Bachelor Thesis Project 2010
CERTIFICATE
This is to certify that the project entitled “Techno-Economic Feasibility Studies and plant
design for Mercury Removal from Naphtha using adsorption” which is hereby presented by
Mr. Anirudh Arun in partial fulfillment of the requirements of the award of the degree of
Bachelor of Technology at the Indian Institute of Technology, Roorkee, is a genuine account of
his work carried out during the period from Oct 2009 to May 2010 under my supervision and
guidance.
Date: 19 -05-2011 (Dr. Vijay Kumar Agrawal)
Department of Chemical Engineering
Indian Institute of Technology, Roorkee
Roorkee – 247 667
India
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Bachelor Thesis Project 2010
ACKNOWLEDGEMENT
It is with a deep sense of gratitude and indebtedness that I express my sincere gratefulness to
my project guide Dr. Vijay Kumar Agrawal, Professor, Department of Chemical Engineering,
Indian Institute of Technology, Roorkee under whose able guidance, constant supervision and
encouragement, this work has been accomplished. I thank him for taking time out of his busy
schedule and aiding us with his priceless suggestions, encouragement and cooperation, which
in turn helped us, enhance the scientific merit of the present project work. Without his
guidance and mentorship, this work would never have reached its completion. The constant
motivation and support from him made us understand the depths of various techniques and
processes being used in the current scenario in the context of mercury removal, environmental
standards and adsorption.
I would also like to convey my heartfelt gratitude to Dr. Prasenjit Mondal, Assistant Professor,
Department of Chemical Engineering, Indian Institute of Technology, Roorkee for his never
ending support and help throughout the course of the project. I thank him for helping us
overcome many difficulties and perfect several processes.
I would like to take this opportunity to thank Dr. Amit Kumar Dhiman, Assistant Professor,
Department of Chemical Engineering, Indian Institute of Technology, Roorkee for motivating us
with constant appreciation and appraisal.
I would also thank my Institution and entire staff of Central Library, IIT Roorkee who provided
me with facilities for various books, research papers and internet.
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Date: 19/05/2011 (Anirudh Arun)
Place: Roorkee
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LETTER OF TRANSMITTAL
Ref. No. SYNTECH Gas Corp Ltd./Plant/Design/2010–01
Date: 20/05/2010
The General Manager
M/S SYNTECH Gas Corp. Ltd.
Subject: Techno-economic feasibility report on the coal based syngas production.
Dear Sir,
I thankfully acknowledge the receipt of your letter ref. no. SYNTECH Gas Corp.
Ltd./Plant/Design/2010 dated October 15th, 2010. I am sending you the techno-economic
feasibility report on the manufacture of 2375 TPD syngas for your kind perusal.
After making a detailed survey and study of various processes available, it has been concluded
that the production of syngas from High Temperature Winkler using coal as raw material is
best suited for your case. Exhaustive study of the process design and economics has been done
and the results say that the project is both technically and economically viable.
The total capital investment required is Rs 2906004600 and the reference payback period is
2.82 years. The selling price of syngas is Rs.25.73/kg to give a 25% return on the investment
after payment of taxes.
Any query regarding the report or elaboration of any point is always welcome.
Assuring you of our reliable and best services.
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Yours truly,
Manoj Kumar
(Project Manager)
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Table of Contents
Certificate....................................................................................................................................................1
Acknowledgement.......................................................................................................................................2
LETTER OF TRANSMITTAL.............................................................................................................................3
Summary.....................................................................................................................................................7
Market Prospects Of The Product..............................................................................................................11
Project Details...........................................................................................................................................19
Introduction...........................................................................................................................................21
Project Definition...................................................................................................................................23
Raw Material.........................................................................................................................................35
Simulation Of The Plant.........................................................................................................................44
Material Energy Flow Information.........................................................................................................49
Process Flow Sheet With Detailed Equipment Specifications................................................................60
Operating Conditions And Safety Measures..........................................................................................81
Design...................................................................................................................................................91
Process Control And Instrumentation.................................................................................................128
Material Storage, Handling And Safety...............................................................................................135
Environmental Protection And Energy Conservation..............................................................................141
Environmenal Aspects:........................................................................................................................143
Energy Integration And Conservation:.................................................................................................147
Alternate Energy Resources.................................................................................................................152
Protection Measures...........................................................................................................................155
Plant Utilities...........................................................................................................................................161
Types Of Utilities:................................................................................................................................163
Water:.................................................................................................................................................164
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Refrigeration:......................................................................................................................................170
Electricity And Power Requirements:.................................................................................................170
Secondary Utilities:.............................................................................................................................170
Air, Oxygen, Nitrogen:.........................................................................................................................171
Site Selection...........................................................................................................................................173
Organizational Structure And Manpower Requirement...........................................................................181
Organizational Structure:....................................................................................................................183
Manpower Requirement.....................................................................................................................185
Organization Chart...............................................................................................................................189
Economic Evaluation And Profitability Of The Project...........................................................................191
References...............................................................................................................................................203
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Table of figures
Figure 1 Applications of Syngas...................................................................................................14
Figure 2 Relative consumption of methanol by usage (source: Methanol Institute website,
2007)............................................................................................................................................15
Figure 3 moving bed gasifier........................................................................................................25
Figure 4 fluidised bed gasifier......................................................................................................26
Figure 5 entrained flow gasifier...................................................................................................27
Figure 6 Comparison between different types of gasification.....................................................33
Figure 7 Uncoupled CFB gasification process...............................................................................44
Figure 8 setting plan of waste heat boiler....................................................................................94
Figure 9 Tube layout of waste heat boiler...................................................................................95
Figure 10 sectional view of waste heat boiler..............................................................................96
Figure 11 setting plan of Heat exchanger HE 01........................................................................100
Figure 12 Tube layout of Heat Exchanger 01.............................................................................101
Figure 13 Setting Plan of Heat Exchanger 02.............................................................................105
Figure 14 Tube Layout of Heat Exchanger 02............................................................................106
Figure 15 PID of Storage tank....................................................................................................131
Figure 16 PID of Storage Tank....................................................................................................132
Figure 17 PID of Absorber..........................................................................................................134
Figure 18 Flow sheet of Activated Sludge System......................................................................156
Figure 19 Typical two-stage Claus unit......................................................................................158
Figure 20 Typical COS hydrolysis flowsheet...............................................................................159
Figure 21 Coal Reserves in India................................................................................................175
Figure 22 Organizational Structure………………………………………………………………………………………..187
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Summary
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Gasification is a process that converts carbonaceous materials, such as coal, petroleum, biofuel,
or biomass, into carbon monoxide and hydrogen by reacting the raw material, such as house
waste, or compost at high temperatures with a controlled amount of oxygen and/or steam. The
resulting gas mixture is called synthesis gas or syngas and is itself a fuel.
The advantage of gasification is that using the syngas is potentially more efficient than direct
combustion of the original fuel because it can be combusted at higher temperatures or even in
fuel cells, so that the thermodynamic upper limit to the efficiency defined by Carnot's rule is
higher or not applicable. Syngas may be burned directly in internal combustion engines, used to
produce methanol and hydrogen, or converted via the Fischer-Tropsch process into synthetic
fuel. Gasification can also begin with materials that are not otherwise useful fuels, such as
biomass or organic waste. In addition, the high-temperature combustion refines out corrosive
ash elements such as chloride and potassium, allowing clean gas production from otherwise
problematic fuels.
Gasification of fossil fuels is currently widely used on industrial scales to generate electricity.
However, almost any type of organic material can be used as the raw material for gasification,
such as wood, biomass, or even plastic waste. Gasification relies on chemical processes at
elevated temperatures >700°C, which distinguishes it from biological processes such as
anaerobic digestion that produce biogas. But gasification of coal is very old. The earliest
practical production of synthetic gas (syngas) is reported to have taken place in 1792 when
Murdoch, a Scottish engineer, pyrolyzed coal in an iron retort and then used the product, coal
gas, to light his home.
Later on, Murdoch built a gas plant for James Watt, the inventor of the steam engine, and
applied the technology to lighting one of Watt’s foundries. The first gas company was
established in 1812 in London to produce gas from coal and to light the Westminster Bridge.
The syngas produced by gasification has mainly two uses- to generate electricity, as a chemical
feedstock in FT process to produce liquid fuels, in the production of fuel additives, including
diethylether and methyl t-butyl ether (MTBE), acetic acid and its anhydride.
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India has huge coal reserves. But most of the coal has high ash content and hence most of the
conventional gasification processes currently used in various countries are not suitable for
production of syngas using Indian coal. But recent technologies like Winkler gasifier which use
circulating fluidized bed technology can successfully process coals with high ash content up to
50%.
The new plant anticipated to be set up may have an environmental impact on the surrounding
villages albeit small. There may be certain hazards involved in the day-to-day operation of the
plant. Some air and water emissions are also expected.
The large quantities of water required as planned utility and its availability from a nearby river
apart from supply of raw material good connectivity and availability of cheap labour along with
the demand of syngas by the nearby industries validates the choice of our site in Talcher.
Cost, Profitability and employment
Plant capacity: 2375 TPD
Total Capital Investment: Rs 2906004600
Net Profit: Rs 726501151
Payback Period: 2.82 years
Syngas selling Price: Rs. 25.73
Return on investment: 25%
Percentage Break Even Capacity: 77.84%
Incubation Period: 2 yrs
Employment: 371
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Market Prospects of
the Product
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Syngas is the direct end-product of the gasification process. Though it can be used as a
standalone fuel, the energy density of Syngas is only about 50 percent that of natural gas and is
therefore mostly suited for use in producing transportation fuels and other chemical products.
As its unabbreviated name implies, Synthesis gas is mainly used as an intermediary building
block for the final production (synthesis) of various fuels such as synthetic natural gas,
methanol and synthetic petroleum fuel (dimethyl ether – synthesized gasoline and diesel fuel).
In a purified state, the hydrogen component of Syngas can also be used to directly power
hydrogen fuel cells for electricity generation and fuel cell electric vehicle (FCEV) propulsion.
The two chief components of synthesis gas, hydrogen and carbon monoxide, are the building
blocks of what is often known as C1 chemistry. The range of products immediately obtainable
from synthesis gas extends from bulk chemicals like ammonia, methanol and Fischer-Tropsch
products, through industrial gases to utilities such as clean fuel gas and electricity. Furthermore,
there are a number of interesting by-products such as CO2 and steam. As can be seen from
above figure many of these direct products are only intermediates towards other products
closer to the consumer market, such as acetates and polyurethanes.
Synthesis gas is an intermediate that can be produced by gasification from a wide range of
feedstocks and can be turned into an equally wide range of products. Given that this broad
range of products is available from the single intermediate of synthesis as, there is no technical
reason why more than one product could not be produced from the same gas source. In fact,
many operators of gasification plants do precisely this. This is known, in an analogy with co-
generation (electricity and heat), as polygeneration. Some even go a step further and install
surplus downstream capacity compared with the available syngas generation capacity.
In this manner, such operators are able to “swing” production from one product (say,
ammonia) to another (say, methanol), or peak power in accordance with market demand, and
are thus in a position to optimize revenue from the gasification plant. In a reverse manner,
there are other operators using different feedstocks and even, where appropriate, different
technologies to generate their syngas. In such a case, the opportunity is to work with the
cheapest feedstocks, topping up with more expensive ones only as required.
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This inherent flexibility associated with syngas production and use provides a multitude of
choices that is increased by the variety of utility systems, in particular the broad possibilities for
steam system configuration. It is therefore useful to look at some typical gas-processing designs
for a number of the commoner applications and review the considerations behind them.
Figure 1 Applications of Syngas
Ammonia:
Over 90% of the world’s ammonia production capacity of 160 million t/y in 2001 was based on
steam reforming of natural gas or (in India) naphtha. Almost all the rest, some 10 million t/y,
was based on gasification of either coal or heavy oil.
The worldwide production of ammonia is, by most measures, the largest of any bulk chemical.
The principle use of ammonia is as nitrogenous fertilizer for agriculture.
Process of production:
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Oxygen and nitrogen are manufactured in the ASU, where the compressors are all driven by
condensing steam turbines. The oxygen is pumped in the liquid phase to a pressure of 80 bar
and evaporated with gaseous nitrogen, which returns the cryogenic energy to the cold box. The
vacuum residue is gasified in the partial oxidation reactor with oxygen and steam at 60 bar and
about 1300 ° C. The raw gas from the reactor contains soot and ash, which is removed in a
water wash. The raw gas, freed of solid matter, is cooled down to about 30 ° C in the Rectisol
unit, where it is washed with cold methanol to give a residual total sulfur content of less than
100 ppb . The sulfur-free gas is then heated up and saturated with water at about 220°C in a
saturator tower in the CO shift. Additional steam is added that reacts over the catalyst with
carbon monoxide to form hydrogen and CO2. The gas at the outlet of the CO shift has a CO slip
of about 3.2% and a CO2 content of about 34%. This gas re-enters the Rectisol unit and is
washed again with cold methanol, this time at about 60°C. The CO2 content is reduced to about
10ppm. The resulting gas is a raw hydrogen with about 92% H2 and about 5% CO, the rest being
nitrogen, argon and methane. This gas is cooled down to about −196°C and washed with liquid
nitrogen. Simultaneously, the amount of nitrogen required for the ammonia synthesis is added.
The gas is then compressed to the pressure required for the synthesis loop.
Methanol:
Approximately 3.3 million metric tonnes per year, or about 9% of the estimated world
methanol production, is based on the gasification of coal or heavy residues.
Methanol is an important intermediate and, as can be seen from below diagram,
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Figure 2 Relative consumption of methanol by usage (source: Methanol Institute website,
2007).
over half of the production goes into the manufacture of formaldehyde and MTBE (methyl
tertiary-butyl ether). The demand for methanol has varied substantially from year to year,
creating some dramatic price swings when supply has failed to keep up with demand.
The main considerations to be applied in developing a synthesis gas production scheme for
methanol manufacture are the same as for ammonia – namely selectionof gasification pressure,
syngas cooling arrangement, and acid gas removal system. Contrary to the ammonia case, the
optimization of oxidant quality is not a consideration, since any inerts in the syngas lower the
conversion in the synthesis. The oxygen should simply be as pure as reasonably possible, which
in effect means 99.5% purity.
Hydrogen:
The market for hydrogen is extremely diversified. The type of industry served ranges from
petroleum refiners with plants varying in size from 20,000–100,000 Nm3/h to the food industry
with requirements in the range of 1000 Nm³/h or less. Similarly, feedstocks and technologies
vary widely, the largest plants being based on steam reforming of natural gas or residue
gasification. At the smaller end of the scale, steam reformers can still hold their own, but
methanol or ammonia cracking and hydrolysis of water are also commercially available. An
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additional source is as a by-product of chlorine production. Inside refineries, much of the
hydrogen demand is met from the naphtha reformer.
The estimated total world hydrogen production (excluding ammonia and methanol plants as
well as by-product hydrogen) is about 16 million Nm³/h. Of this, over 500,000 Nm³/h is
produced by gasification. Practically all the gasification-based hydrogen production falls into the
category of “largeplants”, having capacities of 20,000 Nm³/h upwards. One of the largest is
Shell’s112,000 Nm³/h facility in its Pernis (The Netherlands) refinery. In China, two 2200 t/d
coal gasifiers are under construction to supply about 170,000 Nm³/h of hydrogen to a large
direct coal liquefaction plant. This reflects current economics, and in particular the
opportunities for resid-based hydrogen production in refineries.
A shift reactor is usually employed which increases the hydrogen content in the syngas
produced. It uses the water gas shift reaction in which steam is consumed in the reaction with
CO producing CO2 and H2
Carbon monoxide:
Pure carbon monoxide is a raw material for a number of organic chemicals, such as acetic acid,
phosgene (which is an intermediate for polyurethane manufacture) and formic acid. The toxic
nature of CO makes it difficult to store or transport. For safety reasons, inventories are usually
kept to a minimum, and thus pure carbon monoxide plants tend to be located close to the point
of use of the product and are accordingly fairly small. Approximately 500 kt/y of CO is used for
producing acetic acid.
Liquid fuels:
Virtually all modern coal gasification processes have been originally developed for the
production of synthesis gas for the subsequent production of chemical feed-stocks or
hydrocarbon liquids via Fischer-Tropsch synthesis. The only place in the world where the
process sequence coal gasification to Fischer-Tropsch liquids (CTL) is currently practiced is at
the Sasol complex in South Africa, although a number of projects are currently under
consideration in other parts of the world, such as the USA, China and Australia. For the
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production of SNG from coal, only one plant is in operation, in Beulah, North Dakota. For the
conversion of remote natural gas via partial oxidation and Fischer-Tropsch synthesis into
hydrocarbon liquids (GTL), one plant is currently in operation in Bintulu in Malaysia and another
under construction in Qatar. Other GTL plants in Qatar, Trinidad and South Africa use
autothermal reforming, steam reforming, or a combination of both.
