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A PLANT DESIGN PROJECT REPORT ON GASIFICATION OF 1000 Kg/Hr COAL
SESSION: 2007 – 2011
SUBMITTED BY
FARHAN SHAHZAD E08-CE-09 ASAD NOOR E08-CE-34 SALMAN AKBAR MAILK E08-CE-36 MUHAMMAD ZAHID E08-CE-37
SUPERVISED BY
PROF. DR. ABDULLAH KHAN DURRANIENGR. ABDUL BASIT
INSTITUTE OF CHEMICAL ENGINEERING AND TECHNOLOGY
UNIVERSITY OF THE PUNJAB LAHORE
1
A PLANT DESIGN PROJECT REPORT ON GASIFICATION OF 1000 Kg/Hr COAL
SUBMITTED TO
PROF. DR. ABDULLAH KHAN DURRANI
ENGR. ABDUL BASIT
UNIVERSITY OF THE PUNJAB, LAHORE
IN
PARTIAL FULFILMENT OF THE REQUIREMENTS
FOR THE DEGREE OF
B.Sc. Engg (Chemical Engineering)
BY
FARHAN SHAHZAD E08-CE-09
ASAD NOOR E08-CE-34
SALMAN AKBAR MAILK E08-CE-36
MUHAMMAD ZAHID E08-CE-37
SESSION 2007-2011
INSTITUTE OF CHEMICAL ENGINEERING & TECHNOLOGY
UNIVERSITY OF THE PUNJAB, LAHORE.
2
Approval Certificate
I certify that contents and form of thesis submitted by Mr. Farhan Shahzad, Mr. Asad
Noor, Mr. Salman Akbar Malik and Muhammad Zahid have been found satisfactory and
are according to the prescribed format. I recommend it for the evaluation by the external
examiner for the award of degree of B.Sc. Engg (Chemical Engineering).
_____________________ ______________________
Dr. Abdullah Khan Durrani Engr. Abdul BasitProfessor of chemical engineering Lecturer Institute of Chemical Engineering Institute of Chemical Engineering & Technology, University of the & Technology, University of the Punjab, Lahore. Punjab, Lahore.
3
In the name of Allah the Most
Beneficent, THE Merciful
i
Dedicated
To our parents
Whose love and affection
Made our life worth living
ii
ACKNOWLEDGEMENT
First of all we would like to thank Allah Almighty for the strength, courage and
blessings that He bestowed upon us during design project.
We consider ourselves very lucky to have Prof. Dr. Abdullah Khan Durani as our
supervisor. We would like to thank him for all the guidance that he has given us to
complete our project objectives in a successful manner. We are very much thankful to
him for spending his precious time to share his knowledge & experience with us.
This work may not have been possible without the attention and devotion of Engr.
Abdul Basit as co-supervisor.
We express our sincere gratitude in the respect of honorable Prof. Dr. Syed
Zahoor-Ul-Hassan Rizvi, Director Institute of Chemical Engineering & Technology
University of the Punjab Lahore, for providing us all the necessary facilities for the
completion of this research work.
This section cannot come to an end unless we admit the encouragement of our friends
and teachers who assisted us in every aspect of this project.
ASAD NOOR
FARHAN SHAHZAD
MUHAMMAD ZAHID
SALMAN AKBAR MALIK
iii
iv
Contents
1 Coal...........................................................................................................................1
1.1 Types Of Coal.....................................................................................................2
1.1.1 Peat..............................................................................................................2
1.1.2 Lignite...........................................................................................................2
1.1.3 Sub-Bituminous Coal....................................................................................3
1.1.4 Bituminous Coal...........................................................................................3
1.1.5 Semi-Anthracite Coal....................................................................................4
1.1.6 Anthracite Coal.............................................................................................4
1.2 Coal Analysis......................................................................................................5
1.2.1 Proximate Analysis.......................................................................................5
1.2.2 Ultimate Analysis..........................................................................................6
1.3 Minerals In Coal..................................................................................................7
1.4 Coal Properties...................................................................................................8
1.4.1 Heating Value...............................................................................................8
1.4.2 Caking And Swelling Properties...................................................................8
1.4.3 Hardness......................................................................................................9
1.4.4 Density.........................................................................................................9
1.4.5 Ash Properties............................................................................................10
1.5 Application Of Coal...........................................................................................12
1.5.1 Coal As Fuel...............................................................................................12
1.5.2 Coking And Use Of Coke...........................................................................12
v
1.5.3 Production Of Ethanol................................................................................13
1.5.4 Gasification.................................................................................................13
1.5.5 Liquefaction................................................................................................13
1.6 Coal Reserves In Pakistan................................................................................14
1.7 Application Of Pakistani Coal............................................................................17
1.7.1 Use Of Coal For Power Generation............................................................17
1.7.2 Use Of Coal As An Industrial Fuel..............................................................17
1.7.3 Brick Kilns...................................................................................................18
1.7.4 Cement Production.....................................................................................18
1.7.5 Coal Briquettes...........................................................................................18
1.7.6 Coal Gasification........................................................................................18
1.7.7 Underground Coal Gasification..................................................................18
2 Coal Gasification.....................................................................................................20
2.1 Chemical Reactions..........................................................................................21
2.1.1 Pyrolysis Reactions....................................................................................21
2.1.2 Gasification Reactions................................................................................21
2.1.3 Acceptor Reactions....................................................................................22
2.1.4 Heats of Reactions.....................................................................................22
2.1.5 Equilibrium Considerations.........................................................................23
2.1.6 Reaction Kinetics........................................................................................23
2.2 Gasifier Types...................................................................................................24
2.2.1 Fixed-Bed Gasifier......................................................................................24
2.2.2 Fluidized-Bed Gasifier................................................................................25
2.2.3 Entrained-Flow Gasifier..............................................................................26
vi
2.3 Commercial Gasifiers........................................................................................28
2.3.1 The LurgiGasifier........................................................................................28
2.3.2 Fixed-Bed Gasifier......................................................................................28
2.3.3 The Koppers-Totzek Gasifier......................................................................28
2.3.4 The Winkler Gasifier...................................................................................29
2.4 Process selection..............................................................................................29
2.4.1 Raw Materials.............................................................................................30
2.4.2 Steps Involved............................................................................................30
2.4.3 Process Equipments...................................................................................30
2.4.4 Process Description....................................................................................31
2.4.5 Catalyst Selected.......................................................................................32
2.5 Fluidized Bed Gasifier Design...........................................................................33
2.6 Factors Affecting Reaction Rates......................................................................36
2.6.1 Temperature...............................................................................................36
2.6.2 Pressure.....................................................................................................36
2.6.3 Coal Properties...........................................................................................36
2.6.4 Types Of Reactions....................................................................................36
2.7 Method Of Contacting.......................................................................................37
2.7.1 Fixed bed....................................................................................................37
2.7.2 Molten Bath................................................................................................39
2.7.3 Entrained Phase.........................................................................................39
3 Material Balance.....................................................................................................40
3.1 Material Balance On Dryer................................................................................40
3.2 Material Balance On Fluidized Bed Gasifier.....................................................42
vii
3.3 Material Balance On Cyclone Separator...........................................................49
3.4 Material Balance On Scrubber..........................................................................51
3.5 Material Balance On Absorber..........................................................................54
4 Energy Balance.......................................................................................................57
4.1 Energy Balance On Heat Exchanger................................................................57
4.2 Energy Balance On Dryer.................................................................................60
4.3 Energy Balance On Gasifier..............................................................................63
4.4 Energy Balance On Scrubber...........................................................................67
5 Equipment Design...................................................................................................69
5.1 Fluidized Bed Gasifier Design...........................................................................69
5.2 Heat Exchanger Design....................................................................................76
5.3 Cyclone Separator Design................................................................................85
5.4 Design Of Scrubber..........................................................................................93
5.5 H2S Absorber Design......................................................................................100
6 Instrumentation.....................................................................................................107
6.1 Control............................................................................................................108
6.1.1 Incentives ForChemical Process Control.................................................108
6.1.2 Elements OfControl System.....................................................................109
6.1.3 Modes of Control......................................................................................112
6.1.4 Selection of Controller..............................................................................113
6.2 Control Loops..................................................................................................114
6.2.1 Feed Back Control Loop...........................................................................115
6.2.2 Feed Forward Control Loop......................................................................115
6.2.3 Ratio Control............................................................................................116
viii
6.2.4 Auctioneering Control Loop......................................................................116
6.2.5 Split Range Loop......................................................................................116
6.2.6 Cascade Control Loop..............................................................................116
6.3 Control Loops Around Equipment’s................................................................116
6.3.1 Control Loops On Gasifier........................................................................116
6.3.2 Control Loop On Compressor...................................................................119
6.3.3 Control Loop On Absorption Column........................................................120
6.3.4 Control Loops On Heat Exchanger...........................................................121
7 Cost Estimation.....................................................................................................123
7.1 Total Purchased Cost Of Major Equipment.....................................................123
7.1.1 Cost Estimation Of Heat Exchanger.........................................................123
7.1.2 Cost Estimation Of Cyclone Separator.....................................................124
7.1.3 Cost Estimation Of Absorber....................................................................125
7.2 Fixed Capital Cost...........................................................................................128
7.3 Fixed Cost.......................................................................................................129
7.4 Variable Cost..................................................................................................130
7.5 Utilities............................................................................................................131
ix
List of figures
Figure 1: Coal production by province............................................................................14
Figure 2: Moving bed gasefier........................................................................................25
Figure 3: Fluidized bed gasefier.....................................................................................26
Figure 4: Entrained flow gasifier.....................................................................................27
Figure 5: Control loops on gasefier..............................................................................118
Figure 6: Control loops on compressor........................................................................119
Figure 7: Control loop on absorption column...............................................................120
Figure 8: Control loop on heat exchanger..................................................................121
x
List of Tables
Table 1-1: World Coal Reserves by Region.....................................................................1
Table 1-2: Classification Of Coal......................................................................................5
Table 1-3: Particle and Bulk Density.............................................................................10
Table 1-4: Pakistan's Coal Reserves(4).........................................................................15
Table 1-5: Composition Of Different Coal Fields(4).......................................................16
Table 3-1: Summary of Material Balance on Dryer........................................................41
Table 3-2: Summary Of Material Balance On Gasefier..................................................46
Table 3-3: Summery Of Material Balance On cyclone separator...................................50
Table 3-4: Summery Of Material Balance On Scrubber.................................................53
Table 3-5: Summery Of Material Balance on Scrubber..................................................56
Table 4-1: Summery Of Energy Balance on Gasefier....................................................65
Table 5-1: specification data sheet of gasefier...............................................................75
Table 5-2: specification data sheet of heat exchanger...................................................84
Table 5-3: particle size distribution in cyclone separator................................................87
Table 5-4: calculated performance of cyclone................................................................89
Table 5-5: specification data sheet of cyclone separator...............................................91
Table 5-6: specification data sheet of scrubber..............................................................99
Table 7-1: total purchased cost of equipment..............................................................133
xi
xii
1 Coal
Coal is a readily combustible black or brownish-black sedimentary rock. The harder
forms, such as anthracite coal, can be regarded as metamorphic rock because of later
exposure to elevated temperature and pressure. It is composed primarily of carbon
along with variable quantities of other elements, chiefly sulfur, hydrogen, oxygen and
nitrogen.
Table 1-1: World Coal Reserves by Region
Region % of Total Reserves R/P Ratio
North America 26.2% 234
South and Central America 2.2% 381
Europe 12.7% 167
Former Soviet Union 23.4% >500
Africa and Middle East 5.8% 246
Asia/Pacific 29.7% 147
World 100% 216
All coal has been formed from biomass. Over time this biomass has been turned into
peat. When covered under a layer of overburden, the influence of time, pressure, and
temperature convert this material into brown coal or lignite. Subsequently, the latter
material will turn into sub-bituminous coal, then into bituminous coal, and finally into
anthracite. Coal is often classified in terms of its rank, which increases from brown coal
to anthracite. The classification of coal by rank for ash and moisture-free coal is given in
1
Table 1.2Brown coal, lignite, and sub-bituminous coals are called low-rank coals,
whereas higher-rank coals are often called hard coals. The terms brown coal and lignite
are essentially synonymous, lignite being used more often in the United States and
brown coal in Europe and Australia [1]
1.1 Types Of Coal
As geological processes apply pressure to dead biotic matter over time, under suitable
conditions it is transformed successively into:
1.1.1 Peat
It is the first stage product in the formation of coal from wood under the action of
temperature, pressure and bacteria. Freshly dug peat contains large amount of water
(up to 90%), hence it is sun dried before using as a fuel. Its calorific value is (around
4500 kcal/kg) slightly higher than that of the wood and it is mainly used as a domestic
fuel as well as for power generation. Near the surface of the deposit, peat is light brown
in color and highly fibrous in nature. With the increase in the depth, the color becomes
darker and finally black, when vegetable structure is not obvious. A part of the water
content of freshly dug peat is drained off while large part is removed by drying in air for
40-50 days. The composition and properties of peat vary widely from place to place,
depending on the nature of the original plant material and the agencies and extent of
decay. The lower layers of peat have usually higher ash than the upper layers. Peat is
largely used in steam boilers, power stations and gas producers. The low temperature
carbonization of peat is also practiced for getting peat coke and by products peat coke
is a valuable fuel for some metallurgical processes. Peat is also used as a fertilizer or
for making fertilizer. However most of the peat is used in heat generation.
1.1.2 Lignite
It is the second stage product in the formation of coal from wood. It is friable and occurs
in thick seams (up to 30 meters thickness) near the earth’s surface. Its moisture content
is up to 60 % and calorific value around 5000 kcal/kg (on 10% moisture basis.)
2
On exposure to the atmosphere, the brown color of lignite darkens and moisture content
reduces to an equilibrium value of 10-20% on drying, lignite shrinks and breaks up in an
irregular manner. Hence, it cannot be moved far from the mine. It is likely to ignite
spontaneously as it adsorbs oxygen readily and must not be stored in the open without
care. The lignite deposits in many areas are relatively near the earth’s surface and are
quite thick. Composition and properties of lignite varies widely. The carbon content is
70-75% and the oxygen content is 21-26%. The volatile matter is often over 50% and in
a large number of cases the ratios of volatile matter to fix carbon are 1:1. The ash of
lignite’s is generally low. Raw lignite is an inferior fuel due to high moisture, low calorific
value, small size and bad weathering properties. Lignite is of economic importance in
those places where it is available and other fuels do not occur in abundance. Lignite is
used in the generation of electricity in thermal power stations and carbonized briquettes
are used as smokeless fuel. Other uses of lignite are in gas production and
metallurgical furnaces. Lignite is extensively used in the manufacturing of producer gas.
It is also gasified into synthesis gas for ammonia production.
1.1.3 Sub-Bituminous Coal
It is black, homogeneous and smooth mass having high moisture and volatile matter
content which breaks into smaller pieces on exposure to air. Its carbon content is
around 70-80% and oxygen content is 10-20%. It is a non-coking coal having calorific
value about 7000 kcal/kg. It is variety of mature lignite resembling true coal in color and
appearance. It is black in color with a dull, waxy luster. It is denser and harder than
lignite and has lower moisture content (12-25%).Most sub-bituminous coals appear
banded like bituminous coal. Like lignite; sub-bituminous coal disintegrates on exposure
to atmosphere and is therefore difficult to transport. The sub-bituminous coal has 70-
78% carbon, 4.5-5.5% hydrogen and about 20% oxygen. The air dried moisture is 10-
20%, the volatile matter is 40% above. The calorific value is 6,800-7,600 kcal/kg[dry
mineral matter free]. It ignites easily and is used in raising steam and for manufacturing
gaseous fuels also if low in sulphur.
