American Journal of Oil and Chemical Technologies: Volume 2. Issue 6. June 2014
Petrotex Library Archive American Journal of Oil and Chemical Technologies
Journal Website: http://www.petrotex.us/2013/02/17/317/
Removal of SO2 Using an Amino Compound Solvent in a Regenerative
Method: Investigation of Absorption Theory
Mohammad Reza Shishesaz, Behrooz Roozbehani
Research Center of Petroleum University of Technology; Abadan Faculty of Chemical Engineering, Abadan, Iran
Abstract:
Sulphide Dioxide (SO2) contaminant was captured selectively in a pilot scaled plant. It was
reduced from 8000 ppm all the way to under 10 ppm. The gas flow rate is including 14 lit/min
and the ammine solution flow rate about 30 mi/min. The operation condition including flow
rates, PH and absorption column temperature were optimized. The data were then optimized
using “Taguchi” statistical method. It was concluded that the absorber has the ability of full
(%100) absorption in a condition with a pH of 4, absorption temperature of 120° C, absorber
flow rate of 400 ml/min, and SO2 concentration of 6800 in the inlet. Analysis of the output gas
flow demonstrates an average absorption of %99.95 for the absorber solution with a
concentration of 0.85 gr/lit. The history of the process shows that it is the first time that selective
SO2 absorption is done in pilot scale with such a unique efficiency.
Keywords: Sulphide Dioxide, solution, absorber, Taguchi
1. Introduction
Flue gases from combustion processes normally contain less than 0.5 vol % sulfur dioxide. The
relationship between the sulfur content of the fuel and the sulfur dioxide content of the resulting
flue gas is shown in Table 1. This table gives the sulfur dioxide content of combustion gases
from several typical fuels. On the other hand, stack gas from smelters handling sulfur ores can
have very high sulfur dioxide concentrations. Therefore, the economics of recovering sulfur
values from such gases can be much more favorable. Of course, the problems of discharging
such gases without sulfur dioxide removal are also much more acute.
Most combustion gases contain a small, but significant amount of sulfur trioxide (or sulfuric acid
as reaction with water) as well as sulfur dioxide. This component is of considerable importance
because of its highly corrosive nature, its effect on the chemistry of many sulfur dioxide recovery
Shishesaz, Roozbehani/American Journal of Oil and Chemical Technologies 6 (2014) 179-­‐188
processes, and its suspected critical role in air pollution problems. The amount of sulfur trioxide
emitted to the atmosphere is a function of combustion air fuel ratio, fuel composition,
combustion temperature, time at combustion temperature, the presence or absence of a catalyst,
electrostatic precipitator conditioning with ammonia, and the type of flue gas desulfurization
system. The equilibrium concentrations of the principal sulfur species in the combustion gas
from a typical fuel oil at several air fuel ratios have been calculated. The results show that in
excess air mixtures at equilibrium, SO2 is the most stable compound above 1000 K, SO3 is the
predominant sulfur compound between 900 and 600°K; while, on further cooling, H2SO4 gains
dominance over SO3 [1,2].
Flue Gas Desulfurization (FGD) technology has made considerable progress in terms of
efficiency and reliability since then lots of work has been done to specify the effect of these
pollutant on human. To reduce these effects on environment and human governmental
legislations were enacted [4,3,6]. One of the main pollutants emitted to the environment
contribute in phenomena known as acid rain, is SO2. SO2 reacts with water present in rain, to
form sulphuric acid (H2SO4). Eventually, this ‘acid rain’ returns to the earth and can cause
corrosion structures, soil damages, and lakes resulting in damaged ecosystems. Even short term
exposure to SO2 can contribute to respiratory problems in most individuals, especially those with
prior respiratory illnesses, such as asthma [5, 7].
So many technologies were designed to remove SO2 from flue gas in chemical and
petrochemical industry. Among them, wet flue gas desulfurization (WFGD) is the main
technology have earned widespread use due to high SO2 removal efficiency, reliability and low
utility consumption [10,9]. These technologies represent a varying degree of commercial
readiness. Some can claim tens of thousands of hours of operational experience, while others
have only recently been demonstrated at commercial plants [2, 8]. Environmental regulations are
the driving force behind the need for and selection of flue gas desulfurization(FGD) systems and
dictate many design criteria. For example, they limit the amounts of the pollutants which can be
discharged to the atmosphere and to any waterway. They also place limits on the concentration
of toxic metals and other chemicals in landfilled byproduct, which can significantly affect the
FGD process selection [1].
