SO2 Removal from Power-Plant Stack Gases

Chemical Engineering Principle of Chemical Processes

SO2 Removal from PowerPlant Stack Gases∗

Numerous inventories of the world’s energy reserves have shown that coal is the most abundant
practical source of energy for the next several decades. Two immediate problems have become
apparent as the use of coal has increased: mining can be costly, both economically and
environmentally, and air pollutant emissions are relatively high when coal is burned.

Stack gases from coal-fired furnaces contain large quantities of soot (fine unburned carbon particles) and
ash; moreover, most coals contain significant amounts of sulfur, which when burned forms sulfur
dioxide, a hazardous pollutant. In this case study we examine a process to reduce pollutant
emissions from coal-fired power plant boiler furnaces.

Sulfur dioxide …SO2† emissions from coal-fired furnaces whose construction began after
August 17, 1971, must, by Environmental Protection Agency (EPA) regulation, contain less
than 1.2 lbm, SO2 per 106 Btu (heating value of fuel fed to the boiler). When coal containing a
relatively high quantity of sulfur is to be burned, the emissions standard may be satisfied
by removing sulfur from the coal prior to combustion or by removing SO2 from the product
gases before they are released to the atmosphere.

The technology for removing SO2 from
stack gases is currently more advanced than that for sulfur removal from coal, and a large
number of stack gas desulfurization processes are currently in various stages of commercial

Sulfur dioxide removal processes are classified as regenerative or throwaway, according to
whether the agent used to remove SO2 is reusable.1 Regenerative processes have two major steps:
the removal of SO2 from stack gases by a separating agent, and removal of SO2 from the
separating agent. An example of such a procedure is the Wellman-Lord process-absorption of SO2
by a solution of Na2SO3 to produce NaHSO3, followed by the release of SO2 by partial
vaporization of the NaHSO3 solution. In this process the Na2SO3 solution is regenerated for
reuse as the absorbent.

Na2SO3 ‡ SO2 ‡ H2O ! 2NaHSO3 …absorption†
2NaHSO3 ! Na2SO3 ‡ SO2 ‡ H2O …regeneration†

Throwaway processes utilize a separating agent to remove SO2, followed by the disposal
of both SO2 and the separating agent. Wet limestone scrubbing is one of the most advanced
throwaway processes in terms of industrial acceptance. Several versions of this process have
been developed, one of which is examined in detail in this case study. Parts of the process
have proved troublesome, particularly those involving deposition of solids on surfaces of the
process equipment.

Participants in the case study may find it interesting to learn where the
trouble spots are and to check recent technical articles on SO2 removal processes for
discussions of approaches to solving these problems. Such articles are published frequently
in Chemical Engineering Progress, Environmental Science and Technology, and other
technical journals.

∗ This case study was prepared for the first edition of the text with the assistance of Norman Kaplan of the U.S.
Environmental Protection Agency.
1 Alternatively, the processes may be classified according to whether the sulfur is recovered as a saleable product.


The plant to be described is to produce 500 MW of electrical power. The flow rates, compositions,
stream conditions, and other details to be given are representative of such installations. The key
step in removing SO2 from the stack gas is the reaction of SO2 with CaO and oxygen to produce
CaSO4, an insoluble stable compound. Four major components of the process will be traced: the
coal-limestone-stack gas streams, the scrubber water, the cooling-heating water cycle, and the
generated steam cycle.

The composition of coal can vary considerably, but that shown in Table CS 2.1 is typical of
that used in this process. During coal combustion the sulfur in the coal reacts to form SO2 and very
small amounts of SO3. Eighty-five percent of the ash in the coal leaves the boiler in the stack gas as
fly ash; nitrogen emerges as N2, and the carbon, hydrogen, and sulfur in the fuel are oxidized
completely to CO2, H2O, and SO2.

Finely ground limestone, whose composition is given in Table CS 2.2, is injected directly into
the furnace where complete calcination occurs.2
CaCO3 ! CaO ‡ CO2

The limestone feed rate to the furnace is 10% in excess of that required for complete consumption
of the generated SO2. Both limestone and coal enter the process at about 77°F. A waste stream
consisting of 15% of the limestone inerts and coal ash is removed from the furnace at 1650°F.

