Gas separation: processes – Solid sorption – And liquid contact
Reexamination Certificate
1999-02-08
2001-03-20
Smith, Duane S. (Department: 1724)
Gas separation: processes
Solid sorption
And liquid contact
C095S137000, C095S235000, C423S242100
Reexamination Certificate
active
06203598
ABSTRACT:
FIELD OF THE INVENTION AND RELATED ART STATEMENT
This invention relates to a technique for the purification of flue gas containing SO
2
and SO
3
as sulfur oxides and, moreover, dust such as unburned carbon (e.g., flue gas produced from heavy oil-fired boilers). More particularly, it relates to a flue gas treating technique wherein a countermeasure against SO
3
present in flue gas which may condense to produce harmful sulfuric acid fumes or an improvement in dedusting capability can be achieved at low cost and simple operation or equipment construction.
Generally, flue gas produced, for example, from a heavy oil-fired boiler in a thermal electric power plant or the like contains sulfur oxides, which include SO
3
(sulfur trioxide) in addition to SO
2
(sulfur dioxide). The proportion of SO
3
to the total amount of sulfur oxides (e.g., 1,500 ppm) may vary according to the combustion temperature of the boiler, the type of the burner, the type of the combustion catalyst, and the like, but is of the order of several percent in any event. That is, SO
3
is present in a relatively small amount, for example, of about 30 ppm. Consequently, an important basic consideration in the desulfurization treatment of this type of flue gas is the capability to absorb SO
2
.
However, when SO
3
present in flue gas produces fumes, they form harmful H
2
SO
4
mist which is strongly corrosive and constitute a factor in scale formation. Moreover, they consist of submicron particles which can hardly be captured by mere gas-liquid contact with an absorbing fluid. For this reason, some treatment for the removal of SO
3
is required in order to prevent the corrosion of the equipment and the formation of scale or in order to achieve a further purification of flue gas.
Accordingly, in a flue gas treating system for use, for example, with a heavy oil-fired boiler, it has conventionally been common practice to inject ammonia into flue gas in an upstream part of the system and thereby capture SO
3
present in the flue gas as ammonium sulfate [(NH
4
)
2
SO
4
].
One example of such a conventional flue gas treating process and system is described below with reference to FIG.
14
.
In
FIG. 14
, reference character
1
designates an air heater (boiler-side equipment) for heating combustion air to be supplied to a boiler (not shown) by utilizing the heat of flue gas. In this case, the apparatus or steps following this air heater
1
are within the scope of the present invention.
First, in an inlet duct
2
, untreated flue gas A leaving air heater
1
is brought into contact with ammonia (NH
3
) sprayed from a spray nozzle
2
a
. Thus, SO
3
present in the flue gas reacts with this ammonia and water in the flue gas to form ammonium sulfate. Since this ammonium sulfate is present as solid particles (i.e., dust) in the flue gas, the dust concentration in the flue gas is markedly increased. (For example, when the dust concentration before ammonia injection is 180 mg/m
3
N, the dust concentration after ammonia injection becomes about 360 mg/m
3
N.)
Then, flue gas A is introduced into a dry electrostatic precipitator
3
where dust B is removed therefrom. That part of dust B which was originally contained in flue gas A consists essentially of unburned carbon and, in the case, for example, of heavy oil-fired boilers, further contains impurities such as vanadium and magnesium. Moreover, most of the aforesaid ammonium sulfate is also collected in this electrostatic precipitator
3
, discharged in dust B, and disposed of, for example, as an industrial waste.
Thereafter, in order to heat treated flue gas C to be discharged into the atmosphere, in the reheating section
5
of a gas-gas heater (GGH) as will be described later, flue gas A is introduced into the heat recovery section
4
of this GGH where it is subjected to heat recovery and thereby cooled (heat recovery step). For example, the temperature of flue gas A is cooled from about 160° C. to about 100° C.