Selective SO2 Regenerative process with a cheap initial cost for solvent with no need to separate
absorbed SO2 by products lower the charge and high absorption rate increase the performance
more than that of lime/limestone, citrate, double alkali or other processes, that are all the
charactristics of amine absorbent used which specify it from other solvents. [11,2,1]
2. Experiment
The process consists of a gas cooling and pre-scrubbing section, a sulfur dioxide scrubbing
section and a regeneration and solvent purification section. The flue gas cooling and prescrubbing equipment, usually are downstream of the particulate removal equipment reduces the
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Shishesaz, Roozbehani/American Journal of Oil and Chemical Technologies 6 (2014) 179-­‐188
flue gas temperature, removes most of the acid and particulate matter. It saturates the gas with
water. The SO2 is the absorbed from the gas in a countercurrent multistage scrubber.
Adding 4.4 gram SO2 was added to 250 gram O2-N2 mixture and 50 gram of CO2 was fed to
this blend performed mixture. This was done to gain a 6607 ppm SO2 concentration and mixture,
which implies a simulated outlet stack concentration of Abadan Refinery sub-plants. Analysis for
ensuring about the concentration, which was ready to feed to the pilot, was carried on by a
TESTO detector and they confirmed our supposed concentrations.
The inlet stream to the pilot with a 14 lit/min flow rate and 80 centigrade degree was entered. 12
lit/min of entered stream was gaseous combination and 2lit/min was steam produced for
increment of mixture to a real temperature stream as we mentioned previously.
Three mixture capsules at the beginning spot of pilot are supposed to feed to the system. Beside,
a specific calculated quantity of steam is added to the gaseous mixture. This steam is loaded with
a boiler located before mixing zone of gas stream to the absorbing column.at the mixing zone a
detector was is considered to ensure concentration of all of material like SO2, which is fed to the
column. At the top of the absorption column mine-based solvent is feed to the packed column.
Packings are metal grid made of stainless steel. They increase more interaction between liquid
and gas phase. Consequently mass transfer ratio will be improved. Another reasonable though
for using of this packing is their high resistance in front of SO2 and steam corrosions. Packed
column is 150 cm height and 15 cm diameter. For insurance of column’s pressure a transmitter is
attached to. The absorber is cooled before entering to the absorption column with a jacket tube
to obtain a enhanced condition for absorption process. A level indicator is located below column
to control liquid head by means of pump 101 to reload liquid level to what is desired. Selective
process is held selectively in a counter current condition due to more efficiency. Liquid mixture
leaved from absorption column is lead to top of stripper column by pump 101. This liquid
mixture transfers its heat to the absorber in heat exchanger (b) for reviving the absorber. Pure
solvent leaves through the bottom of the stripper column.
2.1. Tower Sizing:
To introduce gas and liquid stream along the scrubbing it is needed to gain a appropriate sizing
for tower to achieve an optimized condition for tower. The specification of the column diameter
is an important factor to bring flooding. Actually, flooding in a range of 60-75% leads the
process to an optimized condition. In this pilot flooding factor is considered 70% this will
provide a good situation for tower efficiency enhancement. It is necessary to use experimental
curves, which show pressure drop in two-phase bed.
Stream factor could be shown as the below
!!
!!
!
!! !!!
( !) (
181
)=
Shishesaz, Roozbehani/American Journal of Oil and Chemical Technologies 6 (2014) 179-­‐188
by the way after this calculation and considering the quantity of drop pressure related to per
square meter which is mostly experimentally admitted and by using the figure 2 it is obviously
clear the value of fractional equation in the below. Simply 𝐺 ! can be found.
! ! !! !!!.! !
!! (!! !!! )!!
and finally curves diameter is achievable by equation 3.
A! = π
D!!
G
= !
4
G
Absorber column has a 0.152 sectio diameter and sectional area of 1.824e-002. All of the
important features for column are shown briefly in table 1.
Table 1. Absorption column specification
Absorption column
Section Diameter (m)
0.1524
X-Sectional Area (m2)
1.824e-002
Section Height (m)
2.286
Section Delta P (kPa)
4.675e-002
DP per Length (kPa/m)
2.502e-002
Flood Gas Velocity (m3/h-m2)
1.829e+004
Flood Gas Velocity (m/s)
5.080
HETP (m)
0.1524
After entering to the stripper column we because of reducing in absorption and also increasing of
column’s temperature SO2 separate from solvent. A pressure controller due to fix unbalanced
pressure deviations controls stripper column. Furthermore a sensor is hold to control column’s
temperature by means of liquid deviations. (c) a sensor for control pressure drop of the column
also is considered. It let control gradient pressure of the column. information of vapor phase
incoming to the scrubber are shown in the table 2.