2 Direct injection of limestone is the method of operation in this case study, but in conventional practice the flue gas and a
limestone slurry are contacted in an external scrubber.

TABLE CS 2.2 Limestone Properties

1. Composition
Component Dry Wt%
CaCO3 91.8
Inerts 8.2
Moisture: 10 wt% water
2. Heat capacity of inerts
Cp…Btu/lbm F† ˆ 0:180 ‡ 6:00 105T…°F†
TABLE CS 2.1 Coal Properties
1. Composition (ultimate analysis)
Component Dry Wt%
Ash 7.2
Sulfur 3.5
Hydrogen 5.0
Carbon 75.2
Nitrogen 1.6
Oxygen 7.5
Moisture: 4.58 lbm/100 lbm wet coal
2. Heat capacities
Dry coal: Cp=0.25 Btu/lbmF
Ash: Cp=0.22 Btu/lbmF
3. Heating value of coal: 13,240 Btu/lbm dry coal

2 CASE STUDY 2 SO2 Removal from Power-Plant Stack Gases

Air at 110°F and 30% relative humidity is brought to 610°F in an air preheater, and the heated
air is fed to the furnace. The air feed rate is 40% in excess of that required to burn the coal
completely. Gases from the furnace containing fly ash, CaO, and CaSO4 and at 890°F are cooled in
the air preheater and then split into three trains. The gas in each train is cooled further to 177°F, and
fed to a scrubber where it is contacted with an aqueous slurry of CaO and CaSO4. Sulfur dioxide is
absorbed in the slurry and reacts with the CaO.

The gas leaving each scrubber contains 3.333% of
the SO2 and 0.3% of the fly ash emitted from the boiler furnace. The effluent gas from the scrubber,
which is at 120°F and saturated with water, is heated and mixed with the gas streams from the other
trains. The combined gas stream is sent to a blower where its pressure is increased from 13.3 psia
to 14.8 psia; it is then exhausted through a stack to the atmosphere.

The liquid feed enters the scrubber at 117°F and contains 10.00 wt% solids; it is fed at a rate
such that there are 6:12 lbm liquid per lbm inlet gas. Liquid scrubber effluent at 120°F is sent to a
holding tank where it is mixed with fresh makeup water and water recycled from a settling pond.
From the holding tank, one stream is recycled to serve as liquid feed to the scrubber and another is
pumped to the settling pond for solids removal.

Generation of steam and its utilization in the production of electricity in this plant is typical of
many power cycles. Steam is generated in the boiler and leaves the boiler and superheater tubes at
1400°F and 2700 psia. It is expanded through a turbine where its pressure and temperature are
reduced to 5 psia and 200°F. The low-pressure steam is then condensed at constant pressure and
pumped isothermally to the inlet boiler tubes.

The temperature of the water used to cool the gas entering the scrubber is 148°F. The hot
water at 425°F is then used to reheat the effluent gas stream from the scrubber. (The water thus
undergoes a closed cycle.)

The power company for which you work is contemplating adding an SO2 scrubber to one
of its generation stations and has asked you to do the preliminary process evaluation. In
solving the following problems, you may neglect the formation of SO3 in the furnace, and
assume that CaSO4 and CaO are the only calcium compounds present in the slurry used in the
scrubber (i.e., neglect the sulfite, bisulfite, and bisulfate compounds that are present to some
extent in the real process).


Problems CS 2.2 through CS 2.7 should be answered using a basis of 100 lbm/min of wet coal fed to
the boiler.
CS 2.1. Construct a flowchart of the process, labeling all process streams. Show the details of only one
train in the SO2 scrubber operation.

CS 2.2. From the data on coal composition given in Table CS 2.1, determine the molar flow rate of each
element other than ash in the dry coal.

CS 2.3. Determine the feed rate of O2 required for complete combustion.
CS 2.4. If 40% excess O2 is fed to the boiler, calculate:
(a) The air feed in
(i) lb-mole/min.
(ii) Standard cubic feet/min.
(iii) Actual cubic feet/min.
(b) The molar flow rate of water in the air stream.