3
1.1.4 Bituminous Coal
It is most common variety of coal known as “Koela” in Urdu. It is black and brittle which
burns and ignites readily with yellow smoky flame. It has low moisture content (<10%)
and the carbon content varies from 75-90% whereas the volatile matter content is 20-
45%. Depending upon the volatile matter content, it is termed as low volatile, medium
volatile and high volatile coal. Its calorific value on mineral free basis goes up to
9000 kcal/kg. Most of the cooking coals is essentially bituminous coal. It is used for
power generation, coke making, gasification; domestic heating etc. Non-coking
bituminous coals are generally used for purposes other than coke making which
requires coking coal. Bituminous coal is used for combustion in domestic ovens,
industrial furnaces and boilers, railway locomotives and thermal power stations. Two
other important uses are carbonization and gasification, whereby coal is converted into
solid fuels, gaseous fuels and liquid fuels. It is also a source of a wide range of coal
chemicals, fertilizers and synthetic liquid fuels.
1.1.5 Semi-Anthracite Coal
Its properties lie between that of bituminous and anthracite coal. It is harder than the
most mature bituminous coal, and ignites more easily than anthracite to give a short
flame changing from yellow to blue. Some of the properties of semi-anthracite are:
1. Moisture: 1-2%
2. Volatile mater: 10-15%
3. Calorific value: 8,500-8,800 kcal/kg
It is non-coking coal.
1.1.6 Anthracite Coal
This is the most mature coal; hence is of highest rank. Thus high carbon content (85-
95%) and low volatile matter (<10%) coal is hard, non-coking and burns without smoke
with a short non-luminous flame thereby imparting intense localized heating. It ignites
with difficulty due to low volatile matter content. The calorific value may be up to 8000-
4
8500 kcal/kg which is slightly lower than that of bituminous coal due to its lower
hydrogen content.
It has sub-metallic luster, sometimes even a graphite appearance. Anthracite is
characterized by low volatile matter (3-10%) and high carbon content (over 92%). The
air
dried moisture is 2-4%. The hydrogen content is 2.8-3.9% and calorific value is 8,400 to
8,700 kcal/kg. Anthracite arenon caking. The chief uses of anthracites are in boilers,
domestic ovens and metallurgical furnaces. It is also used in small quantities as a
component of coke oven charges. On calcining it gives thermo-anthracite which is a raw
material for the production of carbon electrodes.
1.2 Coal Analysis
The methods generally used for specifying the analysis of coals has developed along
pragmatic lines and are aimed at providing a useful guide to coal users rather than a
purely chemical approach. The two types of analysis for any coal are the proximate
analysis and the ultimate analysis.
Table 1-2: Classification Of Coal
Class Volatile matter Fixed carbon Heating value
WT% WT% MJ/kg
Anthracite <8 >92 36-37
Bituminous 8-22 78-92 32-36
Sub-bituminous 22-27 73-78 28-32
Brown coal (lignite) 27-35 65-73 26-28
5
1.2.1 Proximate Analysis
The proximate analysis determines the moisture, volatile matter, fixed carbon, and ash
in the coal. The analysis is an essentially practical tool providing an initial indication of
the coal’s quality and type. The methods for performing these analyses have been
standardized by all the major standards institutions These standards, though similar in
nature, are different from one another in, for example, the temperature specified for
determining the volatiles content, so it is important when providing data to specify the
method used.
Moisture is determined by drying the coal under standard conditions for 1 h at 104–
110 OC. The method determines the sum of all moisture; that is, both the surface
moisture caused by rain and so on, and the inherent moisture. The inherent moisture is
the water that is very loosely bound in the coal. It can vary from a few percent in
anthracite to 60–70% in brown coal.
Volatile matter is determined by heating the coal in a covered crucible for a defined
time at a defined temperature (e.g., 7min at 950oC ASTM). The loss in mass, minus the
mass of the moisture, represents the mass of the gaseous constituents formed by the
pyrolysis under the conditions mentioned.
Ash is the inorganic residue that remains after combustion of the coal. It consists mainly
of silica, alumina, ferric oxide, lime, and of smaller amounts of magnesia, titanium-oxide,
and alkali and sulfur compounds.
Fixed carbon is determined by subtracting from 100 the mass percentages of moisture,
volatile matter, and ash. It should be remarked that fixed carbon is an artificial concept
and does not mean that this material was present in the coal as pure C in the beginning.
Although the proximate analysis already tells the expert a lot about the coal, for
gasification it is mandatory to have also the ultimate hydro carbonaceous part of the
coal.
6
1.2.2 Ultimate Analysis
For the ultimate analysis the percentages of carbon, hydrogen, oxygen, sulfur, and
nitrogen are determined. In the past, oxygen was sometimes reported as by difference.
If at all possible this should not be accepted, as it makes it impossible to have any
control over the quality of the analysis. Proper balances are the basis for a good
process design and a good operation of plants, but a good balance is equally
dependent on a good elemental analysis. The relevance of sulfur in the coal for
gasification is the same as for oil derived heavy residual feed stocks, which generally
contain more sulfur than most coals, and sulfur contents in coal range from 0.5–6 wt%.
In coals with a high sulfur content, most of the sulfur is generally present in the form of
Pyrite. Note that the quantity of pyritic sulfur is an indicator for the potential
abrasiveness of the coal.
The nitrogen content in coals ranges from 0.5–2.5wt%. Only part of the nitrogen in the
coal is converted into ammonia and HCN upon gasification, whereas the remainder is
converted into elemental nitrogen. The presence of the coal-derived nitrogen in the
product gas is one reason why it is not always essential to gasify coal with very pure
oxygen (>99 mol%), even when the gas is used for the production of syngas or
hydrogen. The percentage of the nitrogen in the coal that is converted into elemental
nitrogen upon gasification will depend on the type of nitrogen compounds in the coal.
1.3 Minerals In Coal
Beyond the elements described above, which are provided with every ultimate analysis
of coal, it will be found that a substantial part of the periodic table can be shown to be
present in coals. These other elements can be divided into macro components, the
presence of which is usually given in wt% and the micro or trace elements that are only
present at ppm levels.
The chlorine content in coal is mostly well below 1wt%. However, in some coals it may
be as high as 2.5wt%. In combination with a low nitrogen content in the coal, this will
result in a high caustic consumption in the wash section of a gasifier.
7
Chlorides have three possible detrimental effects in the plant:
1. Chlorides have a melting point in the range 350–800 oC; they deposit in the syn gas
cooler and foul the exchanger surface. The first indication of this is an increase in the
syngas cooler outlet temperature.
2. In the reactor chlorides can react with the hydrogen present to form HCl, which will
decrease the pH of the wash water or condensate.
3. Chlorides may also form NH4Cl with high nitrogen feeds. With such feed stocks the
chloride deposits as NH4Cl in the economizers at temperatures below about 280 0C.
Further, as an aqueous solution this leads to severe chloride stress corrosion in
stainless steels that are used, for example, in burners and instrument lines. Coals also
contain phosphorus, but this has less significance for gasification than, for instance, for
the steel industry.
1.4 Coal Properties
1.4.1 Heating Value
The heating value is obtained by combustion of the sample in a calorimeter. If not
available, the heating value can be calculated with, for example, the Dulong formula
from the ultimate analyses:
HHV(MJ/kg)33.86×C 144.4×(HO/8) 9.428×S
Where C, H, O, and S are the mass fractions of the elements obtained from the ultimate
Analysis. There are other formulae for calculating the heating value from the ultimate
And/or proximate analyses.
HHV(MJ/kg)34.91×C 117.83×H 10.34×O 1.51×N 10.05×S 2.11×Ash
8
It is always useful to calculate the heating value from these analyses, as it is a good
cross check on measured values. If the deviation is more than a few percent, all
analyses must be checked. [1]
1.4.2 Caking And Swelling Properties
Another important property of a coal is the swelling index. The swelling index is
determined by heating a defined sample of coal for a specified time and temperature,
and comparing the size and shape taken by the sample with a defined scale. There are
a number of different scales defined in, for example, ASTM D 720-91, BS 1016, or ISO
335. The swelling index is an indicator for the caking properties of a coal and its
expansion on heating. Softening/caking does not occur at a certain temperature but
over a temperature range. It is an important variable for moving-bed and fluid-bed
gasifiers. For the gasifiers of entrained-flow systems, the coal softening point has no
relevance. However, the softening point may limit the amount of preheating of the
pulverized coal feedstock used in dry coal feed gasifiers.
1.4.3 Hardness
Physical properties are not very relevant for the operation of a gasifier as such. The
hardness of the coal is, for example, mainly important for the milling and grinding up
stream of the gasifier. The hardness of a coal is usually dependant on the nature and
quantity of its ash content, although some coals, such anthracites, are also hard. A high
ash content or a very high hardness of the ash in the coal can make a feedstock un
attractive for gasification because of the high cost of milling and grinding. Ashes with
high silica and/or alumina contents have a high hardness. The hardness is generally
characterized by the hard grove grind ability index.
1.4.4 Density
The density is primarily of importance for the transport of the coal. In this connection, it
is important to discriminate between the particle density and the bulk density of the coal.
The bulk density is always lower, as is shown in table 1.3
9
Table 1-3: Particle and Bulk Density
Fuel Particle (true)Density
(kg/m3)
Bulk (apparent) Density
(kg/m3)
Anthracite 1450-1700 800-930
Bituminous coal 1250-1450 670-910
lignite 1100-1250 550-630
1.4.5 Ash Properties
1.4.5.1 Melting Properties
For all gasifiers the ash-softening and ash-melting or fusion temperatures are important
variables. For fluid-bed gasifiers these properties govern the upper operating
temperature at which agglomeration of the ash is initiated. For entrained-flow gasifiers it
is essential to ensure that the ash flows continuously and that the slag tap does not
freeze up. The method for determining these temperatures is specified in ASTM D1857,
“Fusibility of Coal and Coke Ash,” or similar specifications, such as ISO 540. In these
methods the temperatures measured relate to the behavior of an ash sample under
specified conditions and are reported as IDT (initial deformation temperature), ST
(softening temperature), HT (hemispherical temperature), and FT (fluid temperature).
For gasifier applications the ash-melting characteristics should be determined under 10
reducing conditions, as these data may differ considerably (generally, but not
universally lower) from data for oxidizing conditions.
An additional property required for slagging gasifiers is the slag viscosity-temperature
relationship. It is generally accepted that for reliable, continuous slag tapping a viscosity
of less than 25 Pas is required. The temperature required to achieve this viscosity (T
250) is therefore sometimes used in the literature.
Some slag’s are characterized by a typical exponential relationship between viscosity
and temperature over a long temperature range. For others this relationship is
foreshortened at a critical temperature (Tcv) at which the viscosity increases very
rapidly with decreasing temperature. For a slagging gasifier to operate at a reasonable
temperature, it is necessary for the slag to have a Tcv<1400 OC.
The relationship between ash-melting characteristics and composition is a complicated
one and is dependent largely on the quaternary .In general, slags that are high in silica
and/ or alumina will have high ash-melting points, but this is reduced by the presence of
both iron and calcium hence the use of limestone as a flux. However, the SiO2/Al2O3
ratio is also important, and where the calcium content is already high, there can be
some advantage to lowering the ash melting point by adding SiO2.
In dry ash moving-bed gasifiers and in fluid-bed gasifiers, coals with a high ash melting
point are preferred, whereas in slagging gasifiers, coals with a low ash melting point are
preferred. The caking properties of a coal and the melting characteristics of its ash are
the reason that there are forbidden temperature ranges that have to be taken into
account, both in design and during operation. In entrained-flow gasifiers only the ash
properties are important.
The ash that is produced in gasifiers always has a lower density than the minerals from
which they originate, due to loss of water, decomposition of carbonates, and other
factors, and the presence of some carbon. The bulk density of the ash in particular may
be low due to the formation of hollow ash particles. This means that special attention
has to be given to the transport of such ashes. Slag is very different from ash as it has
11
been molten and is in fact a fusion-cast material similar to glass. Ideally, slag becomes
available as an inert, fine, gritty material with sharp edges due to the sudden
temperature drop upon contact with a water bath. Because Lumps of solid slag will form
during process upsets, a slag breaker is sometimes installed between the water bath
and the slag depressurizing system.
1.4.5.2 Coke
Coke is a material consisting essentially of the fixed carbon and the ash in the coal. It
was in the past a common fuel in water gas plants, but as it is more expensive than
coal, anthracite is now often the preferred fuel. It is virtually never used in gasification
plants. Coke plays a very important role in blast furnaces, which may be considered to
be very large gasifiers. One of the main reasons to use coke in blast furnaces is that it is
much stronger than coal.
1.5 Application Of Coal
1.5.1 Coal As Fuel
Coal is primarily used as a solid fuel to produce electricity and heat through combustion.
When coal is used for electricity generation, it is usually pulverized and then burned in a
furnace with a boiler. The furnace heat converts boiler water to steam, which is then
used to spin turbines which turn generators and create electricity.
Approximately 41% of the world electricity production uses coal. The total known
deposits recoverable by current technologies, including highly polluting, low energy
content types of coal (i.e., lignite, bituminous), is sufficient for many years. However,
consumption is increasing and maximal production could be reached within decades
1.5.2 Coking And Use Of Coke
Coke is a solid carbonaceous residue derived from low-ash, low-sulfur bituminous coal
from which the volatile constituents are driven off by baking in an oven without oxygen
at temperatures as high as 1,000 °C (1,832 °F) so that the fixed carbon and residual
ash are fused together. Metallurgical coke is used as a fuel and as a reducing agent in
smelting iron ore in a blast furnace. The product is too rich in dissolved carbon, and 12
must be treated further to make steel. The coke must be strong enough to resist the
weight of overburden in the blast furnace, which is why coking coal is so important in
making steel by the conventional route. However, the alternative route is to direct
reduced iron, where any carbonaceous fuel can be used to make sponge or pelletised
iron. Coke from coal is grey, hard, and porous and has a heating value of 24.8 million
Btu/ton (29.6 MJ/kg). Some coke making processes produce valuable by-products that
include coal tar, ammonia, light oils, and "coal gas".
1.5.3 Production Of Ethanol
Coal and natural gas are both abundant in nature and available at a very low cost
compared to other resources.
C (Coke) + CH4 (Natural Gas) C2H4 (Ethylene)
C2H4 + H2O C2H5OH (Ethanol)
Coke which represents about 80% of coal reacts with natural gas producing ethylene
gas. Ethylene Hydration provides ethanol. Product ethanol outweighs other liquid fuels
for its availability and low cost. The reaction itself is obvious, a simple addition reaction
where one mole of carbon reacts with one mole of methane gas producing one mole of
ethylene gas.
1.5.4 Gasification
Coal gasification can be used to produce syngas, a mixture of carbon monoxide (CO)
and hydrogen (H2) gas. This syngas can then be converted into transportation fuels like
gasoline and diesel through the Fischer-Tropsch process. Alternatively, the hydrogen
obtained from gasification can be used for various purposes such as powering a
hydrogen economy, making ammonia, or upgrading fossil fuels.
High prices of oil and natural gas are leading to increased interest in "BTU Conversion"
technologies such as gasification, methanation and liquefaction.
