey, as well as in the US.
Although slightly less pure than typical
SBC, trona does provide several benefts. First,
the product has a lower cost since it can be
mined in a ready-to-use condition. Second,
trona can be injected up to 540°C before the
product is damaged.
This allows the ability to inject further
upstream, which provides more of a reaction
time and improves the effciency of the sorbent.
When compared to SBC, trona performance is
generally lower, and more sorbent is required.
This is often offset by its lower cost.
Balance of plant effects
Effects on plant operation vary for the different
sorbents. Some coal-fred boiler owners
and operators select to use hydrated lime
if possible in order to avoid potential heavy
metal leaching from the collected fy ash
mixed with DSI by-product. The downside of
hydrated lime, however, is the inability of some
ESPs to accommodate the increase in surface
resistivity resulting from the calcium addition.
Alternatively, the use of trona or SBC
reduces the resistivity, making the by-product
and fy ash easier to collect. Most test and
long term installation sites have shown neutral
effects or even improved collection in their
existing ESPs when injecting sodium-based
DSI sorbents are not created equal when
it comes to mercury capture. High levels of
SO3 impede PAC performance, but naturally
occurring halogens in the fue gas are
necessary for oxidation and the capture of
Hydrated lime, being more selective
towards SO3 than HCl, typically improves
PAC performance. Sodium sorbents, though
more effective on a mass basis, are more
likely to impede overall mercury removal
In these instances, I would recommend
separating the DSI and ACI injection locations.
Precise arrangements should be determined
based on unit specifcs. Typically, it is better
for the DSI sorbent to be injected before PAC
on units burning high suphur coal (to remove
SO3), but after the PAC on lower sulphur units
(to avoid halogen removal).
The most effective method to determine
optimal performance and balance of plant
effects is to conduct a DSI trial on the unit in
question. A trial or demonstration test can be
designed to determine the most cost-effective
overall emissions reduction strategy.
Once determined, the system is often
operated continuously for a period of time to
gain a full understanding of the equipment
and downstream effects. These trials typically
range from one week to three months
in duration, using temporary equipment
designed for this purpose.
DSI system design
DSI is a very effective and fexible technology
and, when designed properly, system plugging
should not occur. Poorly designed systems will
have distribution and plugging issues, which
will adversely affect performance and the
ability to beneft from all the advantages the
DSI’s fexibility in application will allow most
coal-fred boilers in operation to achieve
compliance with new air emission limits in a
cost-effective manner. It can be applied as an
independent SOx removal device, or it can be
applied to aid under-performing FGDs.
Instead of upgrading the equipment
for the new regulations, DSI can reduce the
inlet sulphur to the FGD, allowing the existing
equipment to reach the regulatory limits.
DSI should be considered for all future SOx
mitigation requirements as a low-capital cost,
high effciency system.
Connor Cox is Project Manager
at United Conveyor Corporation.
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