CS 2.5. Determine the rate of flow of CaCO3, inerts, and H2O in the limestone feed.
CS 2.6. Estimate the rate at which each component in the gas leaves the furnace. What is the waste removal
rate from the boiler?
Problems 3

CS 2.7. At what rate must heat be removed from the furnace?
CS 2.8. Plants of the type under consideration operate at an efficiency of about 35%; that is, for each unit of
heat extracted from the combustion process, 0.35 units are converted to electrical energy. From
this efficiency and the specified power output of 500 MW, determine:

(a) Coal feed rate in lbm/h.
(b) Air feed rate in
(i) lb-mole/min.
(ii) Standard cubic feet/min.
(c) The flow rate of each component in the gas leaving the furnace.

CS 2.9. How much additional coal is consumed in the boiler because of the addition of limestone?
CS 2.10. Calculate the feed rate of liquid to each scrubber in lbm/h.

CS 2.11. Estimate the composition and flow rates of the gas and liquid streams leaving the scrubber. Are the
EPA requirements satisfied?

CS 2.12. Determine the rate at which water (fresh water and recycled water from the pond) must be mixed
with the effluent from the scrubber to reduce the solids content (ash, CaO, CaSO4) to 10 wt%.

CS 2.13. If essentially all the solids in the waste stream fed to the settling pond are precipitated, and if the
pond surface area is such that half of the water in the waste stream is evaporated, at what rate, in
gallons per minute, must fresh water be fed to the process?

CS 2.14. Determine the temperature of the gas stream as it leaves the heat exchanger following the boiler.

CS 2.15. What is the water circulation rate through the heat-recovery loop; that is, the flow rate of the stream
that cools the gases entering the scrubber and heats the absorber effluent? What is the minimum
pressure at which this cycle can operate with liquid water? To what temperature is the gas leaving
the scrubber reheated before it is mixed with gas from other trains?

CS 2.16. One of the design specifications for power plant boilers is the amount of excess air used in burning
coal. Evaluate the heat removed from the boiler for 20% and 100% excess air if the temperature of
the exit gases and slag is 890°F. What are the ramifications of altering the ratio of air to coal?

CS 2.17. At first glance it might appear that there is no need to split the exit gases into three streams, only to
remix them later in the process. However, for the scrubbers under consideration, the maximum
allowable velocity of the gas through the empty column is given by
vm…ft/s† ˆ 0:15‰…ρL ρG†=ρGŠ
0:5 where ρG and ρL are the densities of the gas and liquid phases. Estimate the minimum column
diameters for one-, two-, and three-train operations. Why is the three-train operation used?
CS 2.18. Why is the gas leaving the scrubber reheated before it is sent to the stack? (Think about it—the
answer is not contained in the process description.)

CS 2.19. If 2.5% of the heat removed from the boiler is lost to the surroundings, at what rate is steam generated?
CS 2.20. Neglecting kinetic and potential energy changes across the steam turbine, calculate the rate at
which work is produced in megawatts.

CS 2.21. What is the flow rate or cooling water through the steam condenser if the water temperature is
allowed to increase by 25°F?

CS 2.22. The pump that transports the steam condensate from the condenser to the boiler has an efficiency of
55% (i.e., 55% of the energy input to the pump is converted to useful work on the condensate).
Neglecting friction losses in the condensate flow and changes in kinetic and potential energy, what
is the required energy input to the pump in horsepower?

CS 2.23. It is estimated that the total capital costs for the SO2-removal portion of this plant will be $25
million. The lifetime of the plant is determined to be 25 years, assuming 7000 hours per year
4 CASE STUDY 2 SO2 Removal from Power-Plant Stack Gases

operation. The annual operating costs, including labor, maintenance, utilities, and the like, are
estimated to be about $10.5 million. Using current costs for electrical energy, estimate the
incremental cost per kilowatt for the desulfurization process. (Note: The costs are based on 1978
estimates. The cost figures can be updated using available cost indices.)

Additional Problems for Study

CS 2.24. Power companies have objected to the wet-limestone scrubbing process, claiming it creates more
environmental problems than it solves. What environmental problems are created by this process?

CS 2.25. As pointed out earlier, many of the problems associated with boiler injection of limestone have
proved to be insurmountable. Discuss what you think some of the problems might be, and propose
an alternative processing scheme that retains the essential features of wet limestone scrubbing. Feel
free to use available references.

CS 2.26. There have been many changes in technology and regulations since this case study was originally
prepared. Search the internet for at least one modification in regulations and/or one new
technology associated with removing SO2 from power-plant stack gases.


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