The GTL option is especially attractive when low-cost natural or associated gas is available that
cannot be economically transported to markets either by pipeline or as liquefied natural gas
(LNG). In principle, there are two liquid products that can be produced: methanol and Fischer-
Tropsch (FT) liquids. For details about methanol, please refer to methanol section above.
Classically, two different FT synthesis process types are available: the ARGE and the Synthol
synthesis.
In the ARGE process, synthesis gas is converted into straight-chain olefins and paraffins over a
cobalt-containing catalyst at temperatures of about 200°C and pressures of 30–40 bar. The
reaction takes place in a large number of parallel fixed-bed reactors that are placed in a
pressure vessel containing boiling water for cooling and ensuring an essentially isothermal
process.
The product is subsequently hydrogenated in case straight paraffins are the desired product.
Such products are eminently suitable for the production of solvents and waxes, as the product
is completely free from sulfur and nitrogen compounds, as well as from aromatics. By adding an
acidic function to the hydrogenation catalyst, some iso-paraffins are also produced that
improve the low-temperature characteristics of the premium fuels that can be produced by the
ARGE process. Moreover the boiling range of the products can be controlled within a wide
range as the acidic function can be used for hydrocracking the heavier fractions.
In the Synthol process, synthesis gas is converted into an aromatic-rich product over an iron-
containing catalyst at temperatures of about 250°C and pressures of 30–40 bars. The reaction
takes place in large fluid-bed reactors. The product is rich in aromatics, and is used for the
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production of motor gasoline and as a diesel blending component. This process is being used at
the Sasol plant in Secunda and in Mossel Bay, both in South Africa.
In recent years, further developments have been made. The Shell SMDS process uses a fixed-
bed reactor similar to that of ARGE. Sasol has developed its advanced slurry-bed reactor. Such
three phase reactors (the solid catalyst, the liquid product and the syngas) have the advantage
of a very good temperature control. They have also been considered for methanol synthesis.
Exxon, BP and Statoil have demonstration plants in operation.
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Project Details
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4.1 INTRODUCTION
4.1.1 Problem statement and description
Objective of this report is based on requirement of Syntech gas Corporation Limited which
intend to setup a coal based syngas production plant which will meet the domestic and
international requirement of syngas. As a consultant project manager acting on behalf of client,
charge has been handed over to do a techno-economic feasibility study for coal based syngas
production of 2375 TPD capacity plant and to submit a report on the same. Feed to the plant is
high ash lignite coal obtined from coal mines of Talcher region which is owned by Mahanadi
coal fields limited.
4.1.2 Introduction to the format of the report
The complete report has been extended to a span of 10 chapters among the separate section
giving references. Each chapter deals with the specific aspect of the report
Chapter 1 contains the letter of transmittal which highlights the main features of the report.
This is followed by the contents of the report.
Chapter 2 contains a brief executive summary of the report characterising the salient features,
cost involved, employment potential, power and other utilities required and the profitability of
the project.
chapter 3 contains an introduction to the project and the format of the report it deals with the
complete description of the report, including the uses and present status of the product,
importance of the problem, available processes for the production, evaluation of alternative
processes, details of the selected process and raw material requirement with basic assumptions
made. The entire material and energy balance for the plant is then shown with all the
assumptions. Next is the detailed design of the process requirements and giving all the
literature references, mechanical design of three major equipment and their fabrication as per
BIS specification. Material storage and handling facilities covered next and the process
instrumentation and control of the entire plan is shown.
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In chapter 4 the environment issues including a solid and noise pollution of the plant along with
the remedial measures are covered. Also the methods for energy conservation and use of
alternate energy are suggested.
Chapter 5 elaborates upon the utilities that will be required for the plant. Primary utilities
include air for process instrumentation,heat transfer media, cooling water, air-conditioning and
electricity. The second utilities are safety, security etc
Chapter 6 deals with the proposed organizational structure and manpower requirements
including managerial supervisories and various categories of skilled, semiskilled and unskilled
workers along with their remunerations.
Chapter 7 has the market prospects of syngas. An analysis of the demand and supply of the
product of a last five years and the projected figures for the next five years are included. Status
and production in the country along with their comparisons all of the world is shown.
Possible site for the plant is suggested in chapter 8 taking full considerations of government
policies, transportational facilities, availability of raw materials and market accessibility. A
project layout showing location of the main plant, provision for future expansion, space for
storage of raw materials and product, administrative block, Facilities, pumphouse, Greenbelt
etc have been suggested in details.
Chapter 9 deals with the economic evaluation and profitability of the project. Total cost
including the fixed cost, but in capital requirements, preliminary and the operating expenses
have been calculated. Cash flow starts, breakeven point with graphical representation, and
justification of the selling price and the implementation schedule is covered next.
Finally the books and journals consulted are cited as a reference.
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4.2 Project Definition
4.2.1 Importance of the Problem:
Coal is one of the primary sources of energy, accounting for about 67% of the total energy
consumption in the country. India is the third largest producer of coal in the world. Also India
has the fourth largest reserves of coal in the world (approx. 267.21 Billion tonnes). Coal
deposits in India occur mostly in thick seams and at shallow depths. Noncoking coal reserves
aggregate 172.1 billion tonnes (85 per cent) while coking coal reserves are 29.8 billion tonnes
(the remaining 15 per cent). Indian coal has high ash content (15-45%) and low calorific value.
With the present rate of around 0.8 million tons average daily coal extraction in the country,
the reserves are likely to last over 100 years. The energy derived from coal in India is about
twice that of energy derived from oil, as against the world, where energy derived from coal is
about 30% lower than energy derived from oil.
India has scarcity of natural gas and syngas at the same time India has abundant non coking
coal reserves. The most efficient way of using this non coking coal reserve is coal gasification.
Buring of coal is a major contributor to the environmental pollution so its better to gasify the
coal to produce cleaner fuel rather than just burn the coal for steam generation.
Coal gasification is a process for converting coal partially or completely to combustible gases.
After purification, these gases - carbon monoxide, carbon dioxide, hydrogen, methane, and
nitrogen - can be used as fuels or as raw materials for chemical or fertilizer manufacture. From
the early 19th century until the 1940s almost all fuel gas distributed for residential or
commercial use in the United States was produced by the gasification of coal or coke. In the
1940s, the growing availability of low-cost natural gas led to its substitution for gases derived
from coal. Interest in coal gasification has been renewed, however, with recent predictions that
natural gas reserves in the United States will begin to diminish by 1980.
Coal gasification offers one of the most versatile and cleanest ways to convert coal into
electricity, hydrogen, and other energy forms. Coal gasification electric power plants are now
operating commercially in the United States and in other nations, and many experts predict
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that coal gasification will be at the heart of the future generations of clean coal technology
plants for several decades into the future. For example, at the core of the US Department of
Energys FutureGen power plant of the future will be an advanced coal gasifier.
The capability to produce electricity, hydrogen, chemicals, or various combinations while
eliminating nearly all air pollutants and potentially greenhouse gas emissions makes coal
gasification one of the most promising technologies for the energy plants of tomorrow.
Synergyst’s Market Analysis - Gasification of Coal & Its Importance in the Power Sector offers
valuable insight into this rapidly evolving sector and analyzes the industry on a microscopic
level. The report focuses on a basic overview of the coal market, an introduction to the process
of coal gasification, clean coal technologies, technological factors associated with the
procedure, regulatory frameworks, the commercial usage of coal gasification, statistics of coal-
fired power plants, and much more. The report focuses on the industry from both the
commercial application of this technology as well as the environmental and reliability aspect of
the same. Synergyst’s Market Analysis - Gasification of Coal & Its Importance in the Power
Sector is the complete information solution to this highly beneficial technology and the overall
industry.
4.2.2 Background Information/ Available Technologies
Gasification:
Gasification is a process for converting carbonaceous materials to a combustible or synthetic
gas (H2, CO, CO2, and CH4). In general, gasification involves the reaction ofcarbon with air,
oxygen, steam, carbon dioxide, or a mixture of these gases at 1,300F or higher to produce a
gaseous product that can be used to provide electric power and heat or a raw material for the
synthesis of chemicals, liquid fuels, or other gaseous fuels such as hydrogen. Once a
carbonaceous solid or liquid material is convened to gaseous state, undesirable substances such
as sulfur compounds and ash may be removed from the gas. In contrast to combustion
processes, which work with excess air, gasification processes operate at sub-stoichiometric
conditions with the oxygen supply controlled.
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In a gasification process the feedstock is hydrogenated. This means hydrogen is added to the
system directly or indirectly or the feedstock is pyrolyzed to remove carbon to produce a
product with a higher hydrogen-to-carbon ratio than the feed stock. The more hydrogen that is
added or the more carbon removed, the lower the overall efficiency ofthe synthetic gas
production process.
Production of Syngas by gasification:
Carbon gasification combines a carbon feedstock, high temperature and pressure in a
controlled limited-oxygen environment. Here an exothermic reaction occurs to produce
asyngas that is mainly composed of carbon monoxide and hydrogen. The major reactions
involved are as follows:
Steam gasification reaction:
C + H20 ↔ H2 + CO
C + ½ 02↔CO
Water shift reaction also takes place as follows
CO + H2O↔ CO2 + H2
The two carbon gasification reactions are the Boudouard reaction with CO2; and steam
gasification. These are endothermic reactions.
C + CO2 ↔ 2CO ΔH = 170 kJ/mol
C + H20 ↔ H2 + CO ΔH = 135 kJ/mol
The heat from the combustion reaction drives these gasification reactions.the gasification
reactions are important in that they allow reduction in the net oxygen consumed in the process
and produce the energy rich syngas components CO and H2
Types of gasifiers
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the coal gasification requires the presence of an oxidant in the process. Air or oxygen may be
used as an oxidant and the gasifiers are accordingly known as either air blown or oxygen blown
gasifiers.
1. Moving-bed: Sometimes also termed as fixed-bed easifier, it involves the coalmoving slowly
downwards as it is gasified by counter-current flow of synthesis gas. The oxygen consumption is
low but the pyrolysis products are present in the synthesis gas. It cannot accept coal with high
coking tendency.
Figure 3 moving bed gasifier
2. Fluidized-bed : It offers extremely good mixing between feed and oxidant, which promotes
both heat and mass transfer. An even distribution of material in the bed takes place and certain
amount of partially converted material is removed with the ash thus leading to a lower carbon
conversion efficiency.
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Figure 4 fluidised bed gasifier
3. Entrained-flow : It operates with feed and oxidant in co-current flow with a short residence
time It is advantageous due to its ability to handle practically any coal as feedstock and to
produce a clean. tar-free gas. It has a high C conversion efficiency (98-99.5%).
Figure 5 entrained flow gasifier
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Typical operating characteristics of the gasifiers are as follows:
Moving Bed Fluidized Bed Entrained Bed
Exit Gas temp (Celsius) 420-650 920-1050 1200
Coal Feed size <50 mm <6mm Few micro meters will
Ash conditions Dry/Slagging Dry/Agglomerating slagging
Available Technologies
Indian coals have high ash content which creates problems for conventional gasification
technologies which use fossil fuel derived feedstock like petcoke.
The two technologies suitable for high ash coal gasification:
1. Lurgi gasification process
2. Circulating fluidized bed gasification process
Lurgi process
The Lurgi dry ash gasifier is a pressurized, dry ash, moving-bed gasifier. Sized coal enters the top
of the gasifier through a lock hopper and moves down through the bed. Steam and oxygen
enter at the bottom and react with the coal as the gases move up the bed. Ash is removed at
the bottom of the gasifier by a rotating grate and lock hopper. The countercurrent operation
results in a temperature drop in the reactor. Temperatures in the combustion zone near the
bottom of the gasifier are in the range of 2000°F, whereas gas temperatures in the drying and
devolatization zone near the top are approximately 500 to 1000°F. The raw gas is quenched
with recycled water to condense tar. A water jacket cools the gasifier vessel and generatespart
of the steam to the gasifier. Sufficient steam is injected to the bottom of the gasifier to keep the
temperature below the melting temperature of ash.
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Bachelor Thesis Project 2010
Disadvantages of lurgi process:
1. Production of tar along with syngas which would require further purification
2. Presence of moving parts which leads to wear and tear of the equipment
3. Steam consumption is relatively higher as the operating temperature is high (>1300 C
for slagging types)
4. Increased heat losses due to higher temperatures
5. Production of by-products is higher which reduces efficiency
FLUIDIZED-BED TECHNOLOGIES
We have examined a few fluidized technologies. The popularity of fluidized bed combustion is
due largely to the technology's fuel flexibility - almost any combustible material, from coal to
municipal waste, can be burned - and the capability of meeting sulfur dioxide and nitrogen
oxide emission standards without the need for expensive add-on controls. Reagents like
limestone are added, and temperatures are controlled to directly capture the sulfur and reduce
formation of Nitrogen Oxides.
HTW process:
The High Temperature Winkler (HTW) process was first developed by Rheinbraun in Germany
to gasify lignites for the production of a reducing gas for iron ore. The gasifier consists of a
refractory-lined pressure vessel equipped with a water jacket. Feedstocks are pressurized in a
lock hopper, which is located below the coal storage bin and then pneumatically conveyed to a
coal bin. The conveying gas is then filtered and recirculated. Coal in the receiving bin is then
dropped via a gravity pipe into the fluidized bed, which is formed by particles of ash, semi-coke,
and coal. The gasifier is fluidized from the bottom with either air or oxygen/steam, and the
temperature of the bed is kept at around 800°C, below the fuel ash fusion temperature. An
additional gasification agent is introduced at the freeboard to decompose, at higher
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Bachelor Thesis Project 2010
temperature (900 to 950°C), undesirable byproducts formed during gasification. The operating
pressure can vary from 1 to 3 MPa, depending on the use of the syngas. The raw syngas
produced is passed through a cyclone to remove particulates and then cooled. Solids recovered
in the cyclones are reinjected into the gasifier, and dry ash is removed at the bottom via a
discharge screw. The syngas cooling system has been the subject of study as to whether to use
a water-cooled or a firetube syngas cooler. The main reason was that the existing water-cooled
syngas cooler was facing fouling and corrosion problems. A conventional water scrubber system
was originally used for gas cleaning but due to blockages, fouling, corrosion, and also the high
operating cost of the system, Rheinbraun decided to develop a hot gas filtration system. A hot
gas ceramic candle unit formed of 450 candles was developed and operated for 15,000 hours.
The HTW technology manufactured by Rheinbraun was successfully applied for the synthesis of
chemicals (methanol) from lignites at Berrenrath, Germany, between 1986 and 1997. The plant
was shut down at the end of 1997 as, at the time, the process was no longer considered to be
economically viable. Another commercial plant has been operating in Finland since 1988,
essentially with peat for the production of ammonia. A 140 ton coal/day pressurized HTW
gasification plant was also commissioned and built at Wesseling, Germany, in 1989, to
supplement research and development of the HTW technology for coal use and particularly to
study its future application to an IGCC process for power generation.
The plant was designed for a maximum thermal capacity of 36 MW and was operated for 3
years either as an air-blown or an oxygen-blown gasification plant with pressures up to 2.5
MPa. A wide range of coals was tested in the Wesseling plant, including brown coals and a high-
volatile bituminous coal (Pittsburgh No. 8). The Wesseling plant provided the operational data
required to design a potential 300 MW commercial IGCC power plant (KoBra), which was finally
never built. However, there is presently a project to develop a 400 MW IGGC plant based on
the HTW technology (two units) to replace 26 existing Lurgi moving beds at Vresova in the
Czech Republic. The new HTW plant (80 ton/hour coal and pressures up to 3 MPa) should
operate on Czech lignite and will benefit from years of research and development at the
Wesseling and Berrenrath plants. In order to adapt the HTW technology to the Czech lignites
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Bachelor Thesis Project 2010
and also to the pre-existing Vresova IGCC plant (coal grinding plant, air separation unit,
wastewater treatment, and steam turbine), tests were performed by Rheinbraun in an HTW
bench-scale gasification unit and compared to results obtained with other coals in the same
benchscale unit and in a demonstration plant.
IDGCC:
The Integrated Drying Gasification Combined Cycle (IDGCC) technology was specifically
developed for the gasification of high-moisture, low-rank coals by Herman Research Pty Limited
in Morwell, Australia. The gasifier is a 5 MW air-blown pressurized fluidized-bed pilot plant that
is fed with coal from an integrated drying process. The feed coal is pressurized in a lock hopper
system and then fed into the dryer, where it is mixed with the hot gas leaving the gasifier. The
heat in the gas is used to dry the coal, while the evaporation of water from the coal cools down
the gas without the need of expensive heat exchangers. The gasifier operates at 900°C under
2.5 MPa air pressure. Chars and ash are collected at the bottom of the gasifier and from a
ceramic filter and burnt in a separate boiler. The final ash product is similar to that from a
conventional low-rank boiler. A wide range of low-rank coals could be processed in the IDGCC,
with only small changes in the operating conditions. Coals containing high levels of sulfur can be
processed with sorbents, such as limestone or dolomite, directly injected into the bed. This
would obviate the need for additional cooling of the gas to 40°C for sulfur removal from the
very high-moisture syngas. The extra cooling would have led to a very large energy loss from
water condensation and reduced mass energy for the gas turbine. It is expected that the IDGCC
could handle coals with lower moisture content and higher ash content. As the IDGCC plant is
based on a fluidized-bed gasification technology, it is then not recommended, as in most of the
fluidized bed technologies, for coals with relatively low reactivities and coals with low ash
melting points. When looking at environmental considerations and particularly at the concept
of CO2 removal and H2 production, the IDGCC, which produces a very moist syngas, can
provide the water for the shift reaction without robbing or much reduced robbing of the steam
cycle and may have potential for future development. It was reported that the IDGCC process is
more efficient and as a consequence more environmentally friendly (lower CO2 emission) than
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Bachelor Thesis Project 2010
conventional processes, and would be just slightly less efficient than an Australian black coal
IGCC process.
