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.

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In the name of Allah the Most

Beneficent, THE Merciful

i

Dedicated

To our parents

Whose love and affection

Made our life worth living

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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

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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

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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

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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

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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

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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

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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

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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

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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

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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.

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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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