13
1.5.5 Liquefaction
Coal can also be converted into liquid fuels like gasoline or diesel by several different
processes. In the direct liquefaction processes, the coal is either hydrogenated or
carbonized. Alternatively, coal can be converted into a gas first, and then into a liquid,
by using the Fischer-Tropsch process.[2]
Figure 1: Coal production by province [3]
1.6 Coal Reserves In Pakistan
In Pakistan there are many reserves of coal. It’s time to explore coal and develop coal-
fired power plants to not only lessen dependence on imported fuel but also to cut the
cost of power production for the benefit of the industries, trade and domestic
14
consumers. The government should also consider the utilization of indigenous coal for
gasification, to produce high value petrochemicals, for which suitable technologies are
available in the world
Table 1-4: Pakistan's Coal Reserves [4]
Coal Resources (million tonnes)
Province/coal field
Measuredresources
Indicated resources Interred resources
Hypothetical resources
Total resources
Sindh
Lakhra 244 629 455 - 1,328
Sonda- thatta 60 511 2197 932 3,700
Jherruck 106 310 907 - 1,323
Others 82 303 1881 - 2266
Thar 3,407 10,323 81,725 80,051 175,506
Sub- total 3,898 12,076 87,165 80,983 184,123
Balochistan
Kohst-sharig-harnai 13 - 63 - 76
Sor-range/degari 15 - 19 16 50
Duki 14 11 25 - 50
Mach-abegum 09 - 14 - 23
Pirismailziarat 02 02 08 - 12
Chamalong 01 - 05 - 06
Sub-total 54 13 134 16 217
Punjab
Eastern salt range 21 16 02 145 235
Central salt range 29 - -
Makerwal 05 08 09
Sub-total 55 24 11 145 235
Grandtotal 4,008 12,113 87,189 81,144 184,575
15
Table 1-5: Composition Of Different Coal Fields [4]
Province/Coal Field
Coal Quality Proximate Analyses (in percent) Heating Value
(mmmf*)Btu/lb
Moisture Volatile Matter
Fixed Carbon
Ash TotalSulphur
Lakhra 9.7-38.1 18.3 38.6 9.8-38.2 4.3-49 1.2-14.8 5,503-9,158
Sonda-Thatta 22.6-48.0 16.1-36.9 8.9-31.6 2.7-52.0
0.2-15.0 8,878-13,555
Jherruk 9.0-39.520.0-44.2 15.0-
58.85.0-39.0
0.4-7.78,800-12,846
Ongar 5,219-11,172
Indus East 7,782-8,660
Meting-Jhumpir 26.6-36.6 25.2-34.0 24.1-32.2
8.2-16.8
2.9-5.1 7,734-8,612
Badin 11,415-11,521
Thar 29.6-55.5 23.1-36.6 14.2-34.0
2.9-11.5
0.4-2.9 6,244-11,054
Khost-Shahrig-Harnai
1.7-11.2 9.3-45.3 25.5-43.8
9.3-34.0
3.5-9.55 9,637-15,499
Sor Range-Deghari 3.9-18.9 20.7-37.5 41.0-50.8
4.9-17.2
0.6-5.5 11,245-13,900
Duki 3.5-11.5 32.0-50.0 28.0-42.0
5.0-38.0
4.0-6.0 10,131-14,164
Mach Abegum 7.1-12.0 34.2-43.0 32.4-41.5
9.6-20.3
3.2-7.4 11,110-12,937
Pir Ismail Ziarat 6.3-13.2 34.6-41.0 19.3-42.5
10.3-37.5
4.0-5.5 10,786-11,996
Chamalong-Bala Dhaka
1.1-2.9 24.9-43.5 19.4-478.1
9.1-36.5
3.0-8.5 12,500-14,357
Salt Range 3.2-10.8 21.5-38.8 25.7-44.8
12.3-44.2
2.6-10.7 9,472-15,801
Makarwal 2.8-6.0 31.5-48.1 34.9-44.9
6.4-30.8
2.8-6.3 10,688-14,029
16
Hangu/Orakzai 0.2-2.5 16.2-33.4 21.8-49.8
5.3-43.3
1.5-9.5 10,500-14,149
Cherat/GullaKhel 0.1-7.1 14.0-31.2 37.0-76.9
6.1-39.0
1.1-3.5 9,388-142,171
Kotli 0.2-6.0 5.1-32.0 26.3-69.5
3.3-50.0
0.3-4.8 7,336-12,338
*mmmf = moist mineral matter free
1.7 Application Of Pakistani Coal
1.7.1 Use Of Coal For Power Generation
Pakistan has abundant resource of lignite. Pakistan’s enormous deposits of lignite need
to be developed, because it is relatively cheap to mine and suitable for power
generation. Open-cut mines using Bucket Wheel Excavators are able to recover lignite
from the thick coal beds located in the Thar coalfield. This type of mining is very
common in Germany, Greece, Spain, Australia and India.
Lignite coal found in Thar in the province of Sindh has 50% moisture. SFBD (steam
fluidized bed drying) technology, now commercially developed, removes moisture from
coal by direct evaporation in a steam heated exchanger, and produces dry coal with
very little moisture. Another technology for power generation from lignite coal is
Circulating Fluidized Bed (CFB) which is also very effective. In CFB technology, coal
mixed with limestone is burned in a fluidized bed. The sulfur in the coal is absorbed by
the calcium carbonate, and the emission is free from sulfur dioxide. Pakistan has very
large deposits of limestone in all its provinces. The Integrated Gasification and
Combined Cycle (IGCC), which increases the efficiency and reduces the emission level
of the power generation plant, is a recent advanced technology applicable to high
moisture lignite coal for power generation.
1.7.2 Use Of Coal As An Industrial Fuel
The importance of coal as an industrial fuel and its role in a wide range of industrial
applications is also well known to the industry. It is a cheaper fuel. In some industrial
applications, such as brick kilns and glass tanks, the high emission of the coal flame is a
17
distinct advantage. In brick kilns, for example, it has been found that one tone of coal
will do the same work as one tone of oil. Coal is used as boiler fuel for the supply of
Steam to process plant in the paper, chemical, and food processing industries. It is used
for direct firing in the manufacture of cement, bricks, pipes, glass tanks, and metal
smelting.
1.7.3 Brick Kilns
Presently, coal is commonly used for making bricks and roofing tiles, as it is an ideal
fuel for kilns, especially for heavy clay products. In Pakistan, about 50% of coal
production is used in the brick kiln industry. Therefore, a large market for indigenous
coal is available in Pakistan for interested private investors.
1.7.4 Cement Production
In many countries, coal is used as fuel in the cement industry. Previously, coal was not
used as fuel in cement plants in Pakistan, but now the cement industry has started
using indigenous coal. The Government of Pakistan is now conducting a feasibility
study to convert gas-based and oil-based cement plants to run on indigenous coal. It is
expected that, in future more and more cement plants will be using indigenous coal as
fuel. This constitutes another market for indigenous coal for private investors.
1.7.5 Coal Briquettes
Yet another industrial use of coal is in the form of smokeless coal briquettes which can
be used as domestic fuel, and would have special application in reducing deforestation
in the Northern Areas of Pakistan. Pakistan’s Fuel Research Centre has developed
smokeless coal briquette of good quality in its pilot plant at Karachi.
1.7.6 Coal Gasification
Electricity generation in Pakistan is severely affected by rapidly escalating gas and oil
prices in the world. IGCC power plants have the potential of being economically
competitive by using gas produced from indigenous coal. Furthermore, catalytic coal
18
gasification is developed as a more efficient and less costly process to produce gas
from coal. Methanol or synthetic gas can be produced from Thar coal at the coalfield
and can easily be transported by pipeline throughout the demand centres.
1.7.7 Underground Coal Gasification
A technology is also available for insitu conversion of coal into gas, which can be used
for power generation or for conversion into higher value products such as diesel fuel,
methanol, and ammonia. Underground coal gasification can be applied to both
horizontal and inclined coal beds. Coal not recoverable by conventional mining
methods, can be accessed for insitu coal gasification. Private investors can use this
new technology where coal beds are thin and steeply dipping, and not economical for
mining by conventional mining methods [5]
19
2 Coal Gasification
Gasification is a process that converts organic or fossil based carbonaceous materials
into carbon monoxide, hydrogen, carbon dioxide and methane. This is achieved by
reacting the material at high temperatures (>700°C), without combustion, with a
controlled amount of oxygen and/or steam. The resulting gas mixture is called syngas
(from synthesis gas or synthetic gas) or producer gas and is itself a fuel. The power
derived from gasification of biomass and combustion of the resultant gas is considered
to be a source of renewable energy, the gasification of fossil fuel derived materials such
as plastic is not considered to be renewable energy.
Gasification is the most versatile of the coal conversion processes having applications
in almost every sector of energy demand. In industrial installations and power
generation systems, for example, a low calorific value gas or a medium calorific value
gas may be used. A medium calorific value gas may also be converted into liquid fuels
or chemicals and in this case is often referred to as synthesis gas. Finally, a substitute
natural gas; high calorific value gas can be manufactured as a direct replacement for
natural gas.
The composition of the gas obtained from a gasifier depends on a number of
parameters such as:
1. Fuel composition
2. Gasifying medium
3. Operating pressure
20
4. Temperature
5. Moisture content of the fuels
6. Mode of bringing the reactants into contact inside the gasifier etc.
2.1 Chemical Reactions
Many chemical reactions may occur in a gasifier, the three main types being
1. Pyrolysis reactions2. Gasification reactions3. Acceptor reactions
The importance of each type of reaction and the extent of the interactions between them
depend on the gasifier design. [5]
2.1.1 Pyrolysis Reactions
As coal is heated it decomposes into a char, residue consisting mainly of carbon and gases including hydrogen, methane, stream, carbon dioxide, carbon mono oxide and tar vapors. This process was the basis for the traditional methods of coal gas manufacture of liquid fuels from coal.
If suitable conditions exist in the gasifier, the gases produced by pyrolysis will form part of the product gas.
2.1.2 Gasification Reactions
Combustion gases can be produced by the reaction of the coal, char or volatile matter
with oxygen, carbon dioxide, hydrogen or stream. The main reactions are listed below
(for simplicity, only reactions with carbon are shown).
Partial combustion reaction:
. C + ½ O2 CO
Boudouard reaction:
C+CO2 2CO
21
Hydro gasification reaction:
C + 2H2 CH4
Water gas reaction:
C + H2O CO + H2
In regions of the gasifier where oxygen is in excess, combustion may also take place.
Combustion reaction [3]:
C+O2 CO2
Shift reaction:
CO + H2O CO2 + H2
Methanation reaction:
CO + 3H2 CH4 + H2O
2.1.3 Acceptor Reactions
In some gasifiers, limestone or dolomite may be used to retain the sulphur. If the
acceptor is calcined before feeding to the gasifier, carbon dioxide may also be retained.
The reactions for calcined limestone are given below.
Sulphur retention:
CaO + H2S CaS + H2O
Carbon dioxide acceptor:
CaO + CO2 CaCO3
22
Reaction of sulphur is also possible using dolomite or unclaimed limestone
2.1.4 Heats of Reactions
An important factor affecting the choice of reactants and gasifier operating conditions is
the heat released or absorbed by the above reactions. In a gasifier the net heat release
has to be just sufficient to bring the reactants to the design operating temperature. Heat
therefore has to be supplied to supply to meet the sensible heat requirements and those
for the endothermic boudouard and water gas reactions.
In a gasifier the net heat release has to be just sufficient to bring the reactants to the
design operating temperature. Heat transfer has to be supplied to meet the sensible
heat requirements and those for the endothermic boudouard and waste gas
reactions .The most designs that is achieved by the combustion and partial combustion
reactions although systems using the methnation reaction, the carbon dioxide acceptor
reaction or an external heat source are also under consideration.
2.1.5 Equilibrium Considerations
An indication of the effect of the temperature and pressure conditions in a gasifier on
the product gas composition may be obtained by considering the theoretical
composition if the reactions were allowed sufficient time to reach equilibrium. In the
presence of an excess of carbon, the equilibrium for the combustion and partial
combustion reactions correspond to extremely low oxygen concentrations and for
practical purposes it may be assumed that the oxygen content of the product gas is zero
for most gasifiers.
2.1.6 Reaction Kinetics
The time taken for some of the above reactions to reach equilibrium can; however be
considerable and the design of gasifier has to take into account the speed of the
reactions. For gas solid reactions (including all the main gasification reactions) the
reaction time is, in general, determined by two processes either of which may be rate
controlling. These are the diffusion of the gaseous reactants and products to and from
the particle surface and the chemical reactions at the particle surface. In practice,
23
diffusion is a comparatively rapid process and conditions under which diffusion
becomes rate controlling in general provide reaction rates that are high from the view
point of gasifier design.
For gas phase reactions, such as shift and methanation, chemical reaction rates are
generally controlling unless the reactions are promoted by a solid catalyst [6]
2.2 Gasifier Types
Gasification processes are classified on the basis of the method used to bring the coal
into contact with the gasifying medium (air or oxygen). The three principal commercial
modes are
1. fixed-bed,
2. fluidized-bed, and
3. entrained-flow
2.2.1 Fixed-Bed Gasifier
In a fixed-bed gasifier, 1/4- 2-in. coal is supplied countercurrent to the gasifying
medium. Coal moves slowly down (sometimes this type of gasifier is called a moving-
bed gasifier).Reaction zones typically consist of drying, devolatilization, reduction,
combustion, and ash zones. In the drying and devolatilization zone, located at the top of
the gasifier, the entering coal is heated and dried and devolatilization occurs. In the
reduction / gasification zone, the devolatilized coal is gasified by reactions with steam
and carbon dioxide. Heat exchanged with the entering gasifying medium and fuel. As a
result both the ash and the product gas leave at modest temperature. Fixed-bed
gasifiers operating on low-rank coals have exit temperatures lower than 800◦F.Low
oxidant requirements. Design modifications required for handling caking coal. Limited
ability to handle fines
24
Figure 2: Moving bed gasefier
(400-1100 0C, 10 to 100 bar) [7]
2.2.2 Fluidized-Bed Gasifier
In this gasifier, coal with 1/8-¼ in. in size enters the side of the reactor and is kept
suspended by the gasifying medium. Similar to a fluidized-bed combustor, mixing and
heat transfer are rapid, resulting in uniform composition and temperature throughout the
bed. The temperature is sustained below the ash fusion temperature to avoid clinker
formation. Char particles entrained in the product gas are recovered and recycled back
into the gasifier via a cyclone. Acceptance of a wide range of solid feedstock (including
solid waste, wood, and high ash content coals) It has Uniform temperature. Oxygen and
steam requirements are moderate and extensive char recycling.
25
Figure 3: Fluidized bed gasefier [7]
(800 – 10500c, 10 to 2 bar)
2.2.3 Entrained-Flow Gasifier
Entrained-flow systems gasify pulverized fuel particles suspended in a stream of oxygen
(or air) and steam. Residence time in this type of gasifier is very short. This gasifier
generally uses oxygen as the oxidant and operates at high temperatures. In this
gasefier. Temperature is well above ash-slagging conditions, to ensure high carbon
conversion. Ash in the coal melts at the high operating temperature of the gasifier and is
removed as liquid slag. The product gas and slag exit close to the reaction temperature.
Entrained-flow gasifiers have the following characteristics:
1. Ability to gasify all coals regardless of coal rank, caking characteristics, or
amount of coal fines,
2. Feed stocks with lower ash contents are favored.
3. Uniform temperatures.
4. Very short fuel residence times in the gasifier;
5. Very finely sized and homogenous solid fuel required;
6. Relatively large oxidant requirements;
26
7. High-temperature slagging operation
8. Entrainment of some molten slag in the raw gas
9. Their use for biomass gasification is rather limited, as it requires the fuel particles
to be very fine (in the order of 80 to 100 μm).
10.A number of manufacturers offers commercial entrained bed gasifiers for large-
scale applications, such as Texaco, Shell, and Koppers–Totzek.
Figure 4: Entrained flow gasifier [7]
(1200-16000c, 25 to 80 bar)
27
2.3 Commercial Gasifiers
The commercially available gasifiers are four types:
1. The Lurgi Gasifier
2. Fixed Bed Producers
3. The Koppers-Totzek Gasifier
4. The Winkler Gasifier
2.3.1 The Lurgi Gasifier
The Lurgi is a fixed bed gasifier and is the only gasifier in commercial use operating at
elevated pressure. Coal is fed to the top of the gasifier through lock-hoppers to
overcome the pressure differential. The coal moves downwards passing through a
carbonization zone to a gasification and combustion zone where steam and oxygen are
injected. The temperature of the gasification zone is about 1000oC.
2.3.2 Fixed-Bed Gasifier
In their simplest form these gasifiers consist of a fixed bed of coke through which air
and steam are blown. Fresh coke is fed to the top of the bed and ash is removed via a
grate at the bottom. The temperature is controlled by the addition of steam to avoid ash
slagging. From the early designs used in gasworks for producer gas manufacture, a
number of commercial systems suitable for industrial applications have been developed.