KRW:
Coal and limestone, crushed to below 1/4," are transferred from feed storage to the KRW
fluidized-bed gasifier via a lock hopper system. Gasification takes place by mixing steam and air
(or oxygen) with the coal at a high temperature. The fuel and oxidant enter the bottom of the
gasifier through concentric high-velocity jets, which ensure thorough mixing of the fuel and
oxidant and of the bed of char and limestone that collects in the gasifier. After entering the
gasifier, the coal immediately releases its volatile matter, which burns rapidly, supplying the
endothermic heat of reaction for gasification. The combusted volatiles form a series of large
bubbles that rise up the center of the gasifier, causing the char and sorbent in the bed to move
down the sides of the reactor and back into the central jet. The recycling of solids cools the jet
and efficiently transfers heat to the bed material. Steam, which enters with the oxidant and
through a multiplicity of jets in the conical section of the reactor, reacts with the char in the
bed, converting it to fuel gas. At the same time, the limestone sorbent, which has been calcined
to CaO, reacts with H2S released from the coal during gasification, forming CaS. As the char
reacts, the particles become enriched in ash. Repeated recycling of the ash-rich particles
through the hot flame of the jet melts the low-melting components of the ash, causing the ash
particles to stick together. These particles cool when they return to the bed, and this
agglomeration permits the efficient conversion of even small particles of coal in the feed. The
velocity of gases in the reactor is selected to maintain most of the particles in the bed. The
smaller particles that are carried out of the gasifier are recaptured in a high efficiency cyclone
and returned to the conical section of the gasifier, where they again pass through the jet flame.
Eventually, most of the smaller particles agglomerate as they become richer in ash and
gravitate to the bottom of the gasifier. Since the ash and spent sorbent particles are
substantially denser than the coal feed, they settle to the bottom of the gasifier, where they are
cooled by a counter-flowing stream of recycled gas. This both cools and classifies the material,
sending lighter particles containing char back up into the gasifier jet. The char, ash, and spent
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Bachelor Thesis Project 2010
sorbent from the bottom of the gasifier flow to the fluid-bed sulfator, where both char and
calcium sulfide are oxidized. The CaS forms CaSO4, which is chemically inert and can be
disposed of in a landfill. Most of the spent sorbent from the gasifier contains unreacted CaO.
Sulfur released from burning residual char in the sulfator is also converted to CaSO4. Pinon Pine
in Nevada is the only large-scale coal-based IGCC plant (100 MWe) that is using the KRW
technology, and it is also the only one that was designed with a 100% hot gas cleanup. The
demonstration plant, owned by Sierra Pacific Resources and sponsored by the U.S. DOE, has
had numerous problems. The gasifier had 18 start-ups, and all of them failed due to equipment
design. Successes in the project included operation of the combined cycle portion of the plant
at 98% availability, efficient removal by the hot gas filter of particulates from the syngas and
production of a good quality syngas for only 30 hours since the first syngas was produced in
1998. Sierra Pacific Resources, which owns the Pinon Pine power plant, was going to be sold to
WPS Power Development, but the sale has been suspended by the state of Nevada, which
placed a moratorium on the sale of power plants in the state.
ABGC:
The Air-Blown Gasification Cycle (ABGC) is a hybrid system that was developed at pilot scale
(0.5 ton/hour coal capacity) by the former Coal Technology Development Division of British
Coal. The gasifier is based on a spoutedbed design and is operated at pressures up to 2.5 MPa
and a temperature between 900 and 1000°C. Coal fed in the gasifier produces a gas with a low
calorific value of around 3.6 MJ/m3. Sorbents such as limestone are also injected into the
gasifier to retain up to 95% of the sulfur originally present in coal. Syngas is first cleaned in a
cyclone, then cooled to around 400°C and cleaned by a ceramic filter, to be finally burned and
expanded through a gas turbine. Only 70 to 80% of the fuel is gasified, and partially gasified
char and other solid residues (fly ash and sulphided sorbent residues) produced in the gasifier
are then transferred to an atmospheric pressure circulating fluidized-bed combustor (CFBC)
operating at a temperature of about 1000°C. Heat generated by the combustion of the char
supplies a steam cycle used to drive a steam turbine to supplement the electricity generation.
The ABGC process is forecast to have an efficiency of about 46 to 48%. The ABGC technology
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Bachelor Thesis Project 2010
was later purchased by Mitsui Babcock Energy Limited (MBEL), which produced in collaboration
with GEC Alsthom and Scottish Power PLC a design of a demonstration plant while being
supported by the European Commission under the THERMIE program. A wide range of UK coals
and international steam coals were studied for use in the ABGC. A laboratory at Imperial
College of Science Technology and Medicine in London studied the impact of several coal
characteristics on the gasification reactivity of some international traded coals in bench-scale
reactors that could mimic the behavior of single coal particles in the ABGC. Coal characteristics
studied included coal maceral composition and coal mineral matter composition.
BHEL:
A 168 ton coal/day capacity air-blown pressurized fluidized-bed gasifier IGCC pilot plant (6.2
MWe) was built at Hyderabad, India, following previous gasification tests in an 18 ton coal/day
capacity IGCC fluidized-bed gasifier pilot plant and in a 150 ton coal/day moving bed IGCC pilot
plant. The plant consists of a refractory lined reactor with a 1.4 m inside diameter in the bed,
expanding to a 2 m inside diameter at the upper section of the gasifier. Crushed coal (6 mm size
or below) is injected into the system via a lock hopper and a rotary coal feeder and then
pneumatically transported into the gasifier with a portion of the air used by the plant. The dry
granular ash produced during gasification is withdrawn from the bottom of the gasifier through
a water-cooled screw extractor and is discharged periodically through an ash lock system. Three
refractory cyclones operating in series are used for primary gas cleaning. Fines collected in the
first two cyclones can be recycled in the gasifier but there is also the possibility to collect the
cyclone fines, without recycling, through a lock hopper. The gasifier operates at a temperature
of 1000°C and pressure of 1.3 MPa to generate a coal gas with a net calorific value of 9.8 MJ/kg.
The 168 ton coal/day demonstration plant was commissioned in 1996 and has since undergone
a series of tests in standalone and in IGCC mode, operating for a total of 1200 hours until the
year 2000. The plant is designed for the gasification of Indian coals with a high ash content of
up to 42%.
Circulating fluidized bed gasification process
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Bachelor Thesis Project 2010
CFB gasification can be integrated into several power cycle configurations. Two primary
configurations are (1) partial gasification cycles and (2) full gasification cycles. Figure below
shows three applications of these cycles.
F
Figure 6 Comparison between different types of gasification
Taken from DOE article ‘The Importance of Fluid Bed Gasification Technology’ by RobertGiglio
Mani Seshamani
The pressurized full gasification application is similar to current IGCC plant configurations which
fully gasifiers the fuel, except using a low temperature, non-slagging CFB gasification process.
This configuration is limited to reactive fuels such as lignite or sub-bituminous coal.
The atmospheric gasification application is a repowering application, which allows solid fuel to
be converted into syngas for burning in an existing oil or gas boiler.
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Major Engineering Problems:
In the manufacture of synGas as in all the other major process industries, many operational
problems are encountered. These problems need to be tackled for the efficient working of the
plant. Some of the main problems faced for this plant are:
1. Improper treatment of boiler feed water can lead to formation of scales in the vessels such as
waste heat boilers, gasifier jacket, etc. The formation of scales leads to decrease in heat
transfer coefficient thus altering the exit temperature of the reactor which affects the whole
process. To prevent the formation of scales, proper treatment of feed water is necessary.
2. Water hammering may occur in the steam pipes due to the presence of constables in the
steam. To prevent the formation of this water hammer, adequate number of steam traps
should be provided.
3. The temperature in the gasifier needs to be closely monitored. If the temperature starts
getting out of hand, it has to be controlled by introduction of more steam into the reactor
which decreases the extent of reaction and thus brings down the exit temperature.
4. Presence of hydrogen sulfide which is highly corrosive gas corrodes gaskets and flanges.
Adequate compensation allowance must be provided to account for this phenomenon.
5. Gasifier temperature has to be closely monitored as an increase in the temperature may lead
to oxidation of incoming nitrogen whose oxides (NOx) are highly injurious to environment.
6. If the outlet temperature from the gasifier is high, it leads to the formation of highly toxic
compounds like COS, which will entail the provision of more purification units thus increasing
the cost.
7. High concentrations of oxygen are observed in the exit gas during practical runs. This is due
to the phenomenon of gas short circuiting through the bubble phase. Gas escaping through the
bubbles does not take part in the combustion and gasification reactions actively, thus a
considerable amount of oxygen escapes from the bed, contributing to the high oxygen content
in the exit gas.
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8. There exists a narrow zone (thickness< 5cm) just above the distributor where the oxidation
reaction is predominant. This can be termed as combustion zone. An increase in oxygen flow
corresponding to increasing feed rate causes extension of this combustion zone which leads to
deteriorated gas quality
4.2.3 Process Selection Criteria:
Advantages of Circulating fluidized bed gasification process:
Since the leading gasification technologies (Chevron/Texaco, Conoco/Phillips, and Shell) are all
entrained flow, high temperature (2600-2900 F), ash slagging gasification processes, the severe
process conditions are a major factor affecting the reliability of these systems. In contrast,
circulating fluid bed (CFB) gasification is a low temperature (under 2000 F), non-slagging
process which avoids these difficult process conditions. Gasifier refractory life is greatly
extended and instead of all the fuel entering through a single fuel injector, simple multiple drop
chutes are used for feeding the fuel to the gasifier. The entire process occurs at a uniform
temperature and the ash or char material is always dry, non sticky and flows freely when
fluidized.
A fluidizing grid and a primary cyclone are used to fluidize the gasifier solids and recycle them
back to the gasifier. The resulting flywheel of solids is circulated around this loop ensuring
uniform process conditions, high solids/gas mixing and most importantly, high solids residence
time. Unlike entrained flow gasifiers which have short solids residence times (about 1 second),
circulating fluid bed gasifiers can achieve solid’s residence times over 30 minutes, allowing
them to achieve high gasification yields at lower temperatures. Besides improving system
reliability, low temperature gasification processes are also inherently more energy efficient. The
gasification process is endothermic (absorbs heat) and ideally only the heat needed to maintain
the process at the optimum temperature should be generated. This heat is generated by
combustion of some of the syngas and char in the gasifier. The fluid bed process utilizes nearly
all the heat generated in the gasifier to support the gasification process since the process is
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Bachelor Thesis Project 2010
virtually adiabatic (no heat loss) and isothermal (uniform temperature). The conditions of the
syngas leaving the gasifier (under 2000 F, with dry char particulates) are mild enough for
practical and effective recovery of the sensible heat in the syngas.
However, for high temperature slagging gasification processes, the process temperature is set
high to ensure the melting and flow of molten ash. The heat used to melt the ash is lost since
the ash is cooled in a water pool without heat recovery. Further, the syngas leaving the gasifier
can still be above 2300-2500 F with the ash in its softened, sticky phase making heat recovery a
difficult and inefficient process. Like the CFB combustion process, the CFB gasification process
can also handle a wide range of fuels from high quality bituminous coal to lignite. However,
because of their low process temperature, CFB gasifiers cannot achieve high gasification yields
for less reactive fuels such as eastern bituminous coals, anthracite, and pet coke, limiting their
application to partial gasification processes. For more reactive fuels such as sub-bituminous
coal and lignite, CFB gasifiers can achieve very high gasification yields (over 95%) at these mild
conditions, resulting in a synergy between the technology and these fuels.
4.3 Raw Material
Specifications:
Coal, the raw material for gasification is transported from the mines in and around angul to the
plant location. As per the information received from EIL, angul coal normally has the below
composition:
Proximate Analysis:
Proximate analysis wt%
Volatile carbon 26.3
Fixed carbon 31.9
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Ash 34.3
Moisture 7.5
Ultimate Analysis:
wt% DAF
Ash 34.3 0
Moisture 7.5 0
C 44.4648 76.4
H 3.0846 5.3
N 1.1058 1.9
S 0.4074 0.7
O 9.1374 15.7
DAF – Dry ash free basis
Ash Fusion Properties:
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Bachelor Thesis Project 2010
Ash Analysis (Mass %)
Caking Properties:
Talcher Coal of the size -19+2.36 mm under pressure of inert atmosphere shows no caking
tendency.
Inorganic and Organic Sulphur Distribution:
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Bachelor Thesis Project 2010
As per the coal standards released by CIL (given below)
Most of the high grade coal (A,B) is imported from Indonesia and Australia. The Indian coal
normally available is D,E, and F.
Hence as per the data given the grade of the coal is F.
44
Grade Useful Heat Value
(UHV)
(Kcal/Kg)
UHV= 8900-
138(A+M)
Corresponding
Ash% + Moisture
% at (60% RH &
40 C)
Gross Calorific
Value GCV (Kcal/
Kg)(at 5% moisture
level)
A Exceeding 6200 Not more than 19.5 Exceeding 6454
B Exceeding 5600 but
not exceeding 6200
19.6 to 23.8 Exceeding 6049 but
not exceeding 6454
C Exceeding 4940 but
not exceeding 5600
23.9 to 28.6 Exceeding 5597 but
not exceeding. 6049
D Exceeding 4200 but
not exceeding 4940
28.7 to 34.0 Exceeding 5089 but
not Exceeding 5597
E Exceeding 3360 but
not exceeding 4200
34.1 to 40.0 Exceeding 4324 but
not exceeding 5089
F Exceeding 2400 but
not exceeding 3360
40.1 to 47.0 Exceeding 3865 but
not exceeding. 4324
Bachelor Thesis Project 2010
According to the Coal India Ltd., vide Price Notification No.CIL/S&M:GM(F): PRICING: 1181
Dated 15.10.2009, the ROM (run-of-mine) coal cost of grade F is 860 Rs per tonne.
The sales tax levied on the ROM coal is 4% and the transportation cost is normally 100 Rs per
tonne for a 25 km radius around the mine. This takes the price of the coal to 1000 Rs per ton.
Quantification
As calculated above the cost of coal used in the plant is Rs 1000 per ton. As the plant is
designed for 2500 ton per day capacity, this takes the material cost of coal used to 25 lakhs per
day.
Testing Method:
As the coal quantity used and stored is huge, testing is normally done on a random sample, a
few times in a week.
Some of the major properties of the coal are measured in the following way.
Moisture
Moisture is an important property of coal, as all coals are mined wet. Groundwater and other
extraneous moisture is known as adventitious moisture and is readily evaporated. Moisture
held within the coal itself is known as inherent moisture and is analysed quantitatively.
Moisture may occur in four possible forms within coal:
Surface moisture: water held on the surface of coal particles or macerals
Hydroscopic moisture: water held by capillary action within the microfractures of the
coal
Decomposition moisture: water held within the coal's decomposed organic compounds
Mineral moisture: water which comprises part of the crystal structure of hydrous
silicates such as clays
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Bachelor Thesis Project 2010
Total moisture is analysed by loss of mass between an untreated sample and the sample once
analysed. This is achieved by any of the following methods
1. Heating the coal with toluene Drying in a minimum free-space oven at 150 °C (302 °F)
within a nitrogen atmosphere
2. Drying in a minimum free-space oven at 150 °C (302 °F) within a nitrogen atmosphere
3. Drying in air at 100 to 105 °C (212 to 221 °F) and relative loss of mass determined
Methods 1 and 2 are suitable with low-rank coals but method 3 is only suitable for high-rank
coals as free air drying low-rank coals may promote oxidation. Inherent moisture is analysed
similarly, though it may be done in a vacuum.
Volatile matter
Volatile matter in coal refers to the components of coal, except for moisture, which are
liberated at high temperature in the absence of air. This is usually a mixture of short and long
chain hydrocarbons, aromatic hydrocarbons and some sulfur. The volatile matter of coal is
determined under rigidly controlled standards. In Australian and British laboratories this
involves heating the coal sample to 900 ± 5 °C (1650 ±10 °F) for 7 minutes in a cylindrical silica
crucible in a muffle furnace. American Standard procedures involve heating to 950 ± 25 °C
(1740 ± 45 °F) in a vertical platinum crucible. These two methods give different results and thus
the method used must be stated.
