A PLANT DESIGN PROJECT REPORT ON GASIFICATION OF 1000 Kg/Hr COAL
SESSION: 2007 – 2011 SUBMITTED BY
FARHAN SHAHZAD ASAD NOOR SALMAN AKBAR MAILK MUHAMMAD ZAHID
E08-CE-09 E08-CE-34 E08-CE-36 E08-CE-37
SUPERVISED BY PROF. DR. ABDULLAH KHAN DURRANI ENGR. ABDUL BASIT
INSTITUTE OF CHEMICAL ENGINEERING AND TECHNOLOGY UNIVERSITY OF THE PUNJAB LAHORE
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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. iii
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).
_____________________
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Dr. Abdullah Khan Durrani Professor of chemical engineering Institute of Chemical Engineering & Technology, University of the Punjab, Lahore.
Engr. Abdul Basit Lecturer Institute of Chemical Engineering & Technology, University of the Punjab, Lahore.
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In the name of Allah the Most Beneficent, THE Merciful
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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 v
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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
Coal Gasification .................................................................................................... 20 2.1
Chemical Reactions ......................................................................................... 21
2.1.1
Pyrolysis Reactions ................................................................................... 21
2.1.2
Gasification Reactions ............................................................................... 21
2.1.3
Acceptor Reactions ................................................................................... 22
2.1.4
Heats of Reactions .................................................................................... 22
2.1.5
Equilibrium Considerations ........................................................................ 23
2.1.6
Reaction Kinetics ....................................................................................... 23
2.2
Gasifier Types .................................................................................................. 24
2.2.1
Fixed-Bed Gasifier ..................................................................................... 24
2.2.2
Fluidized-Bed Gasifier ............................................................................... 25
2.2.3
Entrained-Flow Gasifier ............................................................................. 26 vi
2.3
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
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Commercial Gasifiers ....................................................................................... 28
Method Of Contacting ...................................................................................... 37
2.7.1
Fixed bed ................................................................................................... 37
2.7.2
Molten Bath ............................................................................................... 39
2.7.3
Entrained Phase ........................................................................................ 39
Material Balance .................................................................................................... 40 3.1
Material Balance On Dryer ............................................................................... 40
3.2
Material Balance On Fluidized Bed Gasifier ..................................................... 42 vii
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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
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
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
Instrumentation .................................................................................................... 107 6.1
Control ........................................................................................................... 108
6.1.1
Incentives ForChemical Process Control ................................................. 108
6.1.2
Elements OfControl System .................................................................... 109
6.1.3
Modes of Control ..................................................................................... 112
6.1.4
Selection of Controller ............................................................................. 113
6.2
Control Loops ................................................................................................. 114
6.2.1
Feed Back Control Loop .......................................................................... 115
6.2.2
Feed Forward Control Loop ..................................................................... 115
6.2.3
Ratio Control............................................................................................ 116 viii
6.2.4
Auctioneering Control Loop ..................................................................... 116
6.2.5
Split Range Loop ..................................................................................... 116
6.2.6
Cascade Control Loop ............................................................................. 116
6.3
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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
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
2.2%
381
12.7%
167
23.4%
>500
5.8%
246
29.7%
147
100%
216
South and Central America Europe Former Soviet Union Africa and Middle East Asia/Pacific World
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 Table 1.2Brown coal, lignite, and sub-bituminous coals are called low-rank coals, 1
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.) 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 2
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 7078% carbon, 4.5-5.5% hydrogen and about 20% oxygen. The air dried moisture is 1020%, 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. 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%) 3
and the carbon content varies from 75-90% whereas the volatile matter content is 2045%. 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 (8595%) 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 80008500 kcal/kg which is slightly lower than that of bituminous coal due to its lower hydrogen content.
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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
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 5
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
O
C. 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. 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 6
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. 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.