Subsequently, at least SO
2
and some of the remaining small amount of dust are removed from flue gas A in absorption towers
12
and
13
(which will be described later) of a desulfurizer
10
(absorption step), heated in the reheating section
5
of GGH to a temperature suitable for discharge into the atmosphere, and then discharged from a stack (not shown) into the atmosphere as treated flue gas C.
In this case, desulfurizer
10
has a construction in which two absorption towers
12
and
13
of the liquid column type (i.e., parallel-flow and counterflow absorption towers) are juxtaposed above a tank
11
for storing an absorbent slurry (or absorbing fluid) D and in which flue gas is successively introduced into these absorption towers and brought into gas-liquid contact with the slurry within tank
11
in the respective absorption towers. Absorption towers
12
and
13
are equipped with a plurality of spray pipes
15
and
16
, respectively, and the slurry sucked up by circulating pumps
17
and
18
is injected upward from these spray pipes
15
and
16
in the form of liquid columns. Moreover, in this case, a mist eliminator
20
for collecting and removing any entrained mist is installed on the downstream side of the absorption towers. In the apparatus of
FIG. 14
, the mist collected by this mist eliminator
20
is accumulated in a lower hopper (not shown) and returned to tank
11
through a drain pipe extending from the bottom of the hopper.
Moreover, this apparatus is equipped with a so-called rotating-arm air sparger
21
for blowing oxidizing air into the slurry within tank
11
in the form of fine air bubbles while agitating the slurry, so that the absorbent slurry having sulfur dioxide absorbed therein is brought into efficient contact with the air in tank
11
and thereby completely oxidized to form gypsum.
More specifically, in this apparatus, the absorbent slurry injected from spray pipes
15
or
16
within absorption tower
12
or
13
flows downward while absorbing sulfur dioxide and dust as a result of gas-liquid contact with flue gas, and enters tank
11
where it is oxidized by contact with a large number of air bubbles blown thereinto while being agitated with air sparger
21
, and then undergoes a neutralization reaction to form gypsum. The dominant reactions occurring in the course of these treatments are represented by the following reaction formulas (1) to (3).
(Flue gas inlet section of absorption tower)
SO
2
+H
2
O→H
+
+HSO
3
−
(1)
(Tank)
H
+
+HSO
3
−
+1/20
2
→2H
+
+SO
4
2−
(2)
2H
+
+SO
4
2−
+CaCO
3
+H
2
O→CaSO
4
. 2H
2
O+CO
2
(3)
Thus, gypsum, a small amount of limestone (used as the absorbent), and a slight amount of dust are steadily suspended in the slurry within tank
11
. In this case, the slurry within tank
11
(which may hereinafter be referred to as gypsum slurry S) is withdrawn and fed to a solid-liquid separator
23
by means of a slurry pump
22
. This slurry is dewatered in solid-liquid separator
23
, so that gypsum E having a low water content is recovered. On the other hand, a portion F
1
of the filtrate from solid-liquid separator
23
is fed to a slurry preparation tank
26
by way of a filtrate tank
24
and a filtrate pump
25
, and reused as water constituting absorbent slurry D.
Slurry preparation tank
26
is equipped with a stirrer and serves to prepare absorbent slurry D by mixing limestone G (i.e., the absorbent) introduced from a limestone silo (not shown) with filtrate F
1
fed from filtrate tank
24
. Absorbent slurry D within slurry preparation tank
26
is suitably fed to tank
11
by means of a slurry pump
27
. In order to make up for the water gradually lost, for example, owing to evaporation in absorption towers
12
and
13
, make-up water (such as industrial water) is suitably supplied, for example, to tank
11
. Limestone G is used in the form of a powder usually obtained by pulverizing quarried limestone to a particle diameter of about 100 &mgr;m
Hasegawa Shigeo
Iwashita Koichiro
Kawanishi Yoshimitsu
Kimura Kazuaki
Nakagawa Toyoshi
Mitsubishi Heavy Industries Ltd.
Smith Duane S.
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