Ash
Ash content of coal is the non-combustible residue left after coal is burnt. It represents the bulk
mineral matter after carbon, oxygen, sulfur and water (including from clays) has been driven off
during combustion. Analysis is fairly straightforward, with the coal thoroughly burnt and the ash
material expressed as a percentage of the original weight.
Fixed carbon
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Bachelor Thesis Project 2010
The fixed carbon content of the coal is the carbon found in the material, which is left after
volatile materials are driven off. This differs from the ultimate carbon content of the coal
because some carbon is lost in hydrocarbons with the volatiles. Fixed carbon is used as an
estimate of the amount of coke that will be yielded from a sample of coal. Fixed carbon is
determined by removing the mass of volatiles determined by the volatility test, above, from the
original mass of the coal sample.
Chemical analysis
Coal is also assayed for oxygen content, hydrogen content and sulfur. Sulfur is also analyzed to
determine whether it is a sulfide mineral or in a sulfate form. Sulfide content is determined by
measurement of iron content, as this will determine the amount of sulfur present as iron pyrite
or dissolution of the sulfates in hydrochloric acid with precipitation as barium sulfate.
Carbonate minerals are analyzed similarly, by measurement of the amount of carbon dioxide
emitted when the coal is treated with hydrochloric acid.
An analysis of coal ash may also be carried out to determine not only the composition of coal
ash, but also to determine the levels at which trace elements occur in ash. These data are
useful for environmental impact modelling, and may be obtained by spectroscopic methods
such as ICP-OES or AAS
Physical and mechanical properties
Relative density
Relative density or specific gravity of the coal depends on the rank of the coal and degree of
mineral impurity. Knowledge of the density of each coal ply is necessary to determine the
properties of composites and blends. The density of the coal seam is necessary for conversion
of resources into reserves.
Relative density is normally determined by the loss of a sample's weight in water. This is best
achieved using finely ground coal, as bulk samples are quite porous. To determine in-place coal
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Bachelor Thesis Project 2010
tonnages however, it is important to preserve the void space when measuring the specific
gravity.
Particle size distribution
The particle size distribution of milled coal depends partly on the rank of the coal, which
determines its brittleness, and on the handling, crushing and milling it has undergone. Generally
coal is utilised in furnaces and coking ovens at a certain size, so the crushability of the coal must
be determined and its behaviour quantified. It is necessary to know these data before coal is
mined, so that suitable crushing machinery can be designed to optimise the particle size for
transport and use.
Float-sink test
Coal plies and particles have different relative densities, determined by vitrinite content, rank,
ash and mineral content and porosity. Coal is usually washed by passing it over a bath of liquid
of known density. This removes high-ash content particles and increases the saleability of the
coal as well as its energy content per unit volume. Thus, coals must be subjected to a float-sink
test in the laboratory, which will determine the optimum particle size for washing, the density
of the wash liquid required to remove the maximum ash content with the minimum work.
Floatsink testing is achieved on crushed and pulverised coal in a process similar to metallurgical
testing on metallic ore.
Abrasion testing
Abrasion is the property of the coal which describes its propensity and ability to wear away
machinery and undergo autonomous grinding. While carbonaceous matter in coal is relatively
soft, quartz and other mineral constituents in coal are quite abrasive. This is tested in a
calibrated mill, containing four blades of known mass. The coal is agitated in the mill for 12,000
revolutions at a rate of 1,500 revolutions per minute.(I.E 1500 revolution for 8 min.) The
abrasion index is determined by measuring the loss of mass of the four metal blades.
Special combustion tests
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Bachelor Thesis Project 2010
Specific energy
Aside from physical or chemical analyses to determine the handling and pollutant profile of a
coal, the energy output of a coal is determined using a bomb calorimeter which measures the
specific energy output of a coal during complete combustion. This is required particularly for
coals used in steam-raising.
Ash fusion test
The behaviour of the coal's ash residue at high temperature is a critical factor in selecting coals
for steam power generation. Most furnaces are designed to remove ash as a powdery residue.
Coal which has ash that fuses into a hard glassy slag known as clinker is usually unsatisfactory in
furnaces as it requires cleaning. However, furnaces can be designed to handle the clinker,
generally by removing it as a molten liquid.
Ash fusion temperatures are determined by viewing a moulded specimen of the coal ash
through an observation window in a high-temperature furnace. The ash, in the form of a cone,
pyramid or cube, is heated steadily past 1000 °C to as high a temperature as possible,
preferably 1,600 °C (2,910 °F). The following temperatures are recorded;
Deformation temperature: This is reached when the corners of the mould first become
rounded
Softening (sphere) temperature: This is reached when the top of the mould takes on a
spherical shape.
Hemisphere temperature: This is reached when the entire mould takes on a hemisphere
shape
Flow (fluid) temperature: This is reached when the molten ash collapses to a flattened
button on the furnace floor.
NOC (No-Objection Certificate) and other requisites:
The following steps are to be carried out to obtain a NOC cerificate from the Orissa govt
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Bachelor Thesis Project 2010
1. For starting Large Scale Industries, the entrepreneurs have to first apply/ file for
Industrial Licence/ Industrial Entrepreneurs Memorandum with the Secretariat for Industrial
Assistance in the Ministry of Industry, Government of India.
2. After obtaining the Industrial Licence/ IEM acknowledgment from Government of India,
for such Large-scale industries, which are not identified as highly polluting, entrepreneurs have
to apply to the Directorate of Industries and Commerce for Provisional No Objection Certificate
for setting up of their unit.
3. All proposals for setting up of H.T. Industries will be referred to the Electricity
Department for getting initial advice regarding the availability of power for the unit . In the case
of such industries provisional registration / NOC will not be issued unless the initial advice is
received from the Electricity Department.
4. All the entrepreneurs irrespective of their size of investment, may approach the
`Industrial Guidance Bureau (IGB) ` (Functioning in the District Industries Centre) for getting the
requisite clearances expeditiously.
5. The Regional office of the District Industries Centre will make available to the
entrepreneurs/ Industrialists, the prescribed application forms for obtaining clearances/
permissions from the various govt Departments
After commencement of regular production, the entrepreneurs have to approach the
Directorate of Industries and Commerce for getting commencement of Production Certificate to
avail other concessions.
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Bachelor Thesis Project 2010
4.4 Simulation of the Plant
Process simulation software
ASPEN Plus was selected for modelling the Plant. This simulation package has been used for
modelling coal and biomass power generation systems in many research projects [Wayne et.
al.]. It is a steady state chemical process simulator, which was developed at Massachusetts
Institute of Technology (MIT) for the US DOE, to evaluate synthetic fuel technologies. It uses
unit operation blocks, which are models of specific process operations (reactors, heaters,
pumps etc.). The user places these blocks on a flow sheet, specifying material and energy
streams. An extensive built in physical properties database is used for the simulation
calculations. The program uses a sequential modular (SM) approach, i.e. solves the process
scheme module by module, calculating the outlet stream properties using the inlet stream
properties for each block. ASPEN Plus has the capability to incorporate FORTRAN code, written
by the user, into the model. This feature is utilised for the definition of non-conventional fuels,
e.g. biomass, municipal solid waste (MSW), specific coals and for ensuring the system operates
within user defined limits and constraints. User models can be created in Excel or written using
Fortran and can be fully integrated into the ASPEN Plus flowsheet
Uncoupling the gasification process in gasifier
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Bachelor Thesis Project 2010
Figure 7 Uncoupled CFB gasification process
To model a CFB gasifier using ASPEN Plus, the overall process must be broken down into a
number of sub-processes. For example a model may include the following zones: drying and
pyrolysis, partial oxidation, and gasification. The modeler may choose to model each of these
zones separately or combine them in one unit. Simulation PFD shows the overall gasification
process broken down or uncoupled into its sub-processes. The drying and pyrolysis zone
simulates the first stage of gasification and produces char, H2, CO, CH4, CO2, H2O, other
hydrocarbons, and tars. These products are then either burnt or gasified. The partial oxidation
zone simulates the burning of char as well as some H2 and CO, which generates the heat
required for all the sub-processes. A percentage of the heat generated is lost from the system
and products other than heat from this zone include CO, CO2, and H2O. The third zone, the
gasification zone, simulates the gasification reactions, reactions such as the Boudouard, the
water–gas and the methanation. The products of both the partial oxidation and the gasification
52
Bachelor Thesis Project 2010
zone are fed into an additional zone. This zone sets the final syn-gas composition, which is
composed mainly of H2, CO, CO2 and some CH4. In this zone the chemical equilibrium of the
gasification reactions is restricted in order to give a realistic syn-gas composition. The final zone,
box 5, represents the CFB cyclone separator, which separates out and recycles the solids
entrained in the gas.
Modelling
Thermodynamic Properties
Thermodynamic Property methods selected for various sections
Gasifier section – RKS BM (Redlich-Kwong-Soave equation of state with Boston-Mathias
modification)
Scrubber, Absorber, Stripper section – ELECNRTL ( Electrolyte NRTL model with Redlich-
Kwong equation of state) (Ref-Aspen Plus Help)
Model description
The main model assumptions are: steady state conditions, zero-dimensional model, isothermal
(uniform bed temperature), drying and pyrolysis are instantaneous in a CFB [Moreea et al], char
is 100% carbon (graphite), all of the sulphur reacts to form H2S, only NH3 formed no nitrogen
oxides considered, cyclone separation efficiency is 95%, 2% carbon loss in ash [Li XT et al]. From
Simulation PFD, the stream ‘Coal’ was specified as a nonconventional stream and the ultimate
and proximate analyses were inputted. The stream thermodynamic condition and mass flow
rate were also entered. The block ‘BRKDOWN’ yields are set by a calculator block, which in turn
determines the mass flow of each component in the block outlet stream ‘ELEMENTS’. The
enthalpy of this stream will not equal the enthalpy of the feed stream ‘COAL’, as the enthalpies
of the individual constituents that make up a fuel do not equal the enthalpy of the fuel because
chemical bonds etc. are not taken into consideration. The function of the next block is to
simulate carbon conversion by separating out a specified portion of the carbon from the fuel.
Reported carbon conversion for CFB gasifiers in the literature ranged from 90 to 99% Before
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Bachelor Thesis Project 2010
this carbon can be mixed with the gas downstream it must be brought up to the gasifier
temperature, which is accomplished using the block entitled ‘HEATER’. The un-reacted carbon
represents solids contained in the product gas that must be removed by the CFB gasifier
cyclone or other solids removal steps downstream. In reality there would also be fly ash and
bed material entrained in the gas but these components cannot be modelled in ASPEN Plus.
Thus, in this model the solid carbon that remains in the syn-gas represents all solids. The
streams ‘ELEM2’, ‘OXIDANT’, and ‘RECYCLE’ enter the block ‘GASIF’, where pyrolysis, partial
oxidation, and gasification reactions occur. All the sulphur in the system reacts with H2 to form
H2S. Due to the low contents of sulphur in the fuel, inaccuracies of this simplification are
negligible. The simplification that only NH3 is formed and nitrogen oxides are omitted was
adopted in this work (ref). Char, which is a product of pyrolysis, is assumed to be 100% carbon
(graphite). Demirbasx reported the elemental analysis of various coal chars and the carbon
content ranged from 90.5 to 92.1 wt%, therefore the assumption is valid. Ash removal is
simulated in the model using the unit operation block ‘ASHSEP’. The material stream
‘TOGASIF2’ is fed to the unit operation block ‘GASIF2’, which is an ‘RGIBBS’ reactor. ‘RGIBBS’
reactors allow restricted equilibrium specifications for systems that do not reach complete
equilibrium. Specifying the temperature approach for each reaction results in restricted
equilibrium, which means that the syn-gas composition can be adjusted to match data reported
in the literature. The next block mixes the un-reacted carbon that was separated upstream with
the gas from ‘GASIF2’ and its product stream is fed to a separator that simulates the operation
of the CFB gasifier cyclone. The block ‘CYCLONE’ was specified so that it removes 95% of the
solid carbon from the gas stream. The bottom outlet stream from ‘CYCLONE’ with the stream
name ‘SOLIDS’ is composed of solid carbon only and is sent to a separator block ‘CSEP2’. The
top outlet stream, which is called ‘SYNGAS’, is composed of all the gases from ‘GASIF2’ and a
small amount of solid carbon (5% of the un-reacted carbon). This material stream represents
the final output, i.e. the product gas from the gasifier. ‘CSEP2’ splits the ‘SOLIDS’ stream into a
recycle stream ‘RECYCLE’, that is sent back through the gasifier, and another stream named
‘CLOSS’, which represents the carbon lost from the system in the ash. The recycle was added
because in a real CFB gasifier, inerts (bed material and fly ash) and un-reacted char are
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Bachelor Thesis Project 2010
collected in the cyclone and re-injected into the reaction zone of the gasifier via the return leg.
The ‘CSEP2’ split fraction is set by a calculator block using the specification that the ash exiting
the gasifier contains 2% carbon. The stream ‘CLOSS’ is then mixed with the ash in the block
‘ASH-CARB’. The stream ‘SYNGAS’ is fed to a cooler entitled ‘GASCOOL’ that cools the gas to the
required gas cleanup temperature of 350 C. The energy that would be lost through cooling
could be recovered by generating steam or by supplying heat for air preheating. The next Block
SCRUB simulates the scrubbing of cooled gas using water. In this column 13 stages were used
which was calculated in process design of Scrubber. After this scrubber temperature of syngas
decreases to 120 C and all sulfur coal dust has been removed. After the scrubber, syngas is
further cool down in Heat Exchanger COOL2 using water and the fed to absorber ABS where it
simulates the removal H2S and CO2 form the syngas. SYN2 which is clean gas coming out from
the absorber is sent for storage and H2S rich DEA is sent to Stripper STRP where H2S is removed
from the DEA and lean DEA is recycled to absorber.
Model Validation
The model was validated against a pilot plant to test data which was developed by Sotacarbo,
together with Ansaldo Ricerche, ENEA and the Department of Mechanical Engineering of the
University of Cagliari. The ultimate analyses for the sulcis coal are given in table below.They
reported results for experimental runs coal as input fuel. The input data for this run were
entered into the model and the predictions were found to be in good agreement with the
reported results.
Plant Run Data Sotacarbo pilot plant
Sulcis coal ultimate analysis [wt. %] Dry-based syngas composition [% vol.]
Carbon 53.17 CO 0.3103
Hydrogen 3.89 CO2 0.0254
Nitrogen 1.29 H2 0.1838
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Bachelor Thesis Project 2010
Sulphur 5.98 N2 0.4302
Oxygen 6.75 CH4 0.0297
Chlorine 0.10 H2S 0.0148
Moisture 11.51 COS 0.0008
Ash 17.31 Ar 0.0051
H2O 0.1177
Simulation Results (% Vol)
CO 0.3203
CO2 0.0247
H2 0.1854
N2 0.446
H2S 0.0156
Ar 0.0052
H2O 0.119
These results are quite close to actual conditions. Hence we can use this model for simulation
of coal gasification plant.
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Bachelor Thesis Project 2010
4.5 Material Energy Flow Information
4.5.1 Material Balance:
Whole plant is simulated in aspen plus and results has been taken from the simulation results.