All of these processes operate under non-slagging conditions (with gasification
temperature of about 1000oC) and use air and steam as the gasifying agents although
the processes can be modified to operate using oxygen and stream. The throughputs
are relatively low, being typically only 10 to 20% of those for the Winkler, Lurgi and
Koppers-Totzek gasifiers.
2.3.3 The Koppers-TotzekGasifier
The Koppers-Totzek gasifier is an entrained phase system operating at atmospheric
pressure. Coal, pulverized to a maximum size of 0.1mm is injected with steam and
oxygen into a horizontal-lined, cylindrical reaction chamber. Usually two burners (one at
each end) are used although a four-burner design is now available the coal is gasified at
28
high temperatures (1500-1800oC) in a flame similar to that of a pulverized fuel
combustion furnace. The hot gas leaves the reactor via water cooled, vertical duct.
About half of the ash is entrained in the gas stream as particles of slag that cool and
resolidify by radiation to the vessel walls. The remainder of the ash is removed as slag
from the bottom of the reactor into a water quench bath. The gasifier can handle most
ranks of coal including lignite and strongly caking coals.
2.3.4 The Winkler Gasifier
This is a fluidized bed gasifier that operates at atmospheric pressure. It was originally
designed to use lignite but bituminous coal, although less reactive, can also be used.
The feed material is crushed to a maximum size of 10mm and is delivered to near the
top of the bed by a screw feeder. The bed is fluidized with steam and oxygen (or air)
and ash is removed from the bottom of the bed. The temperature of the bed is
maintained at 800-900 oC to avoid sintering of the ash. However, at this temperature the
gasification reactions proceed slowly and it is necessary to inject additional steam and
oxygen (or air) above the bed. The reactions above the bed increase the gas
temperature to more than 1000C and the ash is therefore cooled to below the
resolidification point by radiative heat transfer to a boiler before leaving the reactor. Ash
and unconverted carbon are removed from the gas stream by cyclones.
2.4 Process selection
We selected the fluidized bed gasifier for the following reasons
1. High rates of heat and mass transfer and efficient gas solid contacting.
2. Temperature control.
3. Good mixing.
4. Effective use of catalyst fuel flexibility including opportunities for co-feeding.
5. Continuous addition, removal, circulation of solids for catalyst capture and
regeneration, circulation of sorbents.
29
2.4.1 Raw Materials
Following are the raw materials used in the manufacturing of syngas from coal:
1. Coal
2. Superheated Steam
3. Pure Oxygen
4. Selexol
5. Process Water
6. Catalyst
2.4.2 Steps Involved
The major steps involved in the formation of syn gas from coal are:
1. Coal Feeding
2. Gasification
3. Gas Cooling
4. Gas Purification
2.4.3 Process Equipment’s
The major equipment’s used are as follows:
1. Rotary Dryer
2. Fluidized Bed Gasifier (Winkler)
3. Heat Exchanger
4. Cyclone Separator
5. Scrubber
6. Absorption Column
7. Compressors
30
2.4.4 Process Description
Coal Feeding
Coal from crusher and breaker is fed to the screening system. Here the 1/8 in (3mm)
particle size material is separated and fed to the gasifiers.
Gasification (Winkler Type)
We have selected Winkler type gasifier because it can operate at 1 atm pressure. The
Winkler process is operable with practically any fuel. Commercial plants have operated
on brown coal coke, as well as on sub-bituminous and bituminous coals. Coal
preparation requires milling to a particle size below 10 mm but does not require drying if
the moisture content is below 10%. The feed is conveyed into the gasifier or generator
by a screw conveyor. The fluid bed is maintained by the blast, which enters the reactor
via a conical grate area at the base. An additional amount of blast is fed in above the
bed to assist gasification of small, entrained coal particles. This also raises the
temperature above that of the bed itself, thus reducing the tar content of the syngas.
The reactor itself is refractory lined. Operation temperature is maintained below the ash
melting point. Most commercial plants have operated between 815 and 980°C. At
maximum load the gas velocity in a Winkler generator is about 5m/s. The flow sheet
incorporates a radiant waste heat boiler and a cyclone to remove the ash. The ash
contains a considerable amount of un reacted carbon— over 20% loss on feed.
Oxygen Supply
Oxygen required for the gasification of coal is produced in an air separation plant and
then compressed to coal gasifier pressure.
Steam Supply
Superheated steam for the process is supplied.
31
Gas Cooling
The crude gas leaving the gasifier immediately enters a heat exchanger and waste heat
boiler to generate low to medium pressure steam.
Cyclone Separator
A cyclone separator removes most of the entrained fly ash and dust. About 85% of
solids are removed in this unit. It is a reverse flow cyclone. In a reverse flow cyclone the
gas enters the top chamber tangentially and spirals down to the apex of the conical
section; it then moves upward in a second, smaller diameter, spiral, and exits at the top
through a central vertical pipe. The solids move radially to the walls, slide down the
walls, and are collected at the bottom.
Absorption Column
Gas from coal gasification contains a large amount of CO2 and H2 S, organic sulfur, and
other impurities. These impurities can be removed by using selexol as a solvent.
Selexol. . It uses dimethyl ethers of polyethylene glycol (DMPEG). The typical operating
temperature range is 0–40 oC. The ability to operate in this temperature range offers
substantially reduced costs by eliminating or minimizing refrigeration duty. On the other
hand, for a chemical application such as ammonia, the residual sulfur in the treated gas
may be 1 ppmv H2S and COS each (Kubek et al. 2002) which is still more than the
synthesis catalysts can tolerate. This is not an issue, however, in power applications
where the sulfur slip is less critical.
The ratio of absorption coefficients for H2S, CO2 is about 1:9 in descending order of
solubility
2.4.5 Catalyst Selected
Catalyst selected was iron with potassium oxide and molybdenum as promoters.
Reasons for selection are as follows:
32
1. Iron catalyst is cheap as compared to others. Although cobalt has very good
selectivity but it is 230 times more expensive than iron
2. Shelf life of iron catalyst is more.
3. It is easily available in market [8]
2.5 Fluidized Bed Gasifier Design
A wide variety of gasifier designs has been developed for different applications and
types of coal feedstock. The four main design parameters are given below:
1. Temperature
Gasifiers can be divided into three categories depending on the physical state of the
ash in the gasification reactor.
a) Dry Ash
For most coals, operation at up to approximately 1000oC enables the ash to be removed
“dry” without sintering or slagging.
b) Ash-Agglomerating
It is also possible to operate at temperatures such that the ash particles become ‘sticky’,
from agglomerates and, with an appropriate reactor design, are removed at a controlled
rate to maintain steady-state operating conditions in the gasifier. For most coals, ash-
agglomerating conditions occur in the temperature range 1000 to 1200C, depending on
the composition of the ash.
c) Slagging
Alternatively, operation above about 1200 0C results in the ash forming a molten slag. If
steam is used as a gasifying agent under non slagging conditions it may be necessary
to use a considerable excess over that which reacts with the coal. Gasifier throughputs
are generally higher under slagging conditions because the increased reaction rates
permit shorter gas and solids residence times and a higher conversion of the reactant
33
gases to product gas. In particular, the higher steam conversion obtained under
slagging conditions can lead to a significant improvement in throughput. For operations
at slagging temperatures the reaction kinetics are fast and differences in coal are less
important than that non slagging temperatures. The ash type should be such that a
sufficiently mobile slag is obtained at the operating temperature. In particular, ashes
with a higher fusion temperature are generally unfavorable for slagging operation.
2. Pressure
Gasification process may be operated either at atmospheric pressure or at elevated
pressure. Equilibrium considerations indicate that operation at elevated pressure tends
to discourage the decomposition of carbon dioxide and steam and the formation of
carbon mono oxide and hydrogen.
At higher pressures the formation of methane by the hydro gasification reaction is
favored by equilibrium considerations. Pressure of at least 80bar is generally regarded
as necessary for hydro gasification based processes. Many of the downstream units
operate at elevated pressure, usually in the range 10 to 30 bar. In general there are
therefore two process design options; either the reactants are compressed and the
gasifier operated at elevated pressure or the gasifier is operated at atmospheric
pressure and the product gas compressed for further processing. The advantages for
the process efficiency and throughput are generally are regarded as favoring
pressurized operation in large scale applications. For this reason most of the current
development effort on coal gasification is being directed towards elevated pressure
systems.
3. Reactant Gases
The three basic reactants for gasification process are oxygen, steam and hydrogen.
These can be used in a number of ways in practical schemes:
34
Oxygen/steam
In gasifiers using oxygen and steam the heat absorbed by the endothermic water gas
reaction is provided by the combustion reactions between oxygen and coal giving an
overall heat balance within the gasifier
Air/steam
For applications in which the presence of nitrogen in the product gas is not a
disadvantage, air can be used instead of oxygen thereby saving air separation costs. In
this case the stream requirements are lower because more sensible heat is needed to
bring the air to the reaction temperature.
Air
At slagging temperatures it is possible to satisfy the heat balance requirements using air
alone as the gasifying agent, the heat released by the combustion reactions being
balanced entirely by the sensible heat required to bring the air to reaction temperature.
Steam may, however, be required in small quantities for control purposes to maintain a
heat balance if the air is preheated or if oxygen enriched air is used. Under non slagging
conditions air may be used alone if heat is removed from the process by other than the
endothermic stream carbon reactions.
Steam
The capital and operating costs of air separation plant are substantial and this factor
has encouraged interest in processes that produce a nitrogen free gas using steam
alone. In this case the heat absorbed by the water gas reaction has to be provided by a
method other than oxidation in the gasifier [5]
35
2.6 Factors Affecting Reaction Rates
The main factors affecting the reaction rates are as follows.
2.6.1 Temperature
An increase in temperature generally results in an increase in the reaction rate, the
increase being greater for chemical reaction rate controlled processes than for diffusion
rate controlled processes. Typically, a temperature increase of 10 C doubles the rate for
a chemical reaction rate controlled process but a temperature increase of several
hundred degrees is required to double the rate for a diffusion rate control process.
2.6.2 Pressure
The gas solid reaction occurring in a gasifier can be regarded approximately as first
order chemical reactions so that an increase in the operating pressure results in a
proportional increase in the chemical rate constant. The gas phase reactions are
generally second order (or higher) and the chemical reaction rate therefore increases
substantially with pressure in this case. Diffusion rate controlled processes are little
affected by pressure.
2.6.3 Coal Properties
Both chemical reaction rates and diffusion rates are dependent on the properties of the
solid materials. The absolute value of the chemical reaction rate can vary greatly
depending on the reactivity of the material. For example, in the case of the water gas
reaction, char produced under different carbonizing conditions can have reaction rates
differing by an order of magnitude or more at the same temperature and pressure.
Diffusion rates vary less, being affected mainly by the particle surface area, pore
structure and thickness of the boundary layer across which mass transport occurs. High
diffusion rates are favored by fine particles and turbulent gas solid mixing.
2.6.4 Types of Reactions
The chemical reaction rates for the combustion and pyrolysis reactions are extremely
high, being several orders of magnitude higher than those for the next fastest reactions.
36
The conversion of carbon dioxide to carbon mono oxide by the Boudouard reaction is
somewhat slower still (typically by half an order magnitude) with the hydro gasification
and methanation reactions being slower than the Boudouard reaction by about a further
two orders of magnitude.
The diffusion rates very comparatively little with the type of reactants. The main factor is
the molecular weight, hydrogen diffusion quicker than the other species. In practice, for
gasification processes using oxygen or air, the oxygen is consumed rapidly at the
beginning of the reaction zone and other reactions occur more slowly as the resulting
gases pas through remainder of the reactor .Both the combustion and partial
combustion reactions can occur at the surface of the coal particles.
The term “pyrolysis” covers a variety of reactions that may be either chemical rate
controlled or transitional at non slagging temperatures. At slagging temperatures,
pyrolysis reactions are generally diffusion rate controlled and are comparatively fast.
The other reactions- Boudouard, hydro gasification, water-gas, shift and methanation-
are generally chemical rate controlled under non slagging conditions [5]
2.7 Method of Contacting
Methods of contacting the solid feed and the gaseous reactants in a gasifier can be
considered in four categories.
2.7.1 Fixed bed
Coal is fed to the top of a bed and is heated as it moves downwards by the upward flow
of the hot gases. The coal passes through a carbonization zone and then gasification
zone, finally reaching a combustion zone at the bottom of the bed where the reactant
gases are injected. The system is illustrated by figure:
37
Fixed Bed Gasifier
Fluidized Bed Gasefier
In fluidized bed gasifiers the reactant gases are used to fluidize a bed of particulate
material containing the coal. The bed can be regarded as being well mixed in order to
avoid sintering of the ash and the consequent loss of fluidization, fluidized bed gasifiers
are restricted to operating at non-slagging temperatures. Fluidized bed gasification is
illustrated in figure.
Fluidized bed Gasifier
38
2.7.2 Molten Bath
Molten bath gasifiers are similar to fluidized bed systems in that the reactions take place
in a well-mixed medium of high inertia. In this case, however, a bath of molten slag,
metal or salt is used. The operating temperature depends on the type of bath; for slag or
molten metal baths, a high temperature (1400-1700 oC) is necessary but temperatures
as low as 1000 C can be used with molten salts. The reactant gases may be injected
from above as jets which penetrate the surface of the bath or may be fed to the bottom
of the bath. In either case a good gas-solid contacting is obtained.
2.7.3 Entrained Phase
In an entrained phase gasifier coal pulverised to less than 0.1 mm is injected with the
reactant gases into a chamber where the gasification reactions take place in a flame
similar to that of a pulverised fuel combustion system. This approach is used in the
commercial Koppers-Totzek process.
It appears that a non-slagging operation in an entrained phase gasifier is attractive only
for hydro-gasification processes where partial conversion of the coal is acceptable
39
ROTARY DRYER
3 Material Balance
3.1 Material Balance on Dryer
Feed (coal)
F0 = 1000 kg/hr. Solids= 0.7
H2O = 0.3
Basis: 1000 kg/hr. of feed
Because efficiency of dryer is 80 %. So water in F2 is 6%
Overall balance
F0 = W + F1
Solids balance
IN = OUT
700 = 0.94×F1
F1 = 744.68 kg / hr.
40
Product
F1 = ?
Solids = 0.94
H2O = 0.06
Moist remove
H2O = 1
W =?
H2O balance
IN = OUT
300 = W + 44.68085106
W = 255.3191489 kg/hr.
Table 3-6: Summary of Material Balance on Dryer
F0 W F1
Solids 70% 0 94%
H2O 30% 100% 6%
kg/hr. 1000 255.3191 744.6809
41
3.2 Material Balance on Fluidized Bed Gasifier
F1 = coal feed
F2 = O2
F3 = syn gas out
F4 = steam
Thar coal composition (dry basis)
XC = 0.621
XH2 = 0.069
XN2 = 0.003
42
F1
F2
F4
F3
GASIFIER
XO2 = 0.28
XS = 0.002
Ash = 0.025 [B-3]
THAR COALCOMPOSOTION (WET BASIS)
XC = 0.58374
XH2 = 0.06486
XN2 = 0.00282
XO2 = 0.2632
XS = 0.00188
Ash = 0.025 × .94
Mass flow rate of Coal = F1 = 744.68 kg/hr.
Cp(carbon) = 0.709 KJ/kgK
Cp(H2)=14.304 KJ/kgK
Cp(N2)=1.04 KJ/kgK
Cp(O2) =0.918KJ/kgK
Cp(S) =0.71KJ/kgK
Cp(gas) =2.728 KJ/kgK [9]
Syn gas composition =F3=?
43
XCO = ?
XH2 = ?
XH2S = ?
XN2 = ?
Basis: 1000 Kg/hr.
Molecular Weights
C 12
H2 2.016
N2 28
S 32
O2 32
CO 2
Reaction
3C + H2O +O2→3CO+H2
Let suppose the conversion of the reaction is B=80% in the gasifier.