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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 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, 8
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
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Table 1-3: Particle and Bulk Density
Fuel
Particle (true)Density 3
Bulk (apparent) Density
(kg/m )
(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 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
10
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 SiO 2/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 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. 11
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 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 12
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. 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] 13
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 coalfired 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 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
14
Table 1-4: Pakistan's Coal Reserves [4]
Coal Resources (million tonnes) Province/ coal field
Measured Indicated resources Interred resources 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
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
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
Balochistan
Punjab
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Table 1-5: Composition Of Different Coal Fields [4]
Province/Coal Field
Lakhra Sonda-Thatta Jherruk Ongar Indus East Meting-Jhumpir
Coal Quality Proximate Analyses (in percent) Moisture Volatile Fixed Ash Total Matter Carbon Sulphur
9.7-38.1 22.6-48.0
18.3 38.6 16.1-36.9
9.8-38.2 8.9-31.6
4.3-49 2.752.0
1.2-14.8 0.2-15.0
20.0-44.2
15.058.8 24.132.2
5.039.0 8.216.8
0.4-7.7
9.0-39.5
26.6-36.6
25.2-34.0
Heating Value (mmmf*) Btu/lb 5,503-9,158 8,878-13,555
2.9-5.1
8,800-12,846 5,219-11,172 7,782-8,660 7,734-8,612
Badin Thar
29.6-55.5
23.1-36.6
14.234.0
2.911.5
0.4-2.9
11,41511,521 6,244-11,054
Khost-ShahrigHarnai Sor Range-Deghari
1.7-11.2
9.3-45.3
9,637-15,499
20.7-37.5
0.6-5.5
Duki
3.5-11.5
32.0-50.0
Mach Abegum
7.1-12.0
34.2-43.0
Pir Ismail Ziarat
6.3-13.2
34.6-41.0
Chamalong-Bala Dhaka Salt Range
1.1-2.9
24.9-43.5
3.2-10.8
21.5-38.8
11,24513,900 10,13114,164 11,11012,937 10,78611,996 12,50014,357 9,472-15,801
Makarwal
2.8-6.0
31.5-48.1
Hangu/Orakzai
0.2-2.5
16.2-33.4
Cherat/GullaKhel
0.1-7.1
14.0-31.2
9.334.0 4.917.2 5.038.0 9.620.3 10.337.5 9.136.5 12.344.2 6.430.8 5.343.3 6.139.0
3.5-9.55
3.9-18.9
25.543.8 41.050.8 28.042.0 32.441.5 19.342.5 19.4478.1 25.744.8 34.944.9 21.849.8 37.076.9
Kotli
0.2-6.0
5.1-32.0
26.369.5
3.350.0
0.3-4.8
*mmmf
= moist mineral matter free
16
4.0-6.0 3.2-7.4 4.0-5.5 3.0-8.5 2.6-10.7 2.8-6.3 1.5-9.5 1.1-3.5
10,68814,029 10,50014,149 9,388142,171
7,33612,338
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 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.
17
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 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, 18
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]
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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 4. Temperature 5. Moisture content of the fuels 6. Mode of bringing the reactants into contact inside the gasifier etc.
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2.1 Chemical Reactions Many chemical reactions may occur in a gasifier, the three main types being 1. Pyrolysis reactions 2. Gasification reactions 3. 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
C+CO2
2CO
C + 2H2
CH4
Boudouard reaction:
Hydro gasification reaction:
21
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
CO + H2O
CO2 + H2
Shift reaction:
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
CaO + CO2
CaCO3
Carbon dioxide acceptor:
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 22
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, 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] 23
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 movingbed 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 0
(400-1100 C, 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 largescale 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, ashagglomerating 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 methanationare 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
3 Material Balance 3.1 Material Balance on Dryer
Feed (coal) F0
= 1000 kg/hr.
H2O = 0.3
Product Solids= 0.7 ROTARY
Moist remove H2O = 1 W
=?
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.
F1
= ?
Solids
= 0.94
H2O
= 0.06
DRYER
40
H2O balance IN
= OUT
300 = W + 44.68085106 W = 255.3191489 kg/hr. Table 3-1: 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
F3
F1 F2
GASIFIER
F4
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
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 3-2: Summary Of Material Balance On Gasefier
Stream
Mass In (kg /hr)
Mass Out (kg/hr)
F1
744.68
----
F2
190.013
F3
-----
F4
172.492
Total
1107.185
46
1107.185
1107.185
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
F5 SYN GAS ENTERING
F8 SYN GAS OUT
CYCLONE SEPARATOR
S2 SOLIDS
Inlet composition (outlet of gasifier=F5=1090.01743 kg/hr = 72.37014613 k mole/hr Solids= S1
= 30kg/hr
Solids outlet=S3
=?