Crusher: Assuming 50% moisture loss in
Feed in: 98958.33333 kg/hr
coal(kg/h) 98958.3333
3
Proximate Analysis, wt% kg/h
Fixed Carbon 31.9 31567.7083
3
Volatile Carbon 26.3 26026.0416
7
Ash 34.3 33942.7083
3
Moisture 7.5 7421.875
Ultimate Analysis(as received
basis),
wt% kg/h
Ash 34.3 33942.7083
3
Moisture 7.5 7421.875
C 44.4648 44001.625
H 3.0846 3052.46875
N 1.1058 1094.28125
S 0.4074 403.15625
O 9.1374 9042.21875
Product out: 98958.33333 kg/hr
Coal(kg/h) 95247.39583
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Bachelor Thesis Project 2010
Proximate Analysis, wt% kg/h
Fixed Carbon 0.331428571 31567.70833
Volatile Carbon 0.273246753 26026.04167
Ash 0.356363636 33942.70833
Moisture 0.038961039 3710.9375
Ultimate Analysis(as received basis), kg/h
Ash 0.356363636 33942.70833
Moisture 0.038961039 3710.9375
C 0.461971948 44001.625
H 0.032047792 3052.46875
N 0.011488831 1094.28125
S 0.004232727 403.15625
O 0.094934026 9042.21875
Moisture loss(kg/h) 3710.9375
Total mass in 98958.33333 kg/h
Total mass out 98958.33333 kg/h
Gasifier
Assuming 95% conversion , 2% loss of carbon in ash and 95% cyclone efficiency
Feed in: 186289.2656 kg/hr
Coal stream:
Coal(kg/
h)
95247.39583 kg/h
Ash 33942.70833 kg/h
Moisture 3710.9375 kg/h
C 44001.625 kg/h
H 3052.46875 kg/h
N 1094.28125 kg/h
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Bachelor Thesis Project 2010
S 403.15625 kg/h
O 9042.21875 kg/h
Steam(kg/h) 31666.7373 kg/h
Product out: 186289.2656 kg/hr
Assuming 95% conversion, 2% loss of carbon in ash and 95% cyclone efficiency
Syngas(kg/
h)
149808.4945 kg/h
CO 89849.4534 kg/h
CO2 12004.6947 kg/h
CARBON 1.19E-08 kg/h
N2 21230.9339 kg/h
NH3 1.0035239 kg/h
S 4.63093641 kg/h
H2S 408.624952 kg/h
O2 0.00988606 kg/h
H2O 19013.6825 kg/h
H2 4680.90382 kg/h
ARGON 2084.22496 kg/h
COAL 530.331895 kg/h
Ash 36480.98383 kg/h
COAL 4232.04853 kg/h
ASH 32248.9353 kg/h
Total mass in 186289.2656 kg/h
Total mass out 186289.4783 kg/h
Water scrubber:
Feed in: 197483.6434 kg/hr
59
Oxygen stream:
O2 stream(kg/h) 59375.1325 kg/h
N2 20191.1794 kg/h
O2 37099.7286 kg/h
Ar 2084.22449
5
kg/h
Bachelor Thesis Project 2010
Syngas(kg/
h)
149808.4945 kg/h
CO 89849.4534 kg/h
CO2 12004.6947 kg/h
CARBON 1.1909E-08 kg/h
N2 21230.9339 kg/h
NH3 1.0035239 kg/h
S 4.63093641 kg/h
H2S 408.624952 kg/h
O2 0.00988606 kg/h
H2O 19013.6825 kg/h
H2 4680.90382 kg/h
ARGON 2084.22496 kg/h
COAL 530.331895 kg/h
water 47675.1489 kg/h
Product out: 197483.6434 kg/hr
scrubbed
gas
165125.0546 kg/h
CO 89760.974 kg/h
CO2 11706.929 kg/h
CARBON 0 kg/h
N2 21213.3815 kg/h
NH3 0.9734371 kg/h
S 5.39E-35 kg/h
H2S 395.216505 kg/h
O2 0.00986818 kg/h
H2O 35285.9245 kg/h
H2 4680.90351 kg/h
ARGON 2080.74225 kg/h
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Bachelor Thesis Project 2010
water 32358.58881 kg/h
CO 88.4794375 kg/h
CO2 297.765622 kg/h
CARBON 1.19E-08 kg/h
N2 17.5524502 kg/h
NH3 0.0300868 kg/h
S 4.63093641 kg/h
H2S 13.4084475 kg/h
O2 1.79E-05 kg/h
H2O 31402.9069 kg/h
H2 0.00030895 kg/h
ARGON 3.48271072 kg/h
COAL 530.331895 kg/h
Component wise material balance
IN kg/h Out kg/h
CO 89849.4534 89849.45344
CO2 12004.6947 12004.69462
CARBON
1.1909E-08 1.1909E-08
N2 21230.9339 21230.93395
NH3 1.0035239 1.0035239
S 4.63093641 4.63093641
H2S 408.624952 408.6249525
O2 0.00988606 0.009886054
H2O 66688.8314 66688.8314
H2 4680.90382 4680.903819
ARGON 2084.22496 2084.224961
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Bachelor Thesis Project 2010
COAL 530.331895 530.331895
Total 197483.6434 197483.6434
Absorber:
Feed in: 545102.4546 kg/hr
Syngas(kg/
h)
165125.0546 kg/h
CO 89760.974 kg/h
CO2 11706.929 kg/h
N2 21213.3815 kg/h
NH3 0.9734371 kg/h
S 5.3862E-35 kg/h
H2S 395.216505 kg/h
O2 0.00986818 kg/h
H2O 35285.9245 kg/h
H2 4680.90351 kg/h
ARGON 2080.74225 kg/h
Product out: 545102.4546 kg/hr
62
DEA 3.80E+05 kg/hr
CO 7.69E-18
CO2 1.44E-02
CARBON 0
N2 1.12E-19
NH3 2.16E-04
S 0
H2S 1.95E-02
O2 3.10E-21
H2O 329774.338
H2 5.93E-35
ARGON 2.08E-16
DEA 50203.0279
Bachelor Thesis Project 2010
Component wise material balance
IN kg/h Out kg/h
CO 8.98E+04 89760.97402
CO2 1.17E+04 11706.94348
CARBON
0.00E+00 0
N2 2.12E+04 21213.38146
NH3 9.74E-01 0.97365267
63
Clean
syngas
116206.5107 kg/h
CO 83720.9354 kg/h
CO2 3872.82262 kg/h
CARBON 0 kg/h
N2 20122.1637 kg/h
NH3 1.20E-04 kg/h
S 0.00E+00 kg/h
H2S 3.70009399 kg/h
O2 0.00857813 kg/h
H2O 884.599325 kg/h
H2 4680.90296 kg/h
ARGON 1834.48607 kg/h
DEA 1086.89187 kg/h
Rich DEA 428895.9448 kg/h
CARBO-
01
6040.03862 kg/h
CARBO-
02
7834.12086 kg/h
CARBON 0.00E+00 kg/h
N2 1091.21776 kg/h
NH3 0.97353248 kg/h
S 0 kg/h
H2S 391.535937 kg/h
O2 1.29E-03 kg/h
H2O 364175.664 kg/h
H2 0.00055006 kg/h
ARGON 246.256181 kg/h
DEA 49116.1361 kg/h
Bachelor Thesis Project 2010
S 5.39E-35 0
H2S 3.95E+02 395.236031
O2 9.87E-03 0.00986818
H2O 3.65E+05 365060.2633
H2 4.68E+03 4680.90351
ARGON 2.08E+03 2080.742251
DEA 5.02E+04 50203.02797
Total 545102.4546 545102.4556
Stripper:
Feed in: 447700.2448 kg/hr
Rich DEA (kg/h) 428895.9448 kg/h
CO 6040.03862 kg/h
CO2 7834.12086 kg/h
CARBON 0 kg/h
N2 1091.21776 kg/h
NH3 0.97353248 kg/h
S 0 kg/h
H2S 391.535937 kg/h
O2 0.00129005 kg/h
H2O 364175.664 kg/h
H2 0.00055006 kg/h
ARGON 246.256181 kg/h
DEA 49116.1361
Steam 1.88E+04 kg/h
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Bachelor Thesis Project 2010
Product out: 447700.2448 kg/hr
Lean DEA stream:
Lean DEA 418952.5354 kg/h
CO 0 kg/h
CO2 1.76E-02 kg/h
CARBON 0 kg/h
N2 0 kg/h
NH3 2.66E-04 kg/h
S 0.00E+00 kg/h
H2S 2.40E-02 kg/h
O2 0 kg/h
H2O 374673.453 kg/h
H2 0 kg/h
ARGON 0 kg/h
DEA 44279.0405 kg/h
H2S stream:
H2S
stream
28747.7094
6
kg/h
CARBO-01 6040.03862 kg/h
CARBO-02 7834.10323 kg/h
CARBON 0.00E+00 kg/h
N2 1091.21776 kg/h
NH3 0.97326651 kg/h
S 0 kg/h
H2S 391.511947 kg/h
O2 1.29E-03 kg/h
H2O 8306.51105 kg/h
H2 0.00055006 kg/h
ARGON 246.256181 kg/h
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Bachelor Thesis Project 2010
DEA 4837.09557 kg/h
Component wise material balance
IN kg/h Out kg/h
CO 6.04E+03 6040.03862
CO2 7.83E+03 7834.120862
CARBON
0.00E+00 0
N2 1.09E+03 1091.21776
NH3 9.74E-01 0.97353247
S 0.00E+00 0
H2S 3.92E+02 391.5359361
O2 1.29E-03 0.00129005
H2O 3.83E+05 382979.9641
H2 5.50E-04 0.00055006
ARGON 2.46E+02 246.256181
DEA 4.91E+04 49116.13607
Total 447700.2448 447700.2449
4.5.2 Energy balance
Gasifier
Feed
Coal 313.15 K
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Steam 773.15 K
Oxygen 773.15 K
Specific Heat capacity data
Cp=a+b*T+c*T^2+d*T^3
Cp (sulfur) 22.75 J/K/mol
Cp (carbon) 8.508 J/K/mol
Steam 6.28E+0
4
J/mole
The above data is for temp 773.15 K
Energy in: 1.38811E+11J/h
A b C d
O2 1159366.51
9
mol/h 28.106 -
0.00000368
0.00001745
9
-1.065E-
08
H2O (g) 1759263.18
3
mol/h
N2 721113.550
1
mol/h 31.15 -0.01357 0.00002679
6
-1.168E-
08
Ar 52170.8259 mol/h 20.804 -
0.00003211
5.1665E-08 0
C 3666802.08
3
mol/h
S 12598.6328
1
mol/h
∫ CpdT n*∫ CpdT
15224.5660
3
17650852119 J/h
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1.10E+11 J/h
13440.5587
5
9692169032 J/h
9882.41269
3
515573632.1 J/h
128.8962 472636854.7 J/h
344.6625 4342276.282 J/h
Sum 1.38811E+11 J/h
Cp (sulfur) 22.75 J/K/mol
Cp (carbon) 8.508 J/K/mol
steam 8.26E+04 J/mol
The above data is for temp 1253.15 K
Species n A b C d
CO 3377799 30.869 -0.01285 0.000027892 -1.272E-08
CO2 287193.6523 19.795 0.073436 -0.00005602 1.7153E-
08
H2 2463633.59 27.143 0.0092738 -0.00001381 7.6451E-
09
H2O (g) 1111911.256
H2S 12650.92732 31.941 0.0014365 0.000024321 -1.176E-08
N2 798155.4107 31.15 -0.01357 0.000026796 -1.168E-08
Ar 54916.67109 20.804 -
0.00003211
5.1665E-08 0
O2 0.325199375 28.106 -
0.00000368
0.000017459 -1.065E-08
S 152.3334344
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C 21.48774582
Rxn ΔH (298K) ΔA ΔB ΔC ΔD
J/mol
C + ½ O2 ―› CO -110525 8.308 -1.29E-02 1.92E-05 -7.35E-09
C + O2―›CO2 -393509 -16.639 7.34E-02 -7.35E-05 2.79E-08
C + H2O ―›CO + H2 175305 17.261 -5.55E-03 3.50E-06 -1.45E-09
H2 + S ―›H2S -20630 -17.952 -7.83E-03 3.81E-05 -1.95E-08
69
∫ CpdT n*∫ CpdT
29499.4547
4
9466106729
8
53196.4654
9
1451380289
3
29166.7656 6826341224
8
8.73E+10
40595.1449
7 487887916.6
29085.1648
9
2205375761
7
19878.6490
7 1037085771
31862.0749
1 9843.449509
21729.6625
8126.4162
SUM 2.88296E+11
Bachelor Thesis Project 2010
∫ CpdT ΔH n n*ΔH
J/mol
6.255E+03 -1.043E+05 856438.7591 -8.9301E+10
2.055E+04 -3.730E+05 272833.9705 -1.0176E+11
1.988E+04 1.952E+05 2352470.291 4.5916E+11
-1.601E+04 -3.664E+04 12018.38094 -4.4031E+08
2.6766E+11
Net energy generated in the gasifier = 1.1818E+11 J
Energy balance on waste heat boiler
IN OUT
Streams Syngas from gasifier Cooled gas
Temperature, C 980 350
Pressure, bar 10 10
Enthalpy, watt -135507003 -180909759
Net heat transferred = 45402756watt
Energy balance on water scrubber
IN OUT
Streams Cooled gas water scrubbed gas water out
Temperature, C 350 30 120.5 128.6
Pressure, bar 10 10 9 9.5
Enthalpy, watt -180909759 -209822154 -252342100 -138389814
Net heat transferred = 1 watt
Energy balance on Absorber
IN OUT
Streams Scrubbed Gas DEA Clean gas DEA out
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Bachelor Thesis Project 2010
Temperature, C 40 39 39.3 35.6
Pressure, bar 10 10 9 9.5
Enthalpy, watt -282709084 -1.47E+09 -104305229 -1.65E+09
Net heat transferred = -403855watt
Energy balance on Stripper
IN OUT
Streams Rich DEA Steam Lean DEA Clean gas
Temperature, C 80 150 97.7 78
Pressure, bar 1 1 1 0.9
Enthalpy, watt -1.62E+09 -68895264 -1.63E+09 -57870391
Net heat transferred = -2.49E+04watt
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Bachelor Thesis Project 2010
4.6 Process flow sheet with detailed equipment specifications
Storage Tanks
Coal Storage Tank
Mass flow rate through tank = 98958.333 kg/h
Density of stream = 1500 kg/m3 (considering voidage etc.)
Volumetric flow rate = 65.97222 m3/h
For 10 days residence time and 80% filled up,
Capacity of tank required = (65.97222*10*24)/0.8 = 19791.67 m3 ~ 20000 m3
Assuming D/H = 2
= 20000
D = 37.06 m
& H = 18.53 m
Water Storage Tank
Mass flow rate through tank = 104500 kg/h
Density of stream = 1000 kg/m3
Volumetric flow rate = 104.5 m3/h
For 5 days residence time and 80% filled up
Capacity of tank required = (104.5*120)/0.8 = 15675 m3
Assuming D/H = 2
= 15675 m3
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Bachelor Thesis Project 2010
D = 34.17 m
& H = 17.09 m
Syngas Storage Tank
Mass flow rate through tank = 116206.5107 kg/h
Density of stream = 157.899 kg/m3 (@pressure = 15 bar)
Volumetric flow rate = 735.95 m3/h
For 5 days residence time and 80% filled up,
Capacity of tank required = (735.95*24*5)/0.8 = 110392.5 m3 ~ 120000 m3
Therefore, we will employ 6 storage tanks each of volume 20000 m3.
Assuming D/H = 2
= 20000
D = 37.06 m
& H = 18.53 m
Oxygen Storage Tank
Mass flow rate through tank = 37099.7286 kg/h
Density of stream = 5.0 kg/m3
Volumetric flow rate = 7419.946 m3/h
For 5 days residence time and 80% filled up,
Capacity of tank required = (7419.946*5)/0.8 = 46374.66 m3 ~ 50000 m3
Therefore, we will employ 2 storage tanks each of volume 25000 m3.
Assuming D/H = 2
= 25000
D = 39.92 m
& H = 19.96 m
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Bachelor Thesis Project 2010
Nitrogen Storage Tank
Mass flow rate through tank = 20191.1794 kg/h
Density of stream = 4.8 kg/m3
Volumetric flow rate = 4206.496 m3/h
For 5 days residence time and 80% filled up,
Capacity of tank required = (4206.496*5)/0.8 = 26290.6 m3 ~ 26000 m3
Therefore, we will employ 2 storage tanks each of volume 13000 m3.
Assuming D/H = 2
= 13000
D = 32.10 m
& H = 16.05 m
DEA Storage Tank
Mass flow rate through tank = 50203.0279 kg/h
Density of stream = 867.966 kg/m3
Volumetric flow rate = 57.84 m3/h
For 10 days residence time and 80% filled up
Capacity of tank required = (57.84*10)/0.8 = 722.9982 m3
Assuming D/H = 2
= 722.9982
D = 12.25 m
& H = 6.12 m
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Bachelor Thesis Project 2010
Crusher
Feed is conveyed to the gasifier and the first prerequisite is that it should be of suitable size (for
gasification). Coal is normally found in lumps and gyratory crusher would be the most suitable
for such sizes. But gyratory crusher reduces the lumps to sizes up to 25mm. This would be
further processed by a Rod mill which would reduce the particle to required size (0.1-2mm) .We
have assumed a 1% loss in each of the above equipments.
Coal Specifications:
Max size: 300 mm (normally found)
Gyratory Crusher (C01)
For safety sake, we have taken the largest particle size to be slightly higher than the maximum
coal size specified in the data obtained. The crusher reduces the size from 300mm to 25mm.