Carbon moles in feed
K moles of carbon in feed = F1×XC/MC= 36.22496 k moles
Steam Moles in Feed
3 k moles of carbon react with = 1 k mole steam
1 k mole carbon react with = 1/3 k moles of steam
44
1 k mole of carbon react with = 0.333 k moles of steam
36.225 k moles of carbon react with = 36.225×0.33 k moles of steam
36.225 k moles of carbon react with = 12.06291 k moles of steam
So, 217.1324 kg/hr. of steam is required.
H 2O Available = 44.64 kg/hr.
Actual required= required H 2O - available H 2O
Actual Required H2O= F4=172.4924 kg/hr
Oxygen Moles in Feed
3 moles of carbon react with = 1 k mole of oxygen
1 k mole carbon react with = 1/3 k moles of oxygen
1 k mole of carbon react with = 0.333 moles of oxygen
36.225 k moles of carbon react with = 36.225×0.33 k moles of oxygen
36.225 k moles of carbon react with = 12.06291 k moles of oxygen
So, 386.0132 kg/hr is required.
Oxygen available = 196 kg/hr
Actual required = required oxygen - available oxygen
Actual Required Oxygen=F2= 190.0134 kg/hr
Carbon Balance
F1×XC/MC=n CO
36.225=n CO eq no 1
45
Sulfur Balance
F1×XS/MS=nH2S
nH2S= 0.04374995 k moles
Hydrogen Balance
F1×XH/MH+F4+nH2S=nH2
nH2=36.06496712 k moles
Nitrogen Balance
F1×XN2/MN2=nN2
nN2= 0.074999914 k moles
Table 3-7: Summary Of Material Balance On Gasefier
Stream Mass In (kg /hr) Mass Out (kg/hr)
F1 744.68 ----
F2 190.013
F3 ----- 1107.185
F4 172.492
Total 1107.185 1107.185
46
Gasses Leaving Gasifier K mole/hr
nCO 36.225
nH2 36.06496712
nH2S 0.04374995
nN2 0.074999914
Total moles 72.40871698
Mole fractions gases Fractions
XCO 0.500285069
XH2 0.498074937
XH2S 0.000604208
XN2 0.001035786
Total 1
47
Gasses Leaving Gasifier Kg/Hr
mCO 1014.3
mH2 72.12993424
mH2S 1.4874983
mN2 2.099997592
Total Mass 1090.01743
Gas Mole fraction Mole wt Contribution
(kg/k mole)
X CO 0.500285069 28 28 14.00798194
XH2 0.498074937 2.016 1.004119072
XH2S 0.000604208 34.016 0.020552751
XN2 0.001035786 28 0.029002
Mole wt gas 15.06165577
48
3.3 Material Balance on Cyclone Separator
Inlet composition (outlet of gasifier=F5=1090.01743 kg/hr
= 72.37014613 k mole/hr
Solids= S1 = 30kg/hr (assumed) [10]
Solids outlet=S3 =?
Solids separated= S2 =?
Gas entering cyclone separator= F5 = F3 = 1090.01743 kg/hr
Solids particles entering into cyclone= S1=30 kg/hr
Efficiency of cyclone separator for removal of particles larger than 10µm= 80%= 0.8
Kg of solids cyclone removed=S2=S1×Efficiency= 24 kg/hr
49
Kg of solids Remain in gas =S3 = S1-S2= 6 kg/hr
Flow rate of gas exiting separator= 1066.01743 kg/hr
Table 3-8: Summery Of Material Balance On cyclone separator
Material Flow Rate(Kg/hr)
solids removed S2 24
Gases leaving cyclone
separator F8
1066.017
solids in gas stream S3 6
50
3.4 Material Balance on Scrubber
Scrubber inlet (outlet of cyclone separator) = G1= 69.67015 kmole/hr
Syn gas composition=YI Syn g=1-XCO2= 0.98
Y1 CO2at inlet = 0.02
Kg of solids entering=S=6 kg/hr
Kg of water entering=L1=?
K mole of gases exiting =G2=?
Kg of water leaving=L2=?
CO2 in leaving liquid=?
Assuming equilibrium condition
At 760 mm hg and 25 degrees centigrade 100 kg H2O absorbs 1.5 kg CO2
Equilibrium partial of CO2 and H2O
51
PH2O= 10 mm hg
P CO2= 12 mm hg
P (atm) = 760 mm hg
So the composition of exiting gas (G2)
Y2 CO2=P CO2 / P (atm)
= 0.015789474
X2 H2O = 0.013157895
Syn gas composition =y2 Syn gas=1-Y CO2
= 0.984210526
Syn gas balance
Gas in = gas out
G1*YI Syng= Y2Syng×G2
G2=G1×Y1syng / Y2syng
= 69.37209588 k mole/hr
Composition of H2O and CO2 in liquid leaving L2 at equilibrium
1.5 kgCO2 / 100kg H2O
YCO2= 0.014778325
XH2O= 0.985221675
CO2 Balance
Molecular WT of CO2= 44 kg/k mole
G1×Y1CO2×MCO2= G2×Y2CO2×MCO2+XCO2×L2
52
L2= [(G1×Y1CO2×MCO2)-(Y2CO2×G2×MCO2)]/YCO2
L2= 887.4064596 kg/hr
Water balance
L1=G2×X2H2O+L2×XH20
L1=875.2048692 kg/hr
Solid balance
All solid will be removed in the scrubber
Solid enter=solid leave
Solid leave with liquid = solid at the exit of cyclone separator
= 6 kg
Table 3-9: Summery Of Material Balance On Scrubber
Stream name Mass in(kg) Mass out(kg)
Syn gas 1065.9533 1061.3931
Liquid 875.20487 887.40646
CO2 21.3 19.052
CO 1014.3 1014.3
H2 72.13 72.13
H2S 1.4875 1.4875
N2 2.099 2.099
53
3.5 Material Balance on Absorber
Mass flow rate of gas in, Gin or mass flow rate out of scrubber = 1061.3931kg /hr
H2S in gas from previous data = 1.4874983 kg/hr
H2S in gas from previous data in moles = 0.04375 kmol/hr
Suppose the percentage of H2S gas removed from gas = 90%
H2S removed = 0.9×H2S in gas =1.33874847 kg/hr
Mass flow rate of gas out =G0= Gin – H2S removed =1060.05435kg/hr
54
To find out flow rate of selexol, we have to apply energy balance around H2S absorber
for gas
Cp of gas = 2.05 kJ/kg0C [11]
Temperature of gas in = 210.3107 k
Temperature of gas out = 250.3107k
Using the relation Q = GO× Cp × ∆T
Q = 24.14568245 KW
For selexol
Cp of selexol= 2.0 KJ/Kg
Temperature of selexol in = T in = 298.15 K
Temperature of selexol out = Tout = 258
Using the relation Q=F (m)×Cp×∆T
Solving above equation for F (m)
SO, mass flow rate of selexol in, F (m) = Fin = Q/Cp ∆T
=-0.294459542 kg/s
SO, mass flow rate of selexol in (m) = Fin =-1060.054352 kg/hr
Mass flow rate of selexol out=Fout= -1061.3931kg/hr
Negative sign shows that energy is being transferred from selexol to gas. selexol is
getting Cool. It does not represent negative magnitude of masses or flow rate.
55
Table 3-10: Summery Of Material Balance on Scrubber
Stream Mass in(kg/hr) Mass out(kg/hr)
Syn Gas G 1061.3931 1060.05435
Selexol 1060.05 1061.39
H2S 1.4874983 1.33874847
56
4 Energy Balance
4.1 Energy Balance on Heat Exchanger
Shell and tube type
Syn gas in =F3=1090.01743 kg/hr
Temperature of syn gas=T1=1100 k
Syn gas outlet =F5=1090.017 kg/hr
Temperature of syn gas outlet=T2=363 k
Flow rate of cooling water=F6=?
Temperature of cooling water=T3=298 k
Flow rate of steam outlet=F7=?
Temperature of steam outlet=T4=?
57
Using formula
Q = m cp ∆t
CP gas = 2.75509 kJ/kg oC
CP H2O = 4.625 kJ/kg oC
For gas,
Q gas= m gas×cp gas×∆t gas
Q gas=614.8005115kw (divided by 3600 for conversion in sec)
As,
Energy given by gas = Energy gained by water
Assuming 70% heat transfer,
Q gas=430.360358KW
As temperature difference between in and out of gas is = 1200-363=837k.
Efficiency of exchanger is 70% means 70%of energy will be transferred to water. So
rise In Temperature of water will also be 70% of the temperature difference, i.e. 70% of
(1200-363).
Rise in temp of water=T rise=585.9 k for 70% efficiency
Temp of water out =T4=883.9k
Flow of water in=F6=?
Latent heat=λs=1569.15 kJ/kg oC [12]
Heat given by gas=heat gained by water
Q gained by water =Q gas
58
QH2O= [m cp (t4-t3)] +λs
Or
m=QH2O/ [(cp*(t4-t3)) + λs]
For 100% efficiency of exchanger
F6 (m) =517.2503317 kg/hr (multiplied by 3600 for kg/hr)
F6=F7= 517.2503 kg/hr
Heat loss
Heat in - heat out =184.44 KW
59
4.2 Energy Balance On Dryer
Feed (coal)
F0 = 1000kg/hr
T0 = 298K
P0 = 14.7 psi
Air
A(air)= ?
T1 = 328K
Basis: 1000 kg/hr of feed
Calorific value of coal in F0= 29396 KJ/kg
Calorific value of coal in F1= 25227 KJ/kg
Specific heat of air at T1= Cp1= 29.14 kJ/k mol – K= 1 kJ/kg-K
Specific heat of air at T2 =C pA= 29.08kJ/k mol-K = 1 kJ/kg-K
Specific heat of water at T2=C pw= 4.169 kJ/kg-K
60
Product
F1 = 744.68kg / hr
T3 = 303K
Air + Moist
air + moist = 255 kg/hr
T2= 317 K
DRYER
Reference temperature =TR= 298 K
Heat In
Heat in by F0
Q0= F0× C.V
= (1000 × 29396)/3
= 8165 kW
Heat in by A
Q1=A×C p1× ∆T
=A× 1 × (328 - 298)
= 30A kW
Heat Out
Heat out by A+W
Q2 = F2×CP2 ×∆T
CP2 = (CP A+
CPW )/2
= 2.5845 KJ/kg-K
Q2 = ((A+ 255/3600) (2.5845) (317 - 298))
Q2 = 49.1 (A+ 0.0708)
61
Eq no 2
Eq no 3
Heat out by Q3
Q3= F1× C.V
= (744.68 × 25227)
= 5218 Kw
A Calculation
Total heat in = Total heat out
8165 + 30 A = 5218 + 49.1(A+ 0.103)
8165 - 5218 – 3.476 =(49.1 - 30) A
A =54.11 kg/s
= 554799.6 kg/hr
Then
A+W= 555054.79 kg/hr
Q1= 4623.3 KW
Q2=7570.3KW
Heat Losses
Heat Losses = Total Heat in – Total Heat Out
= 12788.3 – 1278
= .3 kW
62
4.3 Energy Balance On Gasifie
Basis = 744.68 kg/hr
Energy in coal
Temperature of coal = T = 353.15 k
(80 c temperatures is maintained. Because spontaneous does take place if temperature
rises due To oxidation)
Ambient temperature = Ta = 298 K
Cp of coal= Cp= 1.45 KJ/kg K
63
Energy in coal=m×Cp×∆t
Energy in coal= 55977.18603 KJ/hr
Energy in coal = 15.54921834KW
Energy in oxygen
Amount of oxygen = 190.013kg/hr
Temperature of oxygen= 883.9 k
Room temperature= 298 k
Cpair= 0.918 KJ/Kg K
Energy in oxygen= 102199.6701 KJ/hr
Energy in oxygen= 28.38879726 KW
Total energy in gasifier=E1= 43.9380156KW
Heat generated in gasifier
1- CO+1/2CO2 → CO2 ∆H1 = -393.77 KJ/k mole of carbon
2- H2+O2 → H 2O ∆H2 = 742 KJ/k mole of H2
3- C+H2O → CO+H2 ∆H3 = 131 KJ/k mole of carbon
4- C+CO2 → 2CO2 ∆H4 = 172 KJ/k mole of carbon
5- CO+H2O → CO2+H2∆H5 = 41.98 KJ/k mole of carbon
6- H2+S → H2S ∆H6 = 52 KJ/k mole of carbon
64
Table 4-11: Summery Of Energy Balance on Gasefier
Gases leaving gasifier K mole/hr kg/hr
CO 36.225 1014.3
H2 36.0649671 72.1299342
H2S 0.04374995 1.4874983
N2 0.07499991 2.09999759
F3 72.408717 1090.01743
Calculation of heat of chemical reactions
From reaction
Heat evolved from reaction =R= k mole×∆H/3600
Heat absorbed from reaction no1 =R1= 7.433390445 KW
Heat absorbed from reaction no1 =R1= 2.624728163 KW
Heat absorbed from reaction no1 =R1= 0.42242375 KW
Heat absorbed from reaction NO1 =R1= 0.520938414 KW
Heat of reaction H2= 11.00148077 KW
65
Heat in flue gases
Cp of flue gases = 2.728 kJ/kg k from literature
Temperature of flue gases =1100 k
Reference temperature = 298 k
Mass of flue gases = 1090.01743 kg/hr
Energy in the flue gases =m×Cp×∆T
Energy in the flue gases =m×Cp×∆T
E2= 662.4447707 KW
66
4.4 Energy Balance on Scrubber
Temperature of gases entering scrubber = T5 = 363 K
Cp of product gas= Cp=2.75509 KJ/kg .k
Cp of water = CpW =4.18KJ/kgk
Temperature of water entering scrubber = T7 = 298 K
Temperature of exiting gases from scrubber=T6=?
Temperature of exiting water from scrubber =T8= 308 K
T8 is supposed to be 308 k as our own choice because by controlling water flow we can
control Temperature. Less flow rate of water will cause more temperature of water and
more flow rate Of water will cause less increase in temperature of water.
Flow rate of gas entering is average of = m gas = 1061.39kg/hr
67
Entering and exiting gases from scrubber (from material balance values are
taken)
Average flow rate of water entering= m H20 = 881.3 kg/hr
Energy balance for water
Q= m Cp ∆T
Q= 10.23287222 k w divided by 3600 for conversion into sec.
Energy balance for gas
Energy taken by water = Energy given by gas
Q gas =-10.23287 K
Because energy is being released by gas to water Q =m C p ∆T
OR
T6 = (3600×Q/m Cp) + T5
Because mass in kg/hr so energy should be in hr
Also,
T6= 350.4023605 K
Q H2O= 36838.34 KW
Q gas= 36838.332 KW
68
5 Equipment Design
5.1 Fluidized Bed Gasifier Design [13]
(From chemical process equipment by couper)
Weight of mixture of particles =744.68 kg
Bed is supposed to hold
Density of particles= ρp = 1700 kg/m3
Volumetric flow rate of gas = 0.03718 m3/sec69
Viscosity of fluidizing gas (O2) = 0.02018 Cp
= 0.00002018 N sec/m2
Density of O2 =1.42902kg/m3
Distribution of particles sizes
D µm 252 178 126 89 70 50 30 10
wt fraction 0.088 0.178 0.293 0.194 0.113 .078 0.042 0.014
ut(m/s) 3.45 1.72 0.86 0.43 0.27 0.14 0.049 0.0054
1. Terminal velocity is found by stokes equation
Ut = ((g×(ρp-ρ)/ (18×µ))×(DP^2)
A)-average particle size is
dp =1/∑ (xi/di)
∑xi/di = 0.011828664
Dp = 84.54039997 µm
with dp=84.54
And density difference of = 1698.57098 kg/m3
Material appears to be in group a of fig 6.12 of chemical process equipment by couper
70
2. Minimum fluidizing velocity
Umf = 0.0093dp^1.82(ρp-ρf) ^0.94/µ^0.88ρf^0.06
Umf = 0.005180668 m/sec
Eq 134&135
Remf =dp×u×ρ/µ=((27.2^2)+0.0408(Ar))^0.5-(27.2)
Ar =ρ×(ρp-ρ)×g×dp^3/µ^2
g = 9.81 m/s
Ar = 35.32983304
Remf =0.026484481
Umb = (µ×Remf)/ (dp×ρ)
Umb = 0.004423948
Use larger value as conservative one
umf = 0.005180668 m/sec
Using eq 6.136
Umb = (33)×(dp)×(µ/ρ) ^ (-0.01)
Umb = 0.002911249 m/s
umb/umf= 0.561944832
Using eq 6.138
Umb/umf= ((82)×(µ^0.6)×(ρ^0.06))/ ((g)*(DP^1.3)×(ρp-ρ))
Umb/umf= 1.510541123
71
3. Voidage at minimum bubbling
(From 6.139)
Єmb^3/ (1-Єmb) = (47.4)×((g)×(DP^3)×(ρp^2)/ (µ^2)) ^ (-0.5)
Єmb^3/ (1-Єmb) = 0.231110476
Put Єmb =0.5 it approximately satisfies equation
Єmb = 0.5 eq no 4
Operating gas velocity Ratios of entraining and minimum fluidizing velocities from two
smallest particle sizes present are 16.83126162 for 30µm and 1.042336706 for 10µm.