Table 2. Vapor and Liquid profile
Vapor profile
Mass Flow (kg/h)
Gas Flow (ACT_m3/h)
Molecular Weight
Temperature (C)
Density (kg/m3)
Viscosity (cP)
Fluid Pressure (bar_g)
104.5
98.63
28.75
58.90
1.060
1.748e-002
4.000e-003
Liquid profile
Mass Flow (kg/h)
Liquid Flow (m3/s)
Molecular Weight
Temperature (C)
Density (kg/m3)
41.13
1.269e-005
20.27
58.91
900.5
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Shishesaz, Roozbehani/American Journal of Oil and Chemical Technologies 6 (2014) 179-­‐188
Viscosity (cP)
Surface Tension (dyne/cm)
0.4027
7860
Gaseous mixture mid to steam is crossed into a shell and tube heat exchanger to decrease its
temperature because of containing solvent into it. The stream is crossed into a reflux drum to
separate solvent from gas. Pure solvent settles in drum and it is pumped to the absorption tower
again.
Figure 1. SO2 absorption pilot plant
3. Absorption theory
A chemical absorption leads a better process condition in scrubbing process. Absorption with
reaction is conducted to approach to a more mas transfer coefficient. More removal quantity of
solute in liquid phase in packed column has been established in the recent years. It increases
driving force and causes on the partial pressure of liquid phase. In table 2 detail design
information is shown.
In this continuous steady state process, SO2 is absorbed into liquid in which it dissolves and
react, the reaction take place as what previously was mentioned it could be assumed one order
reaction in a perfect form of injection of amino compound solvent to calculate rate of reaction
and assumption that mass transfer resistance in the gas phase is negligible. It could be assumed:
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Shishesaz, Roozbehani/American Journal of Oil and Chemical Technologies 6 (2014) 179-­‐188
𝑢!
𝜕𝐶!
𝜕𝐶!
𝜕𝐶!
𝜕𝑢! 𝜕𝑢! 𝜕𝑢!
+ 𝑢!
+ 𝑢!
+ 𝐶!
+
+
+
𝜕𝑥
𝜕𝑦
𝜕𝑧
𝜕𝑥
𝜕𝑦
𝜕𝑧
− 𝐷!"
𝜕 ! 𝐶! 𝜕 ! 𝐶! 𝜕 ! 𝐶!
𝜕𝐶!
+
+
+ 𝑅! = −
𝜕𝑥 !
𝜕𝑦 !
𝜕𝑧 !
𝜕𝜃
As it mentioned that reaction done in a steady state condition term (2) equals zero.
𝜕𝐶!
= 0 𝜕𝜃
final formulation for the absorption process is
𝐷!"
𝜕 ! 𝐶!
− 𝐾𝐶! = 0 𝜕𝑥 !
Putting !! !!
!! !
𝐷!" 𝑞
=
!"
!"
=
!" !"!
!"! !"
=𝑞
!"
!"!
𝑑𝑞
− 𝐾𝐶! = 0 𝑑𝐶!
𝑞𝑑𝑞 = −(
𝐾
)𝐶 𝑑𝐶 𝐷!" ! !
𝑞!
𝐾
=−
𝐶 ! + 𝑐𝑜𝑛𝑠𝑡. 2
2𝐷!" !
In the final condition of system at y=∞, 𝐶! = 0 and
𝑑𝐶!
𝑑𝑥
!
=−
184
!!!
!"
= 0 𝑎𝑛𝑑 ℎ𝑒𝑛𝑐𝑒 𝑐𝑜𝑛𝑠𝑡 = 0.
𝐾
𝐶 !
𝐷!" !
Shishesaz, Roozbehani/American Journal of Oil and Chemical Technologies 6 (2014) 179-­‐188
𝑑𝐶!
𝐾
=±
𝐶
𝑑𝑥
𝐷!" !
𝑑𝐶!
𝐾
=±
𝑑𝑥
𝐶!
𝐷!"
by integration it is derived :
ln 𝐶! = ±
𝐾
𝑥 + 𝑐𝑜𝑛𝑡𝑎𝑛𝑡
𝐷!"
At the first surface x=0 and 𝐶! = 𝐶!" therefor: ln 𝐶!" = 𝑐𝑜𝑛𝑠𝑡𝑎𝑛𝑡.
ln 𝐶! − ln 𝐶!! = ±
𝐾
𝑥
𝐷!"
4. Analysis
While running the plant, the gas flow from three capsules of SO2, CO2 and N2 enter the
absorption column. In addition, produced steam from the boiler feed to the tower in order to help
improved distribution of the reactor besides increasing temperature to desired degree.
The tests were done in 100, 200, 300, 400 ml/min levels examining the optimum point of
absorption, the absorption temperature and pH were taken as variables; the first of which was
analyzed in five levels of 105, 110, 115, 120 and 127 centigrade an the latter was observed in
levels of 3, 4 and 6.
Analysis of the output gas from the stack simulated after passing through designed plant
illustrates that gas contains %65 Nitrogen, % 19 water steams and %12 Carbon Dioxide. The
concentration of consumed absorber was 0.78 gr/lit; nothing its low concentration in proportion
to the input SO2 of the absorption tower, the efficiency is to the nearest 100 percent that is quite
unique and desirable and more than what is expected from the cat-cracker unit. Consequently,
the amount of SO2 inlet to the absorption column was tested in three level of 4800, 6800 and
8800 ppm. The results of the experiment demonstrate the absorber- even with a low
concentration- has strong absorption ability so that it reduce the amount of 8800 of SO2 feed to
10 ppm in the outlet.
PH
1
2
3
SO2
inlet
(ppm)
4300
6700
8400
Solvent
flow rate
Lit/min
150
150
150
Absorption
temperature
120
120
120
gas flow
rate
(lit/min)
9
9
9
185
Absorption
temperature
(°C)
55
54
52
Absorption
Pressure
(bar)
0.01
0.01
0.01
desorpt
ion
115
115
115
SO2
outlet
(ppm)
1
4
9
Shishesaz, Roozbehani/American Journal of Oil and Chemical Technologies 6 (2014) 179-­‐188
4
9800
150
120
PH
4
4
4
4
SO2
inlet
(ppm)
Solvent
flow rate
Lit/min
Absorption
temperature
6500
6500
6500
6300
100
200
300
400
120
120
120
120
PH
SO2
inlet
(ppm)
4
4
4
4
6300
6300
6300
6300
Solvent
flow
rate
Lit/min
400
400
400
400
Absorption
Temperature
126
120
110
105
9
53
gas
flow
rate
(lit/min)
9
9
9
9
Gas
flow
rate
(lit/min)
9
9
9
9
0.01
113
Absorption
temperature
(°C)
Absorption
Pressure
(bar)
desorption
SO2
outlet
(ppm)
66
68
66
65
0.01
0.01
0.02
0.03
115
115
115
113
5
3
2
1
Absorption
temperature
(°C)
Absorption
Pressure
(bar)
Desorption
SO2
outlet
(ppm)
77
74
65
65
0.03
0.03
0.03
0.03
115
113
100
89
1.2
0.95
0.35
0.2
4.5
4
3.5
SO2 outlet
3
2.5
2
1.5
1
0.5
0
-0.5
100
105
110
115
120
Desorption Temperature
125
130
Figure 2. Solvent flow rate versus desoption temperature.
186
12
Shishesaz, Roozbehani/American Journal of Oil and Chemical Technologies 6 (2014) 179-­‐188
concentration of final emmited SO2 6
5
4
3
2
1
0
0
100
200
300
400
500
Solvent flow rate
7000
6000
5000
4000
3000
2000
1000
0
1
2
solvent rate
inlet ppm concentration
Figure 3: Solvent flow rate versus final concentration of released SO2 in a constant PH.
3
4
final SO2 outlet
Figure 4. Schematic view of absorption amounts in solvent flow rate increase
5. Conclusion:
Based on figure 3, there is a nonlinear relation between the absorbed sulfide dioxide and solvent
flow rate. The amount of final absorbed SO2 would increase as the solvent flow rate rises. This
behavior is consistent in various pH amounts. Figure 4 is a schematic view of SO2 absorption
improvement via solvent increase.
The five hour test verified the selectivity and high industrial performance of the absorbent.
Results from the experiments confirmed the effectiveness calculated by ANOVA statistical
approach. By comparing the statistical and experimental results, Taguchi prediction showed an
acceptable behavior of SO2 absorption variation with effective parameters and showed that the
Taguchi approach can predict the process behavior qualitatively and may not be employed for
predicting the exact values in this case.
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Index:
𝑮𝒂𝒓𝒆𝒂
𝑳
𝑮
𝑫𝑮
𝑫𝑳
𝑷
𝑴
𝑻
𝒂
𝒆
𝝁
𝒈𝒄
𝑨
𝑫
solvent flow rate
Gas flow rate
Density of gas
Density of liquid
Pressure
Molecular weight
temperature
Packing factor
Packing factor
Viscosity
Gravitational constant
cross section area
Column diameter
188