Input tonnage per min(T) =1.649306
dpa = 1 ft
dpb = 0.082 ft
work index Wi = 11.37
(taken from Table 20-4 of Perry’s Chemical Engineers Handbook, 7th edition)
Power required,
P = 1.468*T*Wi*(1
√d pb
− 1
√d pa
)
= 68.22805 HP
Taking crushing efficiency = 1%
(Assuming 1%, as it practically varies between 0.01 to 2%)
Actual power requirement = 6.822805 kHP
Rod mill (C 02)
Data
Data has been taken from ‘Advances in comminutionby S. KomarKawatra’ Pg389
Work index for Rod mill from Rod mill grindability test at 10 mesh = 13.2
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Bachelor Thesis Project 2010
*chemical process equipment and design- James R. Couper (Table 12.5, Pg:368)
dpa = 300 µm
dpb = 25000 µm
W=10∗13.2∗( 1
√d pa
−1
√d pb)kWh/st
Where dpa and dpb are in µm (st-short tonne)
To convert st to metric ton we multiply by 1.102
W = 6.78618 kWh/st = 7.4783 kWh/metric ton
Hence W = 7.4783*(2500/24) kWh = 778.997 kWh
Considering that actual power requirements are 30% more than theoretical
Power required =1012.696 kWh
Gasifier
Data:
Gasifier temperature = T = 980 oC = 1253 K
Gasifier pressure = P = 10 bar
Solid density (ρs) = 1684.62697 kg/m3
Gas viscosity = 3.075*10-5 Ns/m2
Average molecular weight of the gas = <M> = 24.67 gm/mol
Particle size, dp = 0.3 mm
Gas density (ρg)
P M
RT
= 4.031 kg/m3
( P= 10 bar)
Total gas volume = vol (O2) + vol (steam) + vol (N2) + vol (Ar)
1
n
ii
RTN
P
G=22591 m3/h
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Bachelor Thesis Project 2010
Cross sectional area of the gasifier = At = π*dt2/4
Minimum fluidization:
In general.
1/ 232
2
( )* *(33.7) 0.0408 33.7
p g s gp mf g d gd u
(from Kunii Levenspiel, page 73)
Thus
Minimum fluidization velocity, umf (positive root) = 0.0287 m/s
Also,
Minimum fluidization voidage, εmf = 0.56 (from table 3.3, Kunii-Levenspiel)
Vessel diameter:
We have,
4*
3600* *t
o
Gd
u
From above equation and limiting condition on the minimum velocity required for slugging, we
get:
dt = 3.99748 m
uo = 0.5 m/s
Thus, Total disengaging height, TDH/ dt = 1.5 m (Figure 3.16, , Kunii-Levenspiel )
TDH= 5.996 m
So, to avoid entrained solids to leave the gasifier, freeboard height > TDH.
Hence, total length of the gasiifer should be H = 1.5*TDH = 8.994 m
Now, Lf/Lmf = 1.2-1.4 (typical value for aggressive boiling beds)
Thus,
Lf/Lmf = (1- εmf)/(1- εm) = 1.2
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Bachelor Thesis Project 2010
εm = 0.633
Terminal velocity of particles:
p g tep
d uR
Now,
2 21/3( )4
[ ]225
s gt p
g
gu d
(for 0.4< Rep< 500)
= 1.02 m/s
Rep = 40.00414
Pressure drop:
O2 and Steam are introduced in the bottom of the gasifer.
Pressure drop across the gasifier bed corresponding to the fluidization velocity of 0.5 m/s is =
ΔPb = 250 mm H2O column
(From fig 3.6, Kunii-Levenspiel)
Distributor pressure drop = ΔPd = Max(0.1*ΔPb; 35 cm H2O)
ΔPd =3430 Pa
* *Re
t o gt
d u
= 2.62*105
Cd’ = 0.6 (From fig 3.12, Kunii-Levenspiel)
1/ 2
' 2 dor d
g
Pu C
= 24.7518 m/s
Fraction of open area in the distributor = (uo/uor) *100
= 2.02005 %
2* *
4o or or oru d u N
78
Bachelor Thesis Project 2010
Thus, substituting, we get:
dor (cm) 0.1 0.2 0.3 0.4 0.5
Nor (m-2) 25720.13 6430.033 2857.793 1607.508 1028.805
Since orifices that are too large are likely to cause uneven distribution of gases and those too
small can cause clogging, hence we choose,
Nor = 2858
dor = 3mm
Cyclone
Temperature of operation 980oC
Pressure of operation 10 bar
Volumetric flow rate of syngas (V=nRT/P) 22.279 m3/s
Density of gas at given conditions, ρg = 1.9934384 kg/m3
Density of solid particles, ρs =1684.62697 kg/m3
Taking velocity at the inlet of duct of 15 m/s, area of inlet duct = V/u
= 1.485 m2
(From Fig. 10.44b (CR, Vol 6) (considering a high throughput cyclone))
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Bachelor Thesis Project 2010
Standard cyclone dimension( high throughput cyclone)
(Ref: Fig 10.44, pg-452. C.R. Vol. 6, 4th Ed.)
Duct area = 0.75Dc*0.375Dc
Therefore, Dc = 2.298 m
Using the formula (Ref: pg 450, C.R. vol 6, 4th Ed.)
Scaling factor = 5.905434774
80
Bachelor Thesis Project 2010
Higher value
of particle size
range (μm)
Lower limit of
particle size
range (μm)
Percentage in
the mixture
Mean
particle
size/scaling
factor
efficiency((Ref:
pg. 451, Fig.
10.45 (b), C.R. vol
6, 4th Ed.)
collected
300 150 23.35
37.5889649
5 99.9 23.32665
150 125 20.91
22.9710341
4 99 20.7009
125 97 31.03
18.5438893
7 90 27.927
97 50 24.71
12.2790618
8 78 19.2738
Total
efficiency 91.22835
Calculation of Pressure drop
A1 = 0.75Dc*0.375Dc = 1.4852 m2
Cyclone surface area, As = π Dc *4.875 Dc
= 780.8802 m2
fc = 0.005
=0.272271363
=1.8
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Bachelor Thesis Project 2010
From fig. 10.47, Φ=1.3
u1 = V/A1 = 15 m/s
area of exit pipe= Ae = π (0.75Dc )2 /4=2.333 m2
u2 = V/Ae =9.549296586 m/s
(Ref: Eq 10.9, pg-453. C.R. Vol. 6, 4th Ed.)
= 23.4172855 millibars
Waste Heat boiler
Process Design of Waste Heat Boiler
Design has been done by using the standard software (ASPEN Exchanger Design and Rating
V7.1-aspen ONE) in design mode:
Shell size mm 1092.2
Tube length - actual mm 3048
Tube length - required mm 2406.8
Pressure drop, SS bar 0.12122
Pressure drop, TS bar 0.24505
Baffle spacing mm 647.7
Number of baffles 3
Tube passes 1
Tube number 1731
Number of units in series 1
Number of units in parallel 1
Ao/Ai ratio 1.21
Area actual effective m² 290.8
Area reqd., dirty m² 229.6
Baffle type Single segmental
82
Bachelor Thesis Project 2010
Tube OD mm 19.05
Tube ID mm 15.75
Shell OD mm 1117.6
Shell ID mm 1092.2
Shell passes 1
Re number liquid in, SS 2045.55
Re number vapor in, TS 48749.11
Re number vapor out, SS 79457.22
Re number vapor out, TS 71408.83
Heat Exchanger Specification Sheet:
83
Bachelor Thesis Project 2010
1092.2 / 3048 mm Type BEM 1 1m2 1
CC
/ / / // / / /
/ / / // / / /
Ao basedC
bar / / / /C
mmIn mm 1 / /
1 / /Nominal / /
OD 19.05 1.65 mm Length mm mm
ID OD mmCarbon SteelCarbon Steel-
Single segmental V mmmm
24 3573Flat Metal Jacket Fibe Tube Side Flat Metal Jacket Fibe-
R - refinery service kg
kg/skg/s
kJ/kg
kJ/(kg*K)W/(m*K)
Hor
Shell Side
2.125
0
180.09
kg/s
mPa*skg/m3
kg/s14.6603
4.190.607
Tube Side
041.6133 41.6133
0
syngas
PERFORMANCE OF ONE UNIT
014.6603
water
23.170.49987
Bundle
kg/(m*s2)Bundle exit
1117.6
40.56Cut(%d)
Exp.
Inlet647.7Spacing: c/c
Expansion joint
Tubesheet-stationaryFloating head cover
Filled with waterCode requirements ASME Code Sec VIII Div 1 TEMA classWeight/Shell 5197.8
755.65Type
Carbon Steel TypeBaffle-crossing
Intermediate
1
-
3.18
-152.4406.4
Baffle-longSupports-tube U-bend
Seal type-
Connections
Channel or bonnet
Tube No.
Carbon Steel 1092.2
609.6
Fluid allocationFluid nameFluid quantity, Total 14.6603 41.6133
0
Specific heatThermal conductivityLatent heat
Vapor (In/Out)LiquidNoncondensable
Temperature (In/Out)
Density (Vap / Liq)ViscosityMolecular wt, Vap
Dew / Bubble point
Molecular wt, NC18.01
0
179.84
Connected inSurf/shell (eff.)Shells/unitSurf/unit(eff.)
Size seriesm2290.8
parallel290.8
30 307.47 980 350
2012.8
19.4119.41
1.803
3.660.0272
1.860.03990.7998
3048
-
Plain 1731
30Tube typeShell
Tks-Carbon SteelMaterial
Avg
Bypass seal Tube-tubesheet joint
9020.3 13463.6
RhoV2-Inlet nozzleGaskets - Shell side
Floating head
-762 Bundle entrance
Type
-Channel cover -
NoneImpingement protectionTubesheet-floating
Tube patternPitch 23.81
Shell cover
10
0.1377
Size/rating
424.8 Clean 471.6
-Out
CONSTRUCTION OF ONE SHELLShell Side Tube Side
Transfer rate, ServiceHeat exchanged
bar
Design/Vac/Test pressure
PressureVelocity
m2*K/Wbar
10m/s
Design temperature
Pressure drop, allow./calc.
1
0.00011 0.00011
337.78 1015.56
kW
11.03162
MTD corrected44277.5
Sketch
0.00013
-
Fouling resist. (min)
- - 609.6
Number passes per shellCorrosion allowance
11.03162
335.4453.97
3.18
Dirty W/(m2*K)
1
3.760.0206
997.34
1
1.6560.085
66.220.25855 0.24505
9.75495
0.0456
0.12122
9.87878
T1
S1
S2
T2
Scrubber
Calculation Of Water Required
Gm = 149808.495 kg/h = 5490306.201 mol/h
y1=0.00272764
y2 =2.72764E-05
y1/y2=100
optimum value of m*Gm/Lm = 0.75(Ref: Coulson Richarson vol 6)
84
Bachelor Thesis Project 2010
NOG =13 (from Fig. 11.40 Coulson Richarson vol 6)
m =0.362 Ref: Gas purification By Arthur L. Kohl, Richard B. Nielsen
Lm =2649987.793 mol/h = 47699.78027kg/h
For Column Diameter
For Packing Material
"Take ceramic intalox saddles, 76 mm size"
packing factor F = 72 m-1
(These are the modern packing material taken for the amine treating unit )
For water density= 992.2 kg/m3
Viscosity = 0.000653 Nm/s
For Syngas density= 3.75213324 kg/m3
Flv = 0.019580305
From fig. 11.44, page 603 C.R. Vol6; which correlates the liquid and vapour flow rates, system
physical properties, with the gas mass flow-rate per unit cross-sectional area with kines of
constant pressure drop as a parameter, we get,
K4 = 1.1 "From fig. 11.44, page 603 C.R. Vol6"
K4 (at flooding)= 2.5
percentage flooding =
= 66.33249581 (satisfactory)
Vw* = = 4.237354109 kg/m2/s
Column cross sectional area required , A = Vw/Vw* = 9.820626212 m2
85
Bachelor Thesis Project 2010
Column diameter =3.53610091 m
Column diameter(after rounding off)= 3.6 m
hence area =10.1787602m2
Vw* = 4.088265174 kg/m2/s
% flooding at selected diameter = 63.99862404 %
Estimation of Height: (Using Cornell’s method as specified in Coulson Richardson Vol.6)
(Sc)L = 202.37 ( )
(Sc)v = 0.376
Lw* = 1.301724248 kg/m2/s
At this flooding
K3 = Percentage flooding correction term = 0.8 ("From fig11.41, page 599 given in CR Vol.
6")
Ψh= HG factor = 79 ("From fig11.42, page 600 given in CR Vol. 6" )
At Lw* = 1.301724248 kg/m2/s
Φh= HL factor = 0.048 "From fig11.43, page 600 given in CR Vol. 6"
f1= liquid viscosity correction term = =1
f2 = liquid density correction term = =1
f3 = surface tension correction term = = 1
Hl = height of a gas transfer unit
86
Bachelor Thesis Project 2010
Hg = height of a liquid transfer unit
For our first approximation
Hog =2 m
thus = 26 m
Hl = 0.22977626 m
Hg = 1.239787859 m
Hog = 1.403790782 m
2nd iteration Z = 18.24928017 m
Hl = 0.217894373 m
Hg = 1.095695052 m
Hog = 1.259115832 m
3rd iteration Z = 16.36850582 m
Hl = 0.214368273 m
Hg = 1.057064746 m
Hog = 1.217840951 m ( quite close to previous Hog)
Estimated Height, Z= 15.83193236 m
Z = 16 m
Heat Exchanger 1
Shell size mm 889
Tube length - actual mm 3048
87
Bachelor Thesis Project 2010
Tube length - required mm 2589.4
Pressure drop, SS bar 0.02896
Pressure drop, TS bar 0.21657
Baffle spacing mm 349.25
Number of baffles 6
Tube passes 1
Tube number 1167
Number of units in series 1
Number of units in parallel 1
Ao/Ai ratio 1.21
Area reqd., dirty m² 174.6
Baffle type Single segmental
Tube OD mm 19.05
Tube ID mm 15.75
Shell OD mm 911.22
Shell ID mm 889
Shell passes 1
Re number liquid in, SS 4083.97
Re number liquid out, SS 11032.44
Re number vapor in, TS 156115.5
Re number vapor out, TS 169037.5
Film coef overall, SS W/(m² K) 1731.3
Film coef overall, TS W/(m² K) 706.9
Overall U - clean W/(m² K) 493
Overall U – dirty W/(m² K) 442.1
Heat Exchanger Specification sheet:
88
Bachelor Thesis Project 2010
889 / 3048 mm Type BEM 1 1m2 1
CC
/ / / // / / /
/ / / // / / /
Ao basedC
bar / / / /C
mmIn mm 1 / /
1 / /Nominal / /
OD 19.05 1.65 mm Length mm mm
ID OD mmCarbon SteelCarbon Steel-
Single segmental H mm
0.2961
kg/skg/s
kJ/kg
kJ/(kg*K)W/(m*K)
Hor
Shell Side
0
kg/s
mPa*skg/m3
kg/s10.2143
4.190.607
Tube Side
045.8681 45.8681
0
syngas
PERFORMANCE OF ONE UNIT
10.21430
water
0.180.20684
911.22
30.28Cut(%d) 349.25Spacing: c/c
Tubesheet-stationaryFloating head cover
Carbon Steel TypeBaffle-crossing
Intermediate
1
-
3.18
-101.688.9
Connections
Channel or bonnet
Tube No.
Carbon Steel 889
508
Fluid allocationFluid nameFluid quantity, Total 10.2143 45.8681
0
Specific heatThermal conductivityLatent heat
Vapor (In/Out)LiquidNoncondensable
Temperature (In/Out)
Density (Vap / Liq)ViscosityMolecular wt, Vap
Dew / Bubble point
Molecular wt, NC
0
Connected inSurf/shell (eff.)Shells/unitSurf/unit(eff.)
Size seriesm2205.6
parallel205.6
30 95 120 80
19.6319.63
1.527
6.540.0188
6.010.02040.7998
4.193
962.74
3048
-
Plain 1167
30Tube typeShell
Tks-Carbon SteelMaterial
Avg
-Channel cover -
NoneImpingement protectionTubesheet-floating
Tube patternPitch 23.81
Shell cover
10
0.06620.6741
Size/rating
442.1 Clean 493
-Out
CONSTRUCTION OF ONE SHELLShell Side Tube Side
Transfer rate, ServiceHeat exchanged
bar
Design/Vac/Test pressure
PressureVelocity
m2*K/Wbar
1m/s
Design temperature
Pressure drop, allow./calc.
1
0.00011 0.00011
132.22 160
kW
3.44738
MTD corrected2786.1
Sketch
0.00013
-
Fouling resist. (min)
- - 508
Number passes per shellCorrosion allowance
11.03162
375.636.08
3.18
Dirty W/(m2*K)
1
997.34
1
1.5170.0612
33.60.25855 0.21657
9.78343
0.02896
0.97104
T1
S1
S2
T2
Heat Exchanger HE 02:
Note: Process Design has been done using standard software ASPEN Exchanger Design
and Rating 7.1- aspen ONE
Shell size mm 1092.2
Tube length - actual mm 5486.4
Tube length - required mm 5272.6
Pressure drop, SS bar 0.02926
89
Bachelor Thesis Project 2010
Pressure drop, TS bar 0.25
Baffle spacing mm 596.9
Number of baffles 8
Tube passes 1
Tube number 1767
Number of units in series 2
Number of units in parallel 1
Ao/Ai ratio 1.21
Area reqd., dirty m² 1090.6
Baffle type Single
segmental
Tube OD mm 19.05
Tube ID mm 15.75
Shell OD mm 1117.6
Shell ID mm 1092.2
Shell passes 1
Re number liquid in, SS 2778.27
Re number liquid out, SS 5843.96
Re number vapor in, TS 111628.3
Re number vapor out, TS 122022.1
Film coef overall, SS W/(m² K) 2128.7
Film coef overall, TS W/(m² K) 498.6
Overall U – clean W/(m² K) 398.3
Overall U – dirty W/(m² K) 364.4
90
Bachelor Thesis Project 2010
1092.2 / 5486.4 mm Type BEM 1 2m2 2
CC
/ / / // / / /
/ / / // / / /
Ao basedC
bar / / / /C
mmIn mm 1 / /
1 / /Nominal 1 / /
OD 19.05 1.65 mm Length mm mm
ID OD mmCarbon SteelCarbon Steel-
Single segmental H mmmm
0.3802
kg/skg/s
kJ/kg
kJ/(kg*K)W/(m*K)
Hor
Shell Side
0
kg/s
mPa*skg/m3
kg/s14.6603
4.190.607
Tube Side
045.8681 45.8681
0
syngas
PERFORMANCE OF ONE UNIT
14.66030
water
0.120.20684
1117.6
34.89Cut(%d)Inlet
596.9Spacing: c/c
Tubesheet-stationaryFloating head cover
593.72Carbon Steel TypeBaffle-crossing
Intermediate
1
-
3.18
-152.4152.4
Baffle-long Seal type-
Connections
Channel or bonnet
Tube No.