Entrainment of smallest particles cannot be avoided, but an appreciable Multiple of
minimum fluidizing velocity can be used for operation [14]
Say ratio is 5 so that
Uf = 0.025903338 m/s
Bed expansion ratio from figure 6.10c with
dp = 84.5404 µm
=0.0033 in
And
Gf/Gmf= 5
R = 1.16 by interpolation by full lines
1.22 Off the dashed line
Take
R = 1.22 as more conservative
72
From equation 6.140 ratio of voidages is
Єmb/Єmf = (Gmb/Gmf) ^0.22
Єmb/Єmf = 1.424863957
From eq no 4 above
Єmb = 0.5
SO
Єmf = 0.350910694
Accordingly ratio of bed levels is
Lmb/Lmf = (1-Єmf/1-Єmb)
Lmb/Lmf = 1.298178612
Fluctuations in levels From figure 6.10d with
Dp = 0.0033 in
The value of
m- = 0.02
m- =0.02
SO
r =exp ((m-×(Gf-Gmf)/Gmf)
r = 1.083287068
TDH from fig 6.10i at chemical process equipment by couper
uf =umf(for 30µm)-4(umf)
uf =0.02827733 m/s
73
4. Vessel diameter
Vessel diameter=D= ((vol flow of gas per sec×4)/ (0.305×3.14)) ^ (0.5)
Vessel diameter=D= 0.394066888 m
from 6.10i using D &uf in cm/s
TDH= 1 approx
5. Bed Height
With charge of 10000kg of solids and a voidage at minimum bubbling of 5 the height of
Minimum bubbling bed is
L= (wt of mix particles) / ((density of particles)×(1-Єmb)× (3.14/4) ×(D^2))
L=7.186893649 m
This value includes expansion factor which was calculated separately above but not the
fluctuation parameter. With this parameter bed height is
bed height = Lb=L×r
Lb =7.785468947 m
6. Vessel height
The vessel height is made up of this number + TDH
OR
Vessel height=Lb+ TDH
Vessel height= 8.785468947 m
74
Table 5-12: specification data sheet of gasefier
GASIFIER
Equipment No. 1
Function: Gasification of Coal
Sheet No. 1
Operating Data
Height 8.78m Type Fluidized Bed
No. of Units 1 Connected Vertically
Performance of One Unit
Circulating fluid In (kg/hr) Out (kg/hr)
coal 744.68 -----
steam 172.492 ------
oxygen 190.013 ------
Syn gas ------- 1107.185
Construction of Gasifier
Vessel diameter 0.394m
Bed height 7.78,m
Minimum fluidizing velocity 0.02827733 m/s
75
5.2 Heat Exchanger Design
Feed flow rate in = F1= 1090.01743 kg/hr
Feed flow rate out = F2 = 1090.01743 kg/hr
Mass flow rate of cooling water in = F3 =? Kg/hr
Mass flow rate of cooling water out = F4 =? Kg/hr
Temperature of gas in = T1 = 826.85 oC
Temperature of gas out = T2 = 89.85 oC
Temp of cooling water in = T3 = 24.85 oC
Temp of cooling water out = T4 =610.75 oC
Specific heat of water = cp= 4.625 kJ/kg oC
76
Specific heat gas = cp (gas) = 2.75509 kJ/kg oC
1. Heat load on heat exchanger
Q = m × Cp × ∆T
For gas
Q = m × Cp ×∆T
Q = 614.8005115 KW
= 614800.5115 W
For water
Q =m×Cp×∆T
m = Q/ (Cp×∆T)
m = 0.226881448 kg/sec
m = 816.7732124 kg/hr
2. Log mean temp difference
LMTD=∆Tlm= ((T1-T4)-(T2-T3))/ ((ln ((T1-T4)/ (T2-T3)))
∆Tlm =125.7747515 0C
3. Overall heat transfer coefficient
Assume overall heat transfer coefficient
U= 80 W/m2C
4. Heat transfer area
Q=U×A×∆Tlm
77
A=Q/U×∆Tlm
A=61.10134429 m2
5. Exchanger type & dimensions
Shell and tube heat exchanger
Standard dimension of exchanger
Inner diameter of tubes= i.d= Di=16 mm= 0.016 m
Outer diameter of tubes=o.d=Do= 30 mm= 0.03 m
Length of tubes =L= 4.88 m
Area of one tube
A= π×Do×L
= 0.459696 m cupro nickel
Tube pitch
Tube pitch=Pt=1.25×Do
Pt = 0.0375 m
Number of tubes
Nt =Number of tubes
Nt = heat transfer area / area of one tube
= 132.91685
Bundle diameter
Db = Do×(Nt/K1) ^ (1/n1)
Using triangular pitch and two passes
78
K1= 0.249
n1= 2.207
Db= 516.3066323 m
Shell diameter
Diameter of shell =Ds=Db+ clearance
Using split ring floating head type:
Clearance = 36.604 mm
Ds = 552.9106323 mm
6. Tube side heat transfer coefficient (H2O)
Tube side heat transfer coefficient can be calculated as
Mean gas temperature = Tm= 458.35 OC
Tube cross sectional area Ai= (π×Di^2)/4
Ai = 0.00020096 m2
Tubes per pass = Tpp = Nt / 2
= 66.45842501
Total flow area
Total flow area = At=Tpp×Ai
At = 0.013355485 m2
Gas mass velocity = Gs= mass flow rate of gas/At
= 81615.71239 kg / m2.hr
Water linear velocity= Ut H20
79
Density of gas=density = 0.77026 kg/m3
UtH20 = 2940.383565 kg/sec.m2
Hi H2O= (Jh×Re×Pr^0.33×Kf×(µ/µw) ^0.14)/Di
ReH2O= ρUtDi/µs
= G×Di/µ
ρH2O = 1000 KG/m3
µH2O = 0.8 mNS/m2
Kf H2O =0.59 W/m.C
Viscosity of gas = µgas =0.01258589 Ns/m2
Density of gas =ρ = 0.77026 kg/m3
Thermal conductivity of gas= Kfs= 0.0125 W/mOC
Re H20= 58807.67129
Pr H20 = Cp×µs/Kfs
= 6.271186441
L/Di =305
By using graph 12.23 coulson vol 6 we can find value of transfer factor jh
JhH20 = 0.036
hi H20 = 80010.14719 W/m2.C
80
7. Shell side heat transfer coefficient (gas with lagged shell)
De shell = equivalent diameter
De = (1.10/Do)×(Pt^2-0.0917Do^2)
De = 0.0485364 m
As shell = ((Pt-Do)×Ds×Lb)/Pt
Lb shell = Ds×0.3
Lb = 165.8731897 m
As = 0.01834261 m2
G (GAS) = mass flow rate of gas / As
Cp gas = 2.75509 kJ/kg .0C
G GAS = 59425.42679 kg/m2
ρ gas = density of gas
= 0.77026 kg/m3
µ Gas = viscosity of gas
= 0.01258589 NS/m2
Kf gas = thermal conductivity of gas
= 0.0125 W / m .0C
Re gas = ρ ×g×Ug×De/µg
= G ×g×De/µg
= 314743.9603 (multiply by 1000 for per hr calculation)
81
Pr gas = Cp×µ×g/K fg
= 2.774020774
Baffle cut=20 to 25% optimum
Heat transfer coefficient jh
By using the graph find value of heat transfer coefficient factor jh.
Jh =0.1
hs=shell side transfer coefficient
hs = (Jh×Re×Pr^0.33×Kf gas×(µ/µh20) ^0.14) / De [10]
hs = 6347.127367 W/m2 0C
Fouling coefficients
Hid = Tube side fouling coefficient
Hid = 9000 W/m2c
Hod =Shell side fouling factor
Hod = 7500 W/m2c
8. Overall heat transfer coefficient
Thermal conductivity of cupro nickel alloys=K= 50 W/m2 0C
1/ Uo =1/Hs+1/Hi+ ((Do×ln (Do/Di)/2×K)) + (Do/Di)×(1/Hid) + (Do/Di)×(1/Hi)
1/Uo =0.000405502
Uo = 2466.081172
82
9. Pressure drop
Tube side
From fig 12.24 graph value of friction factor=Jf
Jf = 0.002
Np = number of tube side passes = 2
∆Pt =Np×(8×Jf×(L/Di)×((µ/µw) ^-m) +2.5)×((ρw×(Ut^2))/2)
m = 0.14 for turbulent flow
Us gas= 5094465.178 kg/sec.m2
∆Pt = 96668540294 N/m2
Shell side
∆Ps = (8×Jf×(Ds/De)×(L/Lb)×Cp×(Us^2))/2
∆Ps = 1.91714E+14 N/m2 [15] [16]
83
Table 5-13: specification data sheet of heat exchanger
Heat exchanger
Equipment No.2
Function: Steam Generation
Sheet No.2
Operating Data
Size 61.101 m2 Type Shell and tube
Performance Unit
Shell Side Tube Side
Fluid
Circulating
Water Hot Gases
In Out In Out
Gases - - 1090.017kg/hr 1090.017kg/hr
Water 512.195kg/hr 512.195kg/hr - -
Temperature 298K 883.9k 1100k 363k
Pressure Drop 1.9×1014N/m2 9.6×1011 N/m2
Construction of Shell
Tubes
No of Tubes 133 Length 4.8m
Pitch 0.0375m Inside Dia 16mm
Outside Dia 30mm ------- ------
Shell Dia 552.9mm -------- ------
84
5.3 Cyclone Separator Design
Flow Rate of Gas entering =1850.125kg/hr
Density of particle= Δρ = 2500kg/m3
Density of gas = 0.7702kg/m3
Average particle size = 20µm
Temperature of gas at inlet =363k
V = m / ρ
V = 1850.125 / 0.7702
V = 2401.945 m3 / hr
Volumetric flow rate= v =0.66720m3/sec
1. Using high efficiency cyclone
2. Inlet duct area of gas
The optimum velocity of separator having range 10-20
Let
U =15m/sec
Inlet duct area Ai = flow rate / u
=0.6672 / 15
Ai =0.04448 m2
3. Diameter of cyclone
Area of duct =Ai=0.5Dc × 0.2Dc
0.04448 =0.1Dc2
Dc = 0.6669m
85
This is too large compared with slandered diameter of 0.203 m therefore multiple
cyclones should be tried.
4. Length of upper section
Lc = 1.5Dc
= 1.0003m
5. Length of lower section
Zc = 2.5Dc
=1.6672m
Total height = Lc + Zc
= 4Dc = 2.667m2
6. Outlet duct area of gas
D0 = 0.5Dc
= 0.3334m
A0 = π/4 D0 2
=0.0872m2
7. Dust exit diameter
Dd =0.375 Dc
=0.25m
8. Inlet height
H =0.5Dc
=0.33345m
86
9. Inlet width
B =0.2Dc
=0.13338
10.Terminal velocity of smaller particle
U=0 . 2×Ai×D0×g
π×(ZC+LC )×Q×DC
U= 0 .2×0 .0444×0. 3334×9 .83 . 14×2. 667×Q 0. 669×0 .6672
=7.76×10-3 m/sec
Dc is too large compared with standard diameter of 0.203 m therefore multiple cyclones
should be tried.
Flow per cyclone = 530.008715 kg/hr
Viscosity of gas =µ2 = 0.01258589 Cp
Volumetric flow rate= Q2=688.0896619 m3/.hr
Table 5-14: particle size distribution in cyclone separator
Particle size
µm
50 40 30 20 10 5 2
Percentage
by weight less
than
90 75 65 55 30 10 4
87
11.Cyclone performance
d2/ (d1) = ((((Dc2/Dc1) ^3)×(Q1/Q2)×(Δρ1/Δρ2)×(µ2/µ1)) ^1.2)
Diameter of standard cyclone =Dc1 =0.203 m
Standard flow rate for high efficiency design = Q1 = 223 m3/hr
Solid fluid density difference in standard condition =∆ρ1= 2000 kg/m3
Test fluid viscosity (at 1 atm 20 c)=µ1 = 0.018m Ns/m2
Scaling factor = d2/d =3.422583401
The performance calculations, using this scaling factor and fig 10.4a are set out in the
table below
88
Table 5-15: calculated performance of cyclone
Particle
size
% age in
range
Mean
particle
size/scaling
factor
efficiency
at scaled
size (fig
10.46a vol
6)
Collected
Percent in range×efficency/10
0
Grading
At exit
Percent in range -
collected
% At
exit
>50 10 11 94 9.4 0.6 2.08
50-40 15 10 93 13.95 1.05 3.64
40-30 10 7 88 8.8 1.2 4.16
30-20 10 5 85 8.5 1.5 5.2
20-10 25 3 75 18.75 6.25 21
10 - 5 20 2 50 10 10 34
5 - 2 6 1 30 1.8 4.2 14.58
2 - 0 4 0 0 0 4 13.88
Overall
Efficiency=
71.2
28.8 99.02
89
12.Pressure drop calculations
From 10.44 a & b Coulson vol 6 pg 450
Area of inlet duct= A1 = 0.0254863 m2
Cyclone surface area = As =2.880739093m2
fc taken as= fc = 0.005
ψ =fc×As/A1
ψ = 0.565154435
rt/re =((0.5Dc+0.2Dc+0.2Dc)-(0.2Dc/2))/(0.5×Dc)
rt / re=1.599970596
From figure 10.47 coulson vol 6
Ф =0.8
u1 = vol flow of gas (in m3/sec) / A1 (m2)
u1 = 7.499559261 m/s
Area of exit pipe= (3.14×((0.5Dc) ^2))/4
Area of exit pipe= 0.050013924 m
u2 = vol flow gas (in m3/sec) / area of exit pipe in m2
u2 =3.821656123 m/s
From equation 10.9 coulson vol 6
∆P = ((ρ gas) / (203))×((u1^2) (1+ (2×(Ф^2)×((2×(rt/re)-1)) + (2×(u2^2))∆P
= 7.048064493 mille bar
90
Table 5-16: specification data sheet of cyclone separator
Cyclone Separator
Equipment No.3
Function: Heavy Particle Separation
Sheet No.3
Operating Data
Height 2.667m Type Cyclone
No of unit 2 Category Centrifugal Force
Process Data of One Unit
Material Flow Rate(Kg/hr)
solids removed 24
Gases entering 1090.01743
Gases leaving cyclone 1066.017
solids in gas stream 6
Optimum Velocity 15m/s
Terminal Velocity 7.76×10-3m/s
Pressure Drop 7.048 mille bar
91
Technical Data
Upper Section
Diameter of Cyclone 0.6669m
Area of Gas Inlet 0.04448 m2
Dia of Gas Outlet 0.3334m
Length of Upper Section 1.0003m
Lower Section Diameter of Dust Collector 0.25m
Length of Lower Section 1.6672m
92
5.4 Design Of Scrubber
Flow rate of gas in = 1066 kg/hr
v = 0.296111111 kg/sec
Flow rate of liquid in = 875.20487 kg/hr
Flow rate of gas out = 1066 kg/hr
Flow rate of liquid out = 887.40646 kg/hr
Temp of gas in = 363 k
Temp of gas out = 255.3728 k
93
Temp of liq in = 298 k
Temp of liquid out = 308 k
Density of syn gas = 0.77026 kg/m3
Viscosity of gas = 0.012586 NS/m2
Heat capacity of gas = 2.75509 kJ/kg 0C
Density of water = 1000 kg/m3
Viscosity of water = 0.0035 NS/m2
Heat capacity of water = 4.625 kJ/kg0C
Mole wt of liquid = 18 kg/k mole
1. Packing specification
Packing type intallox saddle (ceramic)
Packing size=dp = 0.038 m
Packing factor = fp = 170 m^-1
Porosity of packing factor= c = 70
Surface area of packing =a= 194 m2/m3
2. Column area required
Column area required =Ax =?
Ax = V / Vw
First we find out Vw
FLv= (L/V) × ((gas density / liq den) ^ 0.5)
FLv= 0.022786163
94
K4 = 1.9 for 42mmH2O/m packing
At flooding
K4 = 6
3. Percentage flooding
Percentage flooding =(((k4 at 42mmH2O/m packing) / (k4 at flooding line)) ^ 0.5) × 100
Percentage flooding= 56.27%
For Vw
Vw = ((k4 × density gas × (liq den - gas den)) / (13.1×fp×((visliq / den liq) ^ 0.1))) ^ 0.5
Table 11.3 for 38 mm packing 1.5 inch intallox sadlles
Fp = 170 m^-1
Vw = 1.518674281 kg/m2 sec
Column area required=Ax= 0.19498 m2
4. Column diameter
Column diameter=d= (4×Ax/3.14)^0.5
d = 0.49837954 m
Ratio of packing size to column diameter = Ax / packing size
= 5.131052629
5. Height of overall gas phase transfer unit HoG
HoG =HG+ (m×(Gm/Lm))×HL
HG =Gm/ (KG×aw×P)
HL =Lm/ (KL×aw×Ct)
95
aw/a=1-(exp((-1.45)×((бc/бL)^0.75)×((Lw×/(a×µL))^0.1)×(((Lw×^2×a)/(ρL^2×g))^-
0.05)×((Lw×^2/ (бL×ρL×a)) ^0.2)))
Бc= 0.061 mN/m
бL= 0.0247 mN/m
g = 9.81 m2/sec
Lw*= L / Ax
w* = 4488.690484 kg/m2 sec
aw /a= 0.998393899
aw= 193.6884164 m2
6. Liquid mass transfer coefficient
DL= 1.7E-09 m2/sec
Dv= 0.0000145 m2/sec
KL×((ρL/(µL×g))^0.33)=(0.0051)×((Lw×/(awµL))^(2/3))×((µL/(ρL×DL))^-
0.5)×((a×dp)^0.4)
KL×((ρL/(µL×g))^0.33)= 0.088123835
KL= 0.002964057
K5=5.23
(KG/a)×((R×T)/Dv) =(K5)×((Vw/ (a×µv)) ^0.7)×((µv/ (ρv×Dv)) ^0.33)×((a×dp) ^-2)
(KG/a)×((R×T)/Dv) = 0.701608509
R = 0.083143 bar.m3/kg mole .k
Temperature of gas= 306.0932 K
96
KG/a=3.99745E-07
KG= 7.75506E-05 k mole/m2.sec.bar
7. Gas film transfer coefficient
HG=Gm/ (KG × a × P)
Gm=Vw / mole wt
Avg mole wt of gas = 17.63 kg/k mole
Gm= 0.086141479
Pressure of column = 101.325 K pa
HG= 5.652179469
HL = Lm / (KL × aw × Ct)
Lm = Lw × / mole wt
Mole wt of water = 18kg/ k mole
Lm = 249.3716935
Ct =ρL / mole wt
Ct = 55.555
HL = 7.818607187 m
AS
HOG=HG+ (m (Gm/Lm))×HL
m (Gm/Lm) =0.7 TO 0.8= 0.75
HOG =11.51613486m
97
8. Height of packing
Z =Height of packing
Z = HOG × NOG
Mass fraction of particles = mass of particles / total mass
Mass of particles entering scrubber seen from material balance on cyclone= 6 kg/hr
Mass fraction of particles in = 0.005628518
Considering 90% removal of particles = 0.90 × mass fraction at inlet of scrubber
= 0.005065666 y1
So
Fraction of particles at outlet of scrubber = inlet fraction - removed fraction
= 0.000562852 y2
y1 / y2 = 9
Using graph 11.40 of Coulson vol 6
NOG =4.85
Z =55.85325407m
1. Height of scrubber
Height of scrubber = height of packing + HoG + HL + HG
Height of scrubber = 80.84017558 m (15)
98
Table 5-17: specification data sheet of scrubber
Scrubber
Equipment No.3
Function: Separation of Gases
Sheet No.3
Column area 0.19498 m2
Percentage flooding 57%
Packing type Intalox saddle
Height of packing 55.85m
Scrubber height 80.840 m
HOG 11.51m
99
5.5 H2S Absorber Design
Flow rate of gas in = 1061.3931 kg/hr
= 0.294831417 kg/sec
Flow rate of liquid in = 1060.15 kg/hr
Flow rate of gas out = 1060.05435 kg/hr
Flow rate of liquid out= 1061.39 kg/hr
100
Temp of gas in = 210.3107 k
Temp of gas out = 250.3107 k
Temp of liquid in = 298.15 k
Temp of liquid out = 258.15 k
Density of gas=∆gas = 0.77026 kg/m3
ρ = PM / RT
Pressure of column= 101.3k pa = 1.013 bars
R =0.083143 bar.m3/kg mole k
T =254.23035 K
M =15.3 kg/k mole
Viscosity of gas =µ = 0.012586 Ns/m2
Heat capacity of gas = 2.75509 KJ / kg 0C
Density of liquid = ρ = 1031 KG/m3
Viscosity of liquid =µ = 4.7 Ns/m2
Heat capacity of liq =2.05 KJ / kg 0C
Mole wt of liquid = 178 kg/k mole
1. Packing specification
Packing type intallox saddle (ceramic)
Packing size = dp = 0.038 m
Packing factor = Fp = 170 m-1
Porosity of packing factor= C= 70
101
Surface area of packing = A=194 m2/m3
2. Column area required
Column area required =Ax=?
Ax = V/Vw
First we find out Vw
FLv = (L/V)×((ρ gas/ρ liq) ^ 0.5)
Density of gas = ρgas = 0.77026 kg/m3
FLv = 0.027301116
K4 = 1.9 for 42 mmH2O/m packing
At flooding
K4 = 6
3. Percentage flooding
Percentage flooding = ((k4 at 42 mmH2O/ m packing/k4 at flooding line) ^0.5)×100
= 56.27314339
For Vw
Vw = ((K4×ρv×(ρ L-ρ gas))/ (13.1×Fp×((µL/ρ L) ^0.1))) ^0.5
Table 11.3 for 38mm 1.5 inch intallox saddles
Fp = 170 m-1
Vw = 1.077359006 kg/m2sec
Ax =Column area required = 0.416 m2
102
4. Column diameter
d =Column diameter
d = (4×Ax/3.14) ^ 0.5
d = 0.72m
Ratio of packing size to column diameter =AX / packing
Size =7.201611951
5. Height of overall gas phase transfer unit
(using Onda’s method)
HoG =Height of overall gas phase transfer unit
HoG =HG+ (m (Gm/Lm))×HL
HG =Gm/ (KG×aw×P)
HL = Lm/ (KL×aw×Ct)
aw/a = 1-(exp((-1.45)×((бc/бL)^0.75)×((Lw×/(a×µL))^0.1)×(((Lw×^2×a)/(ρL^2×g))^-
0.05)×((Lw×^2/(бL×ρL×a))^0.2)))
бC = 0.061 mN/m
g =9.81б m/s2
бL = 0.0247 mN/m
Lw* =L/Ax
Lw* = 1.076097207 kg/m2sec
aw/a = 0.373824235
aw = 72.52190155 m2
103
Liquid mass transfer coefficient
DL = 1.7E-09 m2/s
Dv = 0.0000145 m2/s
KL×((ρL/(µL×g))^0.33)=(0.0051)×((Lw×/(aw×µL))^(2/3))×((µL/
(ρL×DL))^0.5)×((a×dp)^0.4)
KL×((ρ L/(µL×g)) ^ 0.33) = 1.49027E-07
KL = 5.11741E-10 m/s
K5 = 5.23
(KG/a)×((R×T)/Dv)= (K5)×((V w/ (a×µv))^0.7)×((µv/ (ρv×Dv))^0.33)×((a×dp)
^2)(KG/a)×((R×T)/Dv)= 0.551724047
(KG/a = 4.57512E-07
KG = 8.87574E-05 k mole / m2.sec.bar
Gas film transfer coefficient
HG = gas film transfer coefficient
HG =Gm/ (KG × a × P)
Gm =Vw/mole WT
Gm = 0.061109416 kmole/m2.sec
HG = 3.503421355 m
liquid film transfer coefficient
HL = Lm/ (KL × aw × Ct)
Lm = Lw×/mole WT
104
Lm = 0.00604549 k mole/m2.sec
Ct =ρL/mole wt
Ct = 5.792134831
HL = 0.281237854 m
AS
HOG =HG+ (m (Gm/Lm))×HL
m (Gm/Lm) =0.7 TO 0.8=0.75
HOG =3.714349746 m
6. Height of packing
Z =Height of packing
Z = HOG × NOG
Y1 = mole fraction at inlet
= 0.3125 k mole/hr of H2S
Y2 = mole fraction at outlet
= 0.03125 k mole/hr of H2S
YI/Y2= 10
Using graph 11.40 of Coulson vol 6
NOG=5
Z =18.57174873 m
105
7. Total column height
Height of absorber = Z+ HoG +HL+HG
Height of absorber = 26.07075768 m [15]
Absorber
Equipment No.4
Function: Separation of Gases
Sheet No.4
Column area 0.416m2
Percentage flooding 57%
Packing type Intalox saddle
Height of packing 18.59m
Absorber height 26.07m
HOG 3.714349746m
106
6 Instrumentation
Instrumentation is carried out to monitor the key process variables during plant
operation. And instruments may be incorporated in automatic control loops or used for
the manual monitoring of the process operation. There may be manual or automatic
computer data logging system. Instruments monitoring critical process variables will be
fitted with automatic alarms to alert the operators to critical and hazardous situations.
Industry pursuit of increasingly stringent process control and safety requirements led to
an early adaptation of computational techniques in this field. Today, a wide range of
computing devices, ranging from imbedded microprocessors to dedicated computers, is
commonly employed throughout the industry. This class explores the technical
foundations of process and control instrumentation in use, and covers the practical
aspects of its deployment and control [17].
Measurement
Instrumentation can be used to measure certain field parameters (physical
values).These measured values include:
1. Pressure
2. Flow
3. Temperature
4. Level
5. Density
6. Viscosity
7. Radiation
8. Frequency
9. Current
107
10. Voltage
11. Inductance
12. Capacitance
13. Resistivity
14. Chemical Composition
6.1 Control
In addition to measuring field parameters, instrumentation is also responsible for
providing the ability to modify some field parameters to keep the process variables at a
desired value.[8]
6.1.1 Incentives For Chemical Process Control
A chemical plant is an arrangement of processing units (reactor, heat exchanger,
pumps, distillation columns, absorbers, evaporators, tanks etc.), integrated with one
another in a systematic and rational manner. The plants overall objective is to convert
certain raw materials into desired products using available sources of energy, in the
most economical way.
In its operation, a chemical plant must satisfy several requirements imposed by its
designers and the general technical, economic and social conditions in the presence of
ever-changing external influences (disturbances). Among such requirements are the
following:
Safety
The safe operation of a chemical process is a primary requirement for the well-being of
the people in the plant and for its continued contribution to the economic development.
108
1. Production Specification
A plant should produce the desired amounts and quality of the final products. Therefore,
a control system is needed to ensure that the production level and the purity
specifications are satisfied.
2. Environmental Regulations
Various federal and state laws may specify that the temperature, concentrations of
chemicals, and flow rates of the effluents from a plant be within certain limits.
3. Operational Constraints
The various types of equipment used in a chemical plant have constraints inherited to
their operation. Such constraints should be satisfied throughout the operation of the
plant .e.g. pumps must maintain a certain net positive suction head etc.
4. Economics
The operation of a plant must conform to the market conditions, that is, the availability of
the raw materials and the demand of the final products. Furthermore, it should be as
economical as possible in its utilization of raw materials, energy, and capacity and
human labor. Thus it is required that the operating conditions are controlled at given
optimum levels of minimum operating cost, maximum profit and so on [18].
6.1.2 Elements Of Control System
In almost every control configuration, we can distinguish the following hardware
elements.
1. The chemical process
2. Measuring element or sensors
3. Transducers
4. Transmission lines
5. Controllers
6. The final control element
109
1. The Chemical Process
It represents the material equipment together with physical or chemical operation that
occurs.
2. The Measuring Instruments or the Sensors
Such instruments are used to measure the disturbances, the controlled output variables,
or the necessary secondary output variables and are the main sources of information
about what is going on in the process The measuring means depend upon the types of
variable, which is to be measured, and these variables must be recorded also.
Following are some typical sensors, which are used for different variables
measurements.
1. Pressure sensors
2. Temperature sensors
3. Flow rate sensors
4. Level sensors
Characteristics example of these types of sensors is as follows.
1. Thermocouples or resistance thermometers for measuring the temperature, also
used for severe purpose some radiation detectors may also be used.
2. Venturi meters also flow nozzles for flow measurements.
3. Gas chromatograph for measuring the composition of the stream.
A good device for the measurement depends upon the environment in which it is to be
used. Like a thermometer, it is not a good measuring device, as its signal is not rapidly
transmitted. So signal transmission is very important in selecting the measuring device.
So the measuring device must be rugged and reliable for an industrial environment.
110
3. Transducers
Many measurements cannot be used for control until they are converted to physical
quantities such as electric voltage and current a pneumatic signal. For example, stream
gauges are metallic conductors whose resistance changes when mechanical strain is
imposed on it. Thus they can be used to convert a mechanical signal to electric one.
4. Transmission Lines
These are used to carry measurements signal from measuring device to the controller.
In the past, mostly transmission lines were pneumatic nature that they are using the
compressed air or liquid to transmit the signal but with the automation of industry and
advent of electronic controllers, electric lines have over-ruled the pneumatic operations.
Many times the measurements coming from a device are very weak and these must be
amplified to get the things right. So it is very often to find amplifies in the transmission
lines to the controller. For example the output of a thermocouple is only a few milli-volts
so they must be amplified to few volts to get the controller.
5. Controller
This is the hardware element that has “intelligence”. It receives the information from the
measuring device and decides what action must be carried out. The older controllers
were of limited intelligence, could perform very limited and simple operations and could
implement very simple control laws. The use of digital computers in this field has
increased the use of complicated control laws.
6. The Final Control Element
This is the hardware element that implements the decision taken by the controller. For
example, if the controller decides that flow rate of the outlet stream should be increased
Or decreased in order to keep the level of the liquid in a tank then the final control
element which is a control valve in this case implements the decision by slightly opening
or closing the valve.
111
6.1.3 Modes of Control
There are various modes in which the process can be controlled. The different modes
depend upon the types of controllers and the action it takes to control any process
variable. Actually the controller action is dependent on the output signal of the
transmitter (sensor with transducer). This signal is compared with the set point to the
controller and the error between these two is used to control the process. Different
controllers react in different manner to control this off-set between the controlled
variable and the set point.
Different Types of Control Actions
On the prescribed basis, following are the different types of control actions:
1. On-off control
2. Proportional control
3. Integral control
4. Rate or derivative control
5. Composite control
Composite Control Modes
Also there are combined control actions of different types of controllers. Actually in
different operations, it is very rare that only one of the above control actions is found but
a composite control action is the more often practice.
Following are typical composite control modes, which are usually used:
1. Integral-Integral controller (PI-controller)
2. Proportional-Derivative controller (PD-controller)
3. Proportional-Integral-Derivative controller (PID-controller)
In general the process controllers can be classified as:
1. Pneumatic controllers
2. Electronic controllers
112
3. Hydraulic controllers
While dealing with the gases, the controller and the final control element may be
pneumatically operated due to the following reasons.
1. The pneumatic controller is very rugged and almost free of
maintenance. The maintenance men have not had sufficient training and background in
electronics, so pneumatic equipment is simple.
2. Pneumatic controller appears to be safer in a potentially explosive atmosphere
which is often present in the industry.
3. Transmissions distances are short pneumatic and electronic
transmissions system are generally equal up to about 200 to 300 feet. Above this
distance electronic system beings to offer savings [18].
6.1.4 Selection of Controller
Actually in industry, only P, PI and PID control modes are the usual practice. The
selection of most appropriate type of controller for any particular environment is a very
systematic procedure. There are many ways and means that how a particular type of
system may be controlled through which type of controller. Usually type of controller is
selected using only quantitative considerations stemming from the analysis of the
system and ending at the properties of that particular controller and the control
objective. Proportional, Integral and Derivative control modes also affect the response
of the system. Following is the summarized criterion to select the appropriate controller
for any process depending upon the detailed study of the controller and control variable
along with process severity.
1. If possible, use a simple proportional controller:
Simple P-controller can be used if we can achieve acceptable off-set with not too high
values of gain. So for gas pressure and liquid level control, usually a simple proportional
controller may be used.
113
2. If a simple P-controller is not acceptable, use PI-controller:
A steady-stat error always remains for proportional controller so in systems where this
off-set is to be minimized, a PI-controller is incorporated. So in flow control applications,
usually PI-controller is found.
3. Use a PID-controller to increase the speed of the closed loop
response and retain robustness:
The anticipatory characteristic of the derivative control enables to use somewhat higher
values of proportional gains so that off-set is minimized with lesser deviations and good
response of the system. Also it adds the stability to the system. So this type of control is
used for sluggish multi-capacity processes like to control temperature and composition.
In short best controller is selected on following basis;
1. Severity of process
2. Accuracy required
3. Cost
6.2 Control Loops
For instrumentation and control of different sections and equipment of plants, following
control loops are most often used.
1. Feed backward control loop
2. Feed forward control loop
3. Ratio control loop
4. Auctioneering control loop
5. Split range control loop
6. Cascade control loop
114
6.2.1 Feed Back Control Loop
Feedback is a mechanism, process or signal that is looped back to control a system
within itself. Such a loop is called a feedback loop. Intuitively many systems have an
obvious input and output; feeding back part of the output so as to increase the input is
positive feedback; feeding back part of the output in such a way as to partially oppose
the input is negative feedback.
In more general terms, a control system has input from an external signal source and
output to an external load; this defines a natural sense (or direction) or path of
propagation of signal; the feed forward sense or path describes the signal propagation
from input to output; feedback describes signal propagation in the reverse sense. When
a sample of the output of the system is fed back, in the reverse sense, by a distinct
feedback path into the interior of the system, to contribute to the input of one of its
internal feed forward components, especially an active device or a substance that is
consumed in an irreversible reaction; it is called the "feedback". The propagation of the
signal around the feedback loop takes a finite time because it is causal.
Its disadvantage lies in its operational procedure. For example if a certain quantity is
entering in a process, then a monitor will be there at the process to note its value. Any
changes from the set point will be sent to the final control element through the controller
so that to adjust the incoming quantity according to desired value (set point). But in fact
change has already occurred and only corrective action can be taken while using feed
back-control system.
6.2.2 Feed Forward Control Loop
A method of control in which the value of a disturbance is measured, and action is taken
to prevent the disturbance by changing the value of a process variable
This is a control method designed to prevent errors from occurring in a process variable.
This control system is better than feedback control because it anticipates the change in
the process variable before it enters the process takes the preventive action. While in
feedback enter system action is taken after the change has occurred.
115
6.2.3 Ratio Control
A control loop in which, the controlling element maintains a predetermined ratio of one
variable to another. Usually this control loop is attached to such as system where two
different streams enter a vessel for reaction that may be of any kind. To maintain the
stoichiometric quantities of different streams this loop is used so that to ensure proper
process going on in the process vessel.
6.2.4 Auctioneering Control Loop
This type of control loop is normally used for a huge vessel where, readings of a single
variable may be different at different locations. This type of control loop ensures safe
operation because it employs all the readings of different locations simultaneously, and
compares them with the set point, if any of those readings is deviating from the set point
then the controller sends appropriate signal to final control element.
6.2.5 Split Range Loop
In this loop controller is per set with different values corresponding to different action to
be taken at different conditions. The advantage of this loop is to maintain the proper
conditions and avoid abnormalities at very differential levels.
6.2.6 Cascade Control Loop
This is a control in which two or more control loops are arranged so that the output of,
one controlling element adjusts the set point of another controlling element. This control
loop is used where proper and quick control is difficult by simple feed forward or feed
backward control. Normally first loop is a feedback control loop. We have selected a
cascade control loop for our heat exchanger in order to get quick on proper control (19).
6.3 Control Loops Around Equipment’s
6.3.1 Control Loops On Gasifier
The chief reactions taking place in the gasifier are exothermic. Therefore a large
amount of heat is liberated. Although the heat evolved catalysis the other reaction but if
the temperature is not controlled, it may lead to ash fusion temperature. So an
116
auctionary control loop is used to control temperature inside the reactor. Temperature is
controlled through flow rate of steam.
The heat generated is also removed by the coolant, which flows in the jacket around the
reactor. The control objective is to keep the temperature of the reacting mixture
constant at a desired value. Possible disturbances to the reactor include the feed
temperature and the coolant temperature, the manipulated variable to these two
disturbances is the coolant flow rate. We have employ cascade control loop by
measuring temperature inside the reactor, and taking control action before its effect has
been felt by the reacting mixture. Thus, if coolant temperature goes up, increases the
flow rate of the coolant to remove the same amount of heat. Decrease the coolant flow
rate when coolant temperature decreases.
117
Figure 5: Control loops on gasefier
118
6.3.2 Control Loop On Compressor
Figure 6: Control loops on compressor
The discharge of a compressor is controlled with a flow control system .To prevent the
discharge pressure from exceeding an upper limit, an override control with a high switch
selector (HSS) is introduced. It transfers control action from the flow control to the
pressure control loop whenever the discharge pressure exceeds the upper limit. Notice
that flow control or pressure control is actually cascaded to the speed control of the
compressors motor.
119
6.3.3 Control Loop On Absorption Column
Figure 7: Control loop on absorption column
Here a simple feedback control scheme is employed. Whenever the pressure drop
becomes high or low, it will be sensed by the differential pressure sensor and will be
controlled by the raw syngas flow rate. The control valve will accordingly become
partially open or closed.
120
6.3.4 Control Loops On Heat Exchanger
Figure 8: Control loop on heat exchanger
Symbol Used Description
121
Temperature Transmitter
Temperature Controller
Flow Transmitter
Flow Controller
Pressure Transmitter
Pressure Controller
Speed Controller
122
TT
TC
FT
FC FC
PT
PC
SC
Low Selector Switch
7 Cost Estimation
7.1 Total Purchased Cost Of Major Equipment
7.1.1 Cost Estimation Of Heat Exchanger
Heat transfer =61.1 m2
Pressure = 5 bar
Cost index of 2004 = 444.2
Cost index of 2011 = 635.8
As material of construction of shell and tube is carbon steel.
The purchased cost can be calculated by using following method
Purchased in 2004
Purchased cost = (bare cost from chart)×(type factor)×(pressure factor)
Bare cost from chart= 30000 $
Type factor =1
Purchased cost in 2004= 30000 $
Pressure factor= 1
Purchased cost in 2011
123
LSS
AS
Cost in 2004/cost in 2011= cost index in 2004/cost index in 2011
So
Cost in 2011 = 42940.11706 $
Cost in 2011 = (purchased cost in 2004 × cost index in 2011) / cost index in 2004
7.1.2 Cost Estimation Of Cyclone Separator
Diameter of cyclone separator=0.58 m
Height of cyclone separator= 2.019 m
Index of 2004= 444.2
Index of 2011= 681.7
Material of construction is carbon steel
Purchased cost in 2004
Purchased cost in 2004= (bare cost from chart)×(material factor) ×(pressure factor)
So,
Bare cost from chart = 6000 $
Material factor= 1
pressure factor= 1
Purchased cost in 2004 = 6000 $
124
Purchased cost in 2011
Cost in 2004 /cost in 2011=cost index in 2004/cost index in 2011
Cost in 2011 = (index of 2011×purchased cost in 2004)/index in 2004
Cost in 2011 = 9208.014408 $
7.1.3 Cost Estimation Of Absorber
Diameter of absorber= 0.7678 m
Height of absorber= 26.06 m
Index in 2004= 444.2
Index in 2011= 681.7
Material of construction is carbon steel
Purchased cost in 2004
Purchased cost in 2004= (bare cost from chart)×(material factor)× (pressure factor)
So,
Bare cost from chart= 30000 $
Material factor= 1
Pressure factor= 1
Purchased cost in 2004= 30000 $
Purchased cost in 2011
Cost in 2011 = (index of 2011×purchased cost in 2004)/index in 2004
Cost in 2011= 46040.07204 $
125
Now
Packing cost
Packing cost of packed column with packing of "intallox saddle" & packing size of 38mm
Will $ 1020 per m3
Volume of packing =3.14×r^2×l
Radius = 0.019 m
Height of packing = 18.57 m
Volume of packing = 0.021049838 m3
Cost of column packing
Cost of column packing = volume × cost per unit volume
Cost of column packing = 21.47083456 $
Total cost of column = cost of vessel + cost of packing
Total cost of column = 46061.54287 $
7.1.4 Cost estimation of scrubber
Diameter of scrubber= 0.49837954 m
Height of scrubber= 80.84018
Index in 2004= 444.2
Index in 2011= 681.7
126
As material of construction is carbon steel the purchased cost can be calculated using
following Method
Purchased cost in 2004= (bare cost from chart) × (material factor) × (pressure Factor)
As two scrubbers will be installed therefore height of each absorber 40.42009 m
Bare cost from chart = 100000 $
Material factor = 1
Pressure factor = 1
Purchased cost 2004 =100000 $
As there are 2 scrubbers thus cost of two scrubbers will be 200000 $
Purchased cost in 2011
Cost in 2004/cost in 2011= cost index in 2004/cost index in 2011
Cost in 2011= (index of 2011×purchased cost in 2004)/index in 2004
Cost in 2011= 306933.8136 $
Packing cost of scrubber with packing of "intallox saddle" & packing size will be $ 1020
Volume of packing
Volume of packing=3.14×r^2×l
Radius = 0.019 m
Volume of packing = 0.091635578 m3
Cost of column packing = 19.38 $
Total cost of column = 306953.1936 $
127
Total purchased cost of equipment (PCE)
Total purchased cost of equipment (PCE) = cost of reactor +cost of heat exchanger
+cost of Cyclone separator + cost scrubber + cost of absorber
So,
Total purchased cost of equipment (PCE) = 420162.8679 $
7.2 Fixed Capital Cost
Reactor cost $= 15000
ITEM PROCESS FLUID
Major equipmen
t ,total purchased cost
PCF (FLUID)
F1 Equipment erection 0.4
F2 Piping 0.7
F3 Instrumentation 0.2
F4 Electrical 0.1
F5 Building process 0.15
F6 Utilities 0.5
F7 Storages 0.15
F8 Site development 0.05
F9 Ancillary building 0.15
F10 Design and engineering 0.3
F11 contractor's fee 0.05
F12 Contingency 0.1
128
AS
Total purchased cost of equipment = 420162.8679 $
Total physical plant cost (PPC) =PCE ×(1+F1+F2+F3+…..+F9)
Total physical plant cost (PPC) = 1428553.751 $
Now we will find the fixed capital
Fixed capital=PPC× (1+F10+F11+F12)
SO,
Fixed capital = 2071402.939 $
Total investment required for project
AS,
Total investment required for project = fixed capital + working capital
Suppose the working capital is 10%of fixed capital
Now, working capital = 0.10×fixed capital
Working capital = 207140.2939 $
Total investment required for project = 2278543.233 $
Total investment required for project =fixed capital +working capital
7.3 Fixed Cost
Maintenance cost=0.10×fixed capital cost
Maintenance cost=207140.2939 $
Suppose
Operating labor= 80000 $
129
Laboratory cost =0.22×Operating labor
Laboratory cost =17600 $
Supervision cost =0.2×operating labor
Supervision cost =16000 $
Plant overheads =0.5×Operating labor
Plant overheads = 8000 $
Capital charges =0.1×fixed capital
Capital charges=207140.2939 $
Insurance =0.01×fixed capital
Insurance = 20714.02939 $
Local taxes =0.02×fixed capital
Local taxes =41428.05878 $
Royalties=0.01×fixed capital
Royalties= 20714.02939 $
Total fixed costs= 618736.7054 $
7.4 Variable Cost
Raw material cost =100000$ 11
Supposed miscellaneous material=0.1×maintenance cost
Miscellaneous material = 20714.02939 $
Transportation cost=negligible
130
7.5 Utilities
Water required =H2O required for gasifier + H2O for scrubber+H2O for absorber+ H2O
For exchanger
H2O mains =27346.89 kg/hr
Cooling H2O = 889.66 kg/hr
Steam = 310.19 kg/hr
Compressed air = 551.448 kg/hr
N2 = 2397.6 kg/hr
Cost of water mains=50 cents/1000kg
1000kg =50 cents
27346.89kg = (50/1000)×27346.89
Cost of 27346.89 kg of water mains= 1367.3445cents
100 cents =1$
I cent =$(1/100)
1367.345 cents =$(1/100)×1367.345
1367.345 cents =13.67345 $ IN 2004
Cost of cooling water =1cent/1000 kg
1000 kg =1 cent
889.66kg = (1/100)×889.66
889.66kg = 8.8966 cents
100 cents =1$
131
8.8966 CENTS = (1/100)×8.8966$
8.8966 CENTS = 0.088966 $ in 2004
Cost of steam =12$/1000kg
1000 kg steam =12$
1kg steam = (12/1000) $
310.19 kg steam = (12/1000)×310.19$
310.19kg steam =3.72228 in 2004
Cost index in 2004 = 1178.5
Cost index in 2011 = 1490.2
Cost in 2011= (index of 2011×purchased cost in 2004)/index in 2004
Cost of water mains in 2011= 17.28992379 $
Cost of cooling water in 2011= 0.112496507 $
Cost of steam in 2011= 4.70678121 $
Utilities= 22.10920151 $
Variable cost= 120736.1386 $
Direct production cost=total fixed cost +total variable cost
Direct production cost= 739472.8439 $
Now
Sales expense=0.3×direct production cost
Sales expense= 221841.8532 $
General overheads=10000 $
132
Research & development= 20000 $
Annual operating cost=direct production cost +sales expense over heads + research &
development
Annual operating cost= 991314.6971 $ [15]
Table 7-18: total purchased cost of equipment
Equipment Purchased cost
Heat exchanger 42940.11706 $
Cyclone separator 9208.014408 $
absorber 46061.54287 $
scrubber 306953.1936 $
reactor 15000 $
total 420162.8679 $
133
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135
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