Solids separated= S2
(assumed) [10]
=?
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= 49
24 kg/hr
Kg of solids Remain in gas
=S3 = S1-S2= 6 kg/hr
Flow rate of gas exiting separator= 1066.01743 kg/hr Table 3-3: Summery Of Material Balance On cyclone separator
Material
Flow Rate(Kg/hr)
solids removed S2
24
Gases leaving cyclone
1066.017
separator F8 solids in gas stream S3
6
50
3.4 Material Balance on Scrubber H2O IN L1
G2 SYN GAS OUT
G1 SYN GAS IN
H2O + CO2 OUT L2 + SOLIDS
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 3-4: 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
SELEXOL IN Fin 298 K
250 K
Gin SYN GAS IN
Go SYN GAS OUT
210 K
258 K
F out SELEXOL + H2S OUT
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 H2S removed = 0.9×H2S in gas
= 90% =1.33874847 kg/hr
Mass flow rate of gas out =G0= Gin – H2S removed 54
=1060.05435kg/hr
To find out flow rate of selexol, we have to apply energy balance around H 2S absorber for gas = 2.05 kJ/kg0C [11]
Cp of gas 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 3-5: 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 F6 H2O IN
HEAT EXCHANGER
F3 SYN GAS IN
F7 STEAM OUT
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
F5 SYN GAS OUT
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 Temp of water out
for 70% efficiency
=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
Air + Moist air + moist = 255 kg/hr T2= 317 K
Feed (coal)
Product
DRYER F1 = 744.68kg / hr
F0 = 1000kg/hr
T3 = 303K
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
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)
Eq no
2
= 30A kW Heat Out Heat out by A+W
Q2 = F2 × C P2 ×∆T C P2 = ( C PA + C PW )/2 = 2.5845 KJ/kg-K
Q2 = ((A+ 255/3600) (2.5845) (317 - 298)) Q2 = 49.1 (A+ 0.0708)
Eq no
3
61
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
1100 K
F4 STEAM
F3 SYN GAS OUT
P=1 ATM T=1200K GASIFIER
F2 O2
F1 COAL
353 K
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
64
KJ/k mole of carbon
Table 4-1: 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
H2O IN AT T7
SYN GAS OUT AT T6
SYN GAS IN AT T5
H2O + CO2 OUT + SOLIDS AT T8
Temperature of gases entering scrubber
= T5 = 363 K
Cp of product gas= Cp=2.75509 KJ/kg .k Cp of water Temperature of water entering scrubber
= CpW =4.18KJ/kgk =
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
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
values are
5 Equipment Design 5.1 Fluidized Bed Gasifier Design [13] (From chemical process equipment by couper)
VESSEL HEIGHT GASIFIER
VESSEL DIAMETER 0.39407 m
Weight of mixture of particles
=744.68 kg
Bed is supposed to hold Density of particles= ρp Volumetric flow rate of gas
= 1700 kg/m3 = 0.03718 m3/sec 69
8.79 m
Viscosity of fluidizing gas (O2)
= 0.02018 Cp = 0.00002018 N sec/m2 =1.42902kg/m3
Density of O2 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 5-1: specification data sheet of gasefier
Equipment No. 1 Function: Gasification of Coal GASIFIER
Sheet No. 1 Operating Data
Height
8.78m
No. of Units
Type
1
Fluidized Bed
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
DIAMETER OF SHELL 552.9 mm
HEAT EXCHANGER
LENGTH OF TUBES=4.88 m
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 Specific heat of water
= T4 =610.75 oC = 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 Tubes per pass = Tpp
= 0.00020096 m2 = 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 = 2940.383565 kg/sec.m2
UtH20
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 Density of gas
=ρ
=0.01258589 Ns/m2 = 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 5-2: specification data sheet of heat exchanger
Equipment No.2 Heat exchanger
Function: Steam Generation Sheet No.2 Operating Data
Size
61.101 m2
Type
Shell and tube
Performance Unit Shell Side
Tube Side
Water
Hot Gases
Fluid Circulating In
Out
In
Out
Gases
-
-
1090.017kg/hr
1090.017kg/hr
Water
512.195kg/hr
512.195kg/hr
-
-
298K
883.9k
1100k
363k
Temperature Pressure Drop
1.9×1014N/m2
9.6×1011 N/m2 Construction of Shell
No of Tubes Tubes
Pitch Outside Dia
Shell
Dia
133 0.0375m
Length
4.8m
Inside Dia
16mm
30mm
-------
------
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 =0.04448 m2
Ai
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 Z C L C Q D C
U
0.2 0.0444 0.3334 9.8 3.14 2.667 Q0.669 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 5-3: particle size distribution in cyclone separator
Particle size
50
40
30
20
10
5
2
90
75
65
55
30
10
4
µm
Percentage by weight less than
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 5-4: calculated performance of cyclone
Particle
% age in
Mean
efficiency
Collected
Grading
% At
size
range
particle
at scaled
At exit
exit
size/scaling
size (fig
Percent in range×efficency/100
factor
10.46a vol 6)
Percent in range collected
>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
28.8
99.02
Efficiency= 71.2
89
12. Pressure drop calculations From 10.44 a & b Coulson vol 6 pg 450 = 0.0254863 m2
Area of inlet duct= A1
Cyclone surface area = As =2.880739093m2 fc taken as= fc ψ
=fc×As/A1
ψ
= 0.565154435
= 0.005
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 5-5: specification data sheet of cyclone separator
Equipment No.3 Cyclone Separator
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
Lower 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
Diameter of Dust Collector
0.25m
Length of Lower Section
1.6672m
92
5.4 Design Of Scrubber
SCRUBBER HEIGHT 80.84 m
DIAMETER 0.49838 m
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
Temp of liq in
= 298 k 93
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 K4 = 1.9
for 42mmH2O/m packing 94
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)
aw/a=1-(exp((-1.45)×((бc/бL)^0.75)×((Lw×/(a×µL))^0.1)×(((Lw×^2×a)/(ρL^2×g))^95
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 KG/a=3.99745E-07 96
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 5-6: specification data sheet of scrubber
Equipment No.3 Scrubber
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
ABSORBER HEIGHT 26 m
DIAMETER 0.59 m
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]
Equipment No.4 Absorber
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
TC
SYN GAS OUT
H2O IN
TT
HS
GASIFIER
TT
TT
COAL SET POINT
FT
H20 OUT DESIRED RATIO
FC
FT
O2
OXYGEN
Figure 5: Control loops on gasefier
118
6.3.2 Control Loop On Compressor SYN GAS OUT FT
COMPRESSOR
FC
SYN GAS IN
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 SELEXOL IN
GAS OUT
GAS IN
FC
FT
SELEXOL OUT
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
COLD H2O IN
TT
TC
TT
TT
HOT SYN GAS IN
HEAT EXCHANGER
TT
TT STEAM
Figure 8: Control loop on heat exchanger
121
SYN GAS OUT
Symbol Used
Description
TT Temperature Transmitter
TC Temperature Controller
TTTTT
Flow Transmitter
FT
FC FC
Flow Controller
PT
Pressure Transmitter
PC
Pressure Controller
SC
Speed Controller
Low Selector Switch
LSS
122
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
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 $ Purchased cost in 2011 Cost in 2004 /cost in 2011=cost index in 2004/cost index in 2011
124
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 As material of construction is carbon steel the purchased cost can be calculated using following Method
126
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 $ Total purchased cost of equipment (PCE)
127
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
PCF (FLUID)
t ,total purchased cost 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
AS 128
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 $ Laboratory cost
=0.22×Operating labor 129
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 7-1: 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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15. Coulson, J.M. and Richardson,J.F. Chemical Engineering.4th Edition Volume 6. s.l. : Butterworth Heminann, 1991. 16. Kern, D.Q. Process Heat Transfer. s.l. : Mc-Graw Hill, 2000. 17. Stephanopoulos, George. Chemical Process Control. s.l. : Elsevier. 18. Perry, R.H and D.W. Green. Perry's Chemical Engineering Handbook , 7th Edition. Newyork : Mc-Graw Hill, 1997. 19. A, Smith and Carlos and Corripio, Armando B. Principle And Practice of Automatic Process Control. .
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