Carbon Steel 1092.2
609.6
Fluid allocationFluid nameFluid quantity, Total 14.6603 45.8681
0
Specific heatThermal conductivityLatent heat
Vapor (In/Out)LiquidNoncondensable
Temperature (In/Out)
Density (Vap / Liq)ViscosityMolecular wt, Vap
Dew / Bubble point
Molecular wt, NC
0
Connected inSurf/shell (eff.)Shells/unitSurf/unit(eff.)
Size seriesm21134.9
parallel567.4
30 75.33 80 40
19.6319.63
1.517
7.340.0172
6.690.01880.7998
4.187
976.43
5486.4
-
Plain 1767
30Tube typeShell
Tks-Carbon SteelMaterial
Avg
-Channel cover -
NoneImpingement protectionTubesheet-floating
Tube patternPitch 23.81
Shell cover
10
0.06120.6583
Size/rating
364.4 Clean 398.3
-Out
CONSTRUCTION OF ONE SHELLShell Side Tube Side
Transfer rate, ServiceHeat exchanged
bar
Design/Vac/Test pressure
PressureVelocity
m2*K/Wbar
1m/s
Design temperature
Pressure drop, allow./calc.
1609.61
0.00011 0.00011
115.56 115.56
kW
3.44738
MTD corrected2782.8
Sketch
0.00013
-
Fouling resist. (min)
- - 609.6
Number passes per shellCorrosion allowance
11.03162
350.2
152.4
7
3.18
Dirty W/(m2*K)
1
997.34
1
1.5080.0562
19.930.25855 0.25
9.75
0.02926
0.97074
T2 S1
S2 T1
91
Bachelor Thesis Project 2010
Absorber
Calculation Of DEA Required (For 99.9% removal of H2S)
Gm = 165125.055 kg/h = 6283297.374 mol/h
y1=0.00135272
y2 =1.35272E-06
y1/y2=1000
optimum value of m*Gm/Lm = 0.75(Ref: Coulson Richarson vol 6)
NOG =16 (from Fig. 11.40 Coulson Richarson vol 6)
m =1.0266 (From Aspen properties)
Lm = 8600577.446 mol/h = 378425.4076 kg/h
For Column Diameter
For Packing Material
"Take ceramic intalox saddles, 76 mm size"
packing factor F = 72 m-1
(These are the modern packing material taken for the amine treating unit )
For DEA density = 1030kg/m3
Viscosity = 0.00309 Nm/s
For Syngas density = 9.47758145 kg/m3
Flv = 0.219835316
From fig. 11.44, page 603 C.R. Vol6; which correlates the liquid and vapour flow rates,
system physical properties, with the gas mass flow-rate per unit cross-sectional area
with kines of constant pressure drop as a parameter, we get,
92
Bachelor Thesis Project 2010
K4 = 1.4 "From fig. 11.44, page 603 C.R. Vol6"
K4 (at flooding)= 3.5
percentage flooding =
= 63.2455532 (satisfactory)
Vw* = = 7.155930214 kg/m2/s
Column cross sectional area required , A = Vw/Vw* = 6.409798512 m2
Column diameter =2.85678297 m
Column diameter(after rounding off)= 2.9 m
hence area =6.605198554 m2
Vw* = 6.944238005 kg/m2/s
% flooding at selected diameter = 61.37457481 %
Estimation of Height: (Using Cornell’s method as specified in Coulson Richardson Vol.6)
(Sc)L = 193.548 ( )
(Sc)v = 0.455
Lw* = 15.91446009 kg/m2/s
At this flooding
K3 = Percentage flooding correction term = 0.95 ("From fig11.41, page 599 given
in CR Vol. 6")
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Bachelor Thesis Project 2010
Ψh= HG factor = 80 ("From fig11.42, page 600 given in CR Vol. 6" )
At Lw* = 15.91446009 kg/m2/s
Φh= HL factor = 0.073 "From fig11.43, page 600 given in CR Vol. 6"
f1= liquid viscosity correction term = =1.192
f2 = liquid density correction term = =.9637
f3 = surface tension correction term = = .95
Hl = height of a gas transfer unit
Hg = height of a liquid transfer unit
For our first approximation
Hog =1 m
thus = 16 m
Hl = 0.37732334 m
Hg = 0.566095939 m
Hog = 0.849088444 m
2nd iteration Z = 13.5854151 m
Hl = 0.368176962 m
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Bachelor Thesis Project 2010
Hg = 0.536345333 m
Hog = 0.812478055 m
3rd iteration Z = 12.99964887 m
Hl = 0.365750911 m
Hg = 0.528600878 m
Hog = 0.802914061 m ( quite close to previous Hog)
Estimated Height, Z= 12.84662498 m
Z = 13 m
Stripper
Take Dc = 2.9 m (As specified in Peters and Timmerhaus, Plant Design and Economics for
Chemical Engineers)
Assuming 99.9% of H2S gets stripped by Steam
y1=0
x1=0.00053845
x2=5.3845E-07
m=13.2 (From aspen properties)
y2*=0.007100432
Min Gm=
Lm( x1−x2 )y2− y1 = 651558.897 mol/h
Actual steam flow rate required, G= 1042494.236 mol/h (G=1.5* min Gm)
Absorption factor, A=1.6
stripping factor, S = 0.625
For lean mixtures
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x0−xnp
x0−ynp+1
m
=Snp+1−SSnp+1−1
( Kremser equation)(Ref: Process Equipment Design by Coulson &
Richanrdson, Vol -6 )
Solving above equation
Np=12
For Column Height
Following the same procedure as done for absorber
pecentage Flooding= 72.73238618
"Using Berl saddles, 25mm"
Schmidt Number for Liquid, (Sc)L =195.421
Schmidt Number for Gas, (Sc)g=0.7075
Lm∗¿LmA = 15.91446009 kg/m2/s
At this flooding
K3=0.9 "From fig11.41, page 599 given in CR Vol. 6"
Ψh=60 "From fig11.42, page 600 given in CR Vol. 6"
φh=0.01 "From fig11.43, page 600 given in CR Vol. 6"
f1= liquid viscosity correction term = =1.192
f2= liquid density correction term = =0.9637
f3= surface tension correction term = =0.95
Hl = height of a gas transfer unit
Hg = height of a liquid transfer unit
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Bachelor Thesis Project 2010
For our first approximation
Hog=1 m
Z=12 m
Hl=0.047125956 m
Hg= 0.481480877 m
Hog= 1.1035435 m
2nd iteration Hog= 1.1035435 m
Z = 13.24252199 m
Hl = 0.047827601 m
Hg = 0.49739288 m
Hog = 1.128717208 m
Hence Estimated Height, Z = 13.54460649 m
Z=14 m (after rounding off)
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Bachelor Thesis Project 2010
4.7 Operating conditions and safety measures
Operating Conditions
Crusher
The operating conditions of the crusher are given below
Pressure, bar 1.01325
Temperature, C 40
Coal Flow Rate, kg/h (inlet) 98958.33333
Coal Flow Rate, kg/h (outlet) 95247.6084
Gasifier:
As shown in the below diagram, gasification is carried out in a Winkler fluidised-bed gasifier
which is operated at a temperature of about 950 C. The use of this temperature has shown to
produce maximum yield. This technology has been perfected over 20 years through trial and
run mainly by Rheinbraun.
It has been known that increasing the temperature increases carbon conversion but reduces
efficiency of conversion.
The gasifier is operated at 10 bar pressure, which leads to reduced costs in the construction of
the reactor.
Coal Type Talcher 1
Coal Flow Rate, Kg hr (INPUT)
Ultimate Analyses, wt%
Ash
Moisture
C
H
N
S
95247.39583
35.63636
3.896104
46.19719
3.204779
1.148883
0.423273
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O 9.493403
Steam Flow Rate, Kg/hr (INPUT) 31666.7373
Gasification Steam Temp C 500
Gasifier pressure, bar 10
Gasifier temperature, C 980
Oxidant Flow Rate, Kg/hr (INPUT)
Composition, Mole fraction
N2
O2
Ar
59375.1325
0.373
0.6
0.027
Oxidant Inlet Temp, C 500
Oxygen/Coal mass ratio 0.39
Oxygen/Coal mass ratio 0.33
Cyclone
The operating conditions of the cyclone are given below. It is operated at pressure and
temperature at which syngas enters the vessel.
Pressure, bar 10
Temperature, C 980
Syngan Flow Rate, kg/h (inlet) 159884.801
Syngas Flow Rate, kg/h (Outlet) 149808.495
Soids Flow Rate, kg/h 10076.306
Waste heat boiler
The waste heat boiler (WHB) is located adjacent to reactor and is essential for economic
viability of the plant. The major function of the WHB is to reduce the temperature of the syngas
which enters at 980 C
Steam generation is a byproduct of WHB. This steam is then sent back to the gasifier for use in
gasification. Since the temperature of the steam is below 350 C, (since this is the temperature
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Bachelor Thesis Project 2010
of the syngas outlet), it is then compressed to raise the temperature to 500 C. This is fed back
to the gasifier.
Syngas Flowrate, Kg/hr (Inlet) 149808.495
Syngas Inlet temp, C 980
Syngas Inlet Pressure, bar 10
Cool Syngas Flow rate, Kg/hr (outlet) 149808.495
Cool Syngas outlettemp, C 350
Cool Syngas outlet Pressure, bar 9.75
Water Flow rate, Kg/hr (Inlet) 52777.08
water Inlet temp, C 30
water Inlet Pressure, bar 10
Water Flow rate, Kg/hr (outlet) 52777.08
water outlet temp, C 3.7.47
water outlet Pressure, bar 9.8
Area of Heat Exchanger 229.6
Water Scrubber
Water scrubber performs two functions:
1. Scrubbing any solid residue and removal of acid gases.
2. Reducing the temperature of the syngas
This means the scrubber should be operated at as high pressure as possible for economically
scrubbing the waste out.
Scrubber working pressure [bar] 10
Scrubber inlet syngas temperature [°C] 350
Scrubber outlet syngas temperature [°C] 120.5
Scrubber inlet water temperature [°C] 30
Scrubber outlet water temp. [°C] 128.5
Water Inlet Flow rate, [kg/h] 47675.1489
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Heat Exchanger 01
A train of heat exchangers operate to cool the temperature of the syngas so as to be suitable
for water scrubbing.
Syngas Flow rate, Kg/hr (Inlet) 165125.16
Syngas Inlet temp, C 120
Syngas Inlet Pressure, bar 10
Cool Syngas Flow rate, Kg/hr (outlet) 165125.16
Cool Syngas outlet temp, C 80
Cool Syngas outlet Pressure, bar 9.7
Water Flow rate, Kg/hr (Inlet) 52777.08
water Inlet temp, C 30
water Inlet Pressure, bar 1.03
Water Flow rate, Kg/hr (outlet) 52777.08
water outlet temp, C 95
water outlet Pressure, bar 1.01
Area of Heat Exchanger, m2 174.6
Heat Exchanger 02
A train of heat exchangers operate to cool the temperature of the syngas so as to be suitable
for water scrubbing.
Syngas Flow rate, Kg/hr (Inlet) 165125.16
Syngas Inlet temp, C 120
Syngas Inlet Pressure, bar 10
Cool Syngas Flow rate, Kg/hr (outlet) 165125.16
Cool Syngas outlet temp, C 80
Cool Syngas outlet Pressure, bar 9.7
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Water Flow rate, Kg/hr (Inlet) 36771.48
water Inlet temp, C 30
water Inlet Pressure, bar 1.03
Water Flow rate, Kg/hr (outlet) 36771.48
water outlet temp, C 75.33
water outlet Pressure, bar 1.01
Area of Heat Exchanger, m2 1090.6
Absorber Stripper System:
Absorber is operated at high pressure because this increases the diffusion of gas into the
absorbent where as the stripper is operated at low pressure as gas have to desorbed from the
DEA solution Super heated steam is used in the process which accelerates the process. DEA is
cooled before it enters the stripper by using the DEA makeup which increases the heat
efficiency of the process.
Absorber working pressure [bar] 10
Absorber inlet syngas temperature [°C] 40
Absorber outlet syngas temperature [°C] 39.3
Absorber inlet solution temperature [°C] 39
Absorber outlet solution temp. [°C] 35.6
Stripper working pressure [bar] 1
Stripper inlet solution temperature [°C] 80
Stripper outlet solution temperature [°C] 97.7
Stripper outlet gas temperature [°C] 78
Stripper inlet Steam temperature [°C] 150
Sripper Inlet Steam Flow Rate Kg/h 18804.3
DEA make up Solution [kg/h] 51817.75
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Potential Hazards and safety
Issues of safety are associated with practically all industrial technologies, and understanding the
appropriate measures for safety management is an important part of understanding the
technology itself. In this respect, gasification is no different from many other technologies.
Gasification plants are complex plants that produce a high-pressure toxic gas that is
inflammable or even explosive in the presence of oxygen and an ignition source. Generally, all
these dangers are well taken care of in the process designs. Handled correctly during
construction, operation, and maintenance, they pose no more problems to personnel or
environment than many other industrial plants. This does however place a premium on training
operations and maintenance staff, introducing concepts such as HAZOP reviews, Process Safety
Management and others, which are common in the chemical industry, but maybe new in a
power plant environment.
Start-up
One of the potentially dangerous moments during start-up is the ignition of the coal or oil
burners. The procedure is much more complex than in regular atmospheric pressure furnaces,
as ultimately the burners have to work at pressures ranging from
20–70 bar, and there are no burners that can operate properly over this whole pressurerange.
Where membrane walls are used, which cool very quickly in the absence of a flame, start-up
burners have to be used to cover part of this pressure range. This is easier with a refractory
lining, which can maintain a temperature above the fuel ignition temperature, while exchanging
a heat-up burner for the operations burner. In either case and at all times, the situation should
be avoided in which a mixture of a combustible gas and oxygen is present in the reactor. In
most modern facilities these procedures are automated and controlled by a PLC. This eases the
load on the operator and reduces the chance for human error.
Shutdown
Gasifier shutdown procedures are also generally automated. Shutdown steps usually include
shutting off the supply of reactants, depressurizing the system and purging with nitrogen to
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remove any remaining synthesis gas. Purging serves a number of purposes. It eliminates any
potential source of flammable or toxic gases.
For an extended shutdown, nitrogen blanketing also serves as anti-corrosion measure. When
repairs have to be carried out inside the gasifier, it is important to ensure that there are no
other gases than air present. Drawing a good vacuum and breaking this with air is the best way
to make sure that only air is present. This operation may have to be repeated several times to
ensure that all noxious gases are removed from insulating materials, bricks, and dead ends in
the plant. Even with all these precautions, air masks may be required under certain conditions.
Spontaneous combustion
As in a conventional PC power plant, safety precautions in coal storage and handling are
essential to avoid spontaneous combustion. This applies equally well to other feed stocks, such
as biomass and certain types of waste. The key in particular is to prevent fines from drying out,
so that a first-in-first-out inventory policy must be part of the safety procedures.
Besides the fuel itself, there are other potential sources of spontaneous combustion. Particular
attention must be paid to FeS, which may form as a product of corrosion.
Toxic and asphyxiating materials
Apart from the main syngas component, carbon monoxide, there are many other toxic gases
present in a gasification complex, particularly if the end product is a chemical.
Typical toxic gases present in synthesis gas can include compounds such as H2S and COS, as well
as ammonia and HCN. The design of a plant must take account of this, and personnel must be
trained in their safe handling. There are many public sources of safety information available on
material safety data sheets. Many of these are available from Internet sources such as
www.ilpi.com/msds, which has links to many international source sites. An up-to-date set of
safety data sheets should always be available with the safety officer or other member of staff
responsible for safety training.
Nitrogen
It may come as a surprise, but a large proportion of the accidents occurring in gasification
plants are due to nitrogen that is produced as a (by-)product from oxygen plant and used for
blanketing and transport of coal, and in IGCC plants as a diluents for the fuel gas.
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The problem with nitrogen is that, in contrast to raw syngas, it has no smell and therefore gives
no warning and, even more problematic, it leads very quickly to unconsciousness. Good
ventilation of the plant is a vital measure, and for this reason many designers prefer an open-air
layout. Building a gasifier inside a closed structure requires additional precautions, not only
because of the nitrogen, but also because of other toxic or flammable gases present, such as H
2 , CO, H 2 S, COS, HCN and NH 3 .
Where enclosing the plant is absolutely necessary, such as in locations with extreme climates,
then it is best is to have louver walls and roof vents that guarantee good ventilation with
natural circulation.
CO2
Where concentrated CO2 streams are present, it is important to be aware of its asphyxiating
properties and the fact that it is heavier than air. Sub-grade drain pits and the like are typical
locations where CO 2 can accumulate, and should not be entered by plant personnel without
suitable precautions. The potential danger is not only because of leaks and open valves; also,
the gas in the stacks through which the CO 2 is vented should have sufficient buoyancy by
ensuring elevated temperatures. For all large quantities, dispersion calculations should be
made.
Oxygen
Oxygen makes up about 21% of our atmosphere, and is essential to life. It is also an essential
ingredient for combustion, in which fuels are oxidized in an extremely exothermic reaction. If
oxygen is present in concentrations significantly above 21%then the combustion becomes much
more vigorous, and materials (such as metals) that normally oxidize in a slow manner without
fire risk (e.g. rusting of iron) can behave as fuels for fire. When handling oxygen it is therefore
essential to take the necessary precautions to prevent oxygen fires (Schmidt et al., 2001).
The precautions necessary for safe operation of oxygen systems are well codified. Not only do
all the leading industrial gas supply companies and gasification technology suppliers have their
own strict safety regulations, but also trade associations such as the Compressed Gas
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Bachelor Thesis Project 2010
Association (CGA), the British Compressed Gas Association (BCGA), and the European Industrial
Gas Association (EIGA), in which these companies and other major operators of oxygen systems
are represented, publish codes of practice based on the joint experience of all their members.
Where carbon capture and storage is proposed additional safety issues needs consideration.
Experience in handling the very large quantities of supercritical CO 2 is limited and guidelines
for design, operation and emergency response need development. Issues connected with trace
components in the CO2 in pipelines need addressing. Elimination of any water is required to
eliminate the corrosion risk in all cases.
Another corrosion risk currently being investigated is caused by the presence of SO2 (for the flue
gas capture case). There is at present no consensus on the allowable concentration of H2S in
CO2. Some existing pipelines specify 25 ppmv max, while the Wey burn pipeline carries over 1%
H 2 S. A detailed risk assessment including the H 2 S issue has been prepared for the Future Gen
project (US Department of Energy, 2007b).
Many substances such as oils and grease will combust spontaneously in the presence of pure
oxygen. The energy of impact of small particles on many metals is sufficient to cause ignition.
Fires initiated by both these causes are sufficient to ignite the primary material of construction.
The principle means of combating these dangers lies in meticulous cleaning of the system prior
to the introduction of oxygen. All safety guidelines for oxygen systems include
recommendations for cleaning and inspection after cleaning .An important aspect of safety
precautions for oxygen service is material selection and system geometry. Materials are
selected to keep the ignitability of the material and its capability of sustaining a fire in an
oxygen atmosphere to a minimum. Typically, copper-based materials (e.g. Monel) or stainless
steel are used in high-pressure non cryogenic systems. Inside the cold box, where low
temperature suitability is also a criterion and pressures are limited, aluminum is also used. For
pressures up to 40 bars, carbon steel may be used. Cleaning in such applications is, however,
extremely important and for this reason the authors have a preference for stainless steel on
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both suction and discharge side of the oxygen compressor, even when not formally required by
the codes.
System geometry is also significant. Velocities in oxygen lines are generally kept low as a
measure to limit the energy release on impact of any particles in the system. An additional
measure to limit the ignition risk is to avoid sharp bends in piping, where turbulence can
increase local velocities much above these limits. For this reason also, much attention is
required to the design of valving and piping at pressure letdown stations.
An additional approach to safety in oxygen systems is to incorporate design features that
ensure that personnel are not put at risk and that any material damage in the event of a fire is
kept to a minimum. This type of precaution is taken with oxygen compressors, which are
enclosed by a fireproof wall. There is an extensive monitoring system, which on detection of a
fire risk will cause the machine to be stopped, depressurized and flooded with nitrogen. The
cooling water circuit for intercooling is usually a closed-circuit system to avoid any potential
corrosion and subsequent leaks on the intercoolers.
An important safety aspect to consider is the quality of the air entering the air separation unit.
Modern molecular sieve PPUs will generally remove heavy hydrocarbons present in the air.
Cases are known where the concentration of hydrocarbons in the atmosphere increased
substantially over the life of the ASU and overloaded an internal hydrocarbon filter inside the
cold box, breaking through into the oxygen-rich environment of the LP column. In one case
known to us, results from ethylene leakage from nearby plant were detected in time and the
filter was enlarged to cope with the new air quality. In another, the mechanism was more
complicated and an explosion resulted. Such incidents do, however, illustrate the need to
specify the feed air quality conservatively and with an eye to future developments.
The unit operations of the process are: Coal handling and preparation, coal feeding, coal
gasification, ash removal, gas cooling, gas purification (acid gas removal), and Brief discussions
of these operations follow:
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Coal Handling and Preparation
Coal is delivered from the mine to the plant unloading hopper from which it is transferred by
feeders and conveyors to primary and secondary mechanical crushers and is then stockpiled.
Later the coal is moved from the stockpile to sizing screens and to the coal-cleaning operation,
for removal of fines which may present a dust and/or explosion hazard. The cleaned, sized coal
is then used to produce gas and steam and, in some cases, power. Reject material can be
returned to the mine for final disposal.
Occupational health hazards associated with the coal handling and preparation process include
exposure to coal dust, noise, and fires from possible spontaneous combustion of coal in the
storage areas, with the potential attendant inhalation of the products of combustion.
Coal Feeding
After passage through the preparation operation, the coal is moved by conveyor either to
intermediate storage or directly to the gasifier coal bunker. Coal is then fed from this bunker to
the coal lock hopper, the operation of which is cyclic, ie, the lockhopper is charged with coal,
pressurized to gasifier pressure (with C02, raw gas, etc), opened to discharge the coal to the
gasifier, closed, depressurized, and then recharged with coal, the entire cycle taking 10-30
minutes. Each depressurization releases an estimated 280 cubic feet (cu ft) of pressurizing gas
(which is incinerated or otherwise disposed of). It is conceivable that pressurizing gas or raw gas
could be released into the coal bunker and result in exposure of operators. Occupational health
hazards associated with the coal-feeding process include exposure to coal dust, noise, and
gaseous toxicants. There is also a potential for asphyxiation by inert gases used for lockhopper
pressurization.
Coal Gasification
High-BTU gasifiers operate at high pressures, and at temperatures of 980 C .The feed streams to
the gasifier are coal, steam, and oxygen.
Traveling by gravity, coal from the lockhopper encounters the hot gas rising to the top of the
gasifier and is gradually heated to combustion temperature through successive, overlapping
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zones of preheat, devolatilization, gasification, and combustion. It is in the preheat and
devolatilization zones. Trace elements are volatilized from all parts of the bed. Steam and
oxygen enter the gasifier near the bottom and are heated by the hot ash moving downward
from the combustion zone.
Occupational health hazards associated with the gasifier operation include pptential exposure
to coal dust, high-pressure hot gases, trace elements, tar, fire, and noise.
Ash Removal
Ash from the gasifier is continuously removed by a rotating grate and collected in a steam-
pressurized lockhopper from which it is discharged. The ash is then dewatered and disposed of.
The ash lockhopper pressurizing steam is condensed after passing through a cyclone for
particulate removal and is vented to the atmosphere. Particulates collected in the cyclone are
transferred to the ash disposal area. At the end of the ash discharge cycle, the ash lockhopper is
repressurized. The quantity of radioactive material in coal varies widely with geographic
location and type of coal, but it is generally less than that in sedimentary rock. At a gasification
plant, any radioactivity would be found mainly in the product gas and the ash, neither of which
should lead to significant worker exposure. There would also be furnace-stack emissions of gas
and fly ash from any coal burned for steam generation. Fly ash removal by modern control
methods, and elevated-stack emission of hot gases should result in negligible exposure. Even in
the vicinity of a large (1,960 megawatt, electrical) electricity-generating plant with inefficient
stack gas cleaning and short stacks, air samples have shown maximum lung and bone radiation
dose rates of only about 1% of the maximum permissible rate recommended by the
International Commission on Radiological Protection. It was also found that soil samples
downwind from the plant showed no radioactivity above the natural background levels [8]. It is
not possible at present to provide a more definitive assessment of potential radiation hazards.
Occupational health hazards associated with the ash removal process include potential
exposure to heat, high-pressure steam, high-pressure oxygen, hot ash, and dust. Trace
elements in coal, although averaging only 0.03% of the total weight, present a potential hazard
for plant employees because of the large quantities of coal consumed.
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Gas Cooling
The gas cooling unit (Figure XI-5) cools the hot raw gas that bypasses the shift conversion unit
and the shifted gases in two separate, but similar, trains. Condensate (gas-liquor) is transferred
to the primary gas-liquor separator (see Section 11 below). The cooled gases are mixed and
then transferred to the Rectisol unit (see Section 8 below) for purification,
Occupational health hazards associated with gas cooling include potential exposure to high-
pressure hot raw gas, hot tar, hot tar oil, hot gas-liquor, fire, heat, and noise.
Gas Purification (Acid-Gas Removal)
The Rectisol process is a licensed gas purification process in which methanol is used to absorb
acid gases such as carbon dioxide, hydrogen sulfide, carbonyl sulfide, and organic sulfur-
containing compounds at cryogenic temperatures and at process pressure. Methanol is
regenerated by a combination of flashing to atmospheric or sub atmospheric pressure and
heating to as high as 65 C (149 F). Naphtha and residual heavy hydrocarbons are removed from
the raw gas and recovered by extracting the methanol from the water at 75 C (167 F)
Occupational health hazards associated with the gas purification process include potential
exposure to sulfur-containing gases, methanol, naphtha, cryogenic temperatures, high-pressure
steam, refrigerant gases, and noise.
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4.8 Mechanical Design
Waste Heat Boiler
Material of Construction:
Component Material
Shell Cylinder SA-516 K02700 Grd 70 Plate
Front Head Cylinder SA-516 K02700 Grd 70 Plate
Front Head Cover SA-516 K02700 Grd 70 Plate
Rear Head Cover SA-516 K02700 Grd 70 Plate
Shell Lifting Lugs SA-285 K02801 Grd C Plate
Shell Lifting Lugs Pad SA-285 K02801 Grd C Plate
Front Tubesheet SA-516 K02700 Grd 70 Plate
Rear Tubesheet SA-516 K02700 Grd 70 Plate
Front Head Flng At TS SA-516 K02700 Grd 70 Plate
Rear Head Flng At TS SA-516 K02700 Grd 70 Plate
Front Head Gasket At TS Flat Metal Jacket Asbestos Soft Steel
Rear Head Gasket At TS Flat Metal Jacket Asbestos Soft Steel
Tubes SA-214 K01807 Wld. Tube
Baffles SA-285 K02801 Grd C Plate
Tie Rods SA-36 K02600 Bar
Spacers SA-214 K01807 Wld. Tube
Shell Support A SA-285 K02801 Grd C Plate
Shell Support B SA-285 K02801 Grd C Plate
Front Hd Bolting At TS SA-193 G41400 Grd B7 Bolt(<= 2 1/2)
Rear Hd Bolting At TS SA-193 G41400 Grd B7 Bolt(<= 2 1/2)
Design Specifications
TEMA Class Shell Side Tube Side Tubesheets
Design pressure bar 10 10
Vacuum design pressre bar
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Test pressure bar 13.72988 13.83214
Design temperature C 337 400 400
Average metal temperature C 337 400 400
Corrosion allowance mm 1.59 1.59
Front tubesheet corrosion
allow
mm 1.59 1.59
Rear tubesheet corrosion
allow
mm 1.59 1.59
Radiographing Spot Spot
Number of passes 1 1
Code ASME Section VIII Div.1 2007 A08 TEMA 8th/9th Editions
Weights Empty: 7487 Full: 10300 Bundle: 5649 kgf
Cylinders/Covers
Front Head Shell Rear Head Shell Cover Tubes
Cover Cyl. Cyl. Cyl
.
Cover Cyl. Cover
Head type Ellipsoidal Ellipsoida
l
Outside
diameter
mm 1066.8 1066.8 1066.8 1066.8 19.05
Calculated
thk.
mm 6.81 7.76 6.38 6.81 0.15
TEMA
minimum
thk.
mm 11.11 11.11 11.11 11.11
Actual
thickness
mm 12 12 12 12 2.11
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Bachelor Thesis Project 2010
X-ray Spot Spot Spot Spot
Joint
efficiency
Spot Spot Spot Spot
Corrosion
allowance
mm 1.59 1.59 1.59 1.59
External
pressure
bar 10
Length
Ext.Press.
mm 3048
Maximum
Ext.Press.
bar 103.918
8
Max.lengt
h
Ext.Press.
mm 9144
Body Flanges Front Head Rear Head
Cover at
TbSh
at TbSh Cover
Flange type Ring Ring
Flange OD mm 1174 1174
Bolt circle mm 1135 1135
Bolt diameter mm 15.88 15.88
Bolt number 56 56
Gasket OD mm 1106 1106
Gasket width mm 13 13
Gasket thk. mm 3.18 3.18
Flange calc. thk. mm 69 69
Flange act. thk. mm 69 69
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Weld height mm 15 15
Tubesheets Front Rear
Tubesheet diameter mm 1174 1174
TEMA minimum thickness mm 15.88 15.88
TEMA bending thickness mm 80.62 80.62
TEMA shear thickness mm 31.38 31.38
TEMA flange extension thk mm 24.32 24.32
TEMA effective thickness mm 81 81
Code thickness mm 79.82 79.82
Corrosion allowance – shell mm 1.59 1.59
Corrosion allowance – tube mm 1.59 1.59
Recess mm
Actual thickness mm 83 83
Clad thickness (not included above) mm
Tube Details
Tube type Plain
Tube OD mm 19.05
Tube wall thickness mm 2.11
Number of tubes 1639
Tube length mm 3048
Tube pitch mm 23.81
Outer tube limit diameter mm 1030.1
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Setting Plan:
4 2 53
8 1 9 3 0 42 3 9 2
0 610
2440
Fron t H ead
1067
S he l l
1067
R ea r H ead
1067
D im e n s ion s : m m
Design Specifications S hel l Tube
D es ig n P re s s u re
Te s t P res s u re
D es ig n Tem p e ra tu re
N um b e r o f P a s s e s
C orro s ion A l lo w a n c e
R ad io g ra ph in g
b a r
b a r
C
m m
1 0
1 3 .7
3 3 7
1
1 .6
S po t
1 0
1 3 .8
4 0 0
1
1 .6
S po t
A S M E V III-1 2 00 7 A 08
TE M A Ty p e : B E M
S iz e : 1 042 -3 0 4 8
TE M A C la s s : B
W t E m p ty : 7 4 87 Fu l l : 1 0 29 9 B u nd le : 5 6 4 8 k gR ev : D a te : D es c rip ti on D w g C k d A pp d
D w g N o .: R ev :
S Y N TE C H GA S C O. LTD .TA LC H E R , OR IS S A
C o m pa ny N a m eC ity, S tate
Nozzles (1 )
L a be l S i z e : D es c rip ti on P ro je c t.
Couplings / S upports (2 )
L a be l S i z e : D es c rip ti on P ro je c t.
S S 1 2 3 3 .0 B o l t H o le s 6 8 7
S S 2 2 3 3 .0 x 6 6 .0 S lo ts 6 8 7
S etting P lan
U nti tled 01
Figure 8 setting plan of waste heat boiler
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Bachelor Thesis Project 2010
Tubesheet Layout:
N o te s :
S c a le :
R e v : D a te : D e s c rip ti o n D w g C k d A p p d
D w g N o .: R e v :
A S M E V III-1 20 0 7 A 0 8
TE M A Ty p e : B E M
S iz e : 1 04 2 -3 0 48
TE M A C la s s : B
S Y N TE C H GA S C O. LTD .TA LC H E R , OR IS S A
C om pa ny N am eC ity, S tate
Design SpecificationsN umber of Tube H oles 1639Tube O uts ide D iameter 19 mmTube P itc h 23.8 mmTube P attern TriangularTube P as s es 1N umber of Tie R ods 8Tie R od D iameter 12.7 mmB affle D iam eter 1036.5 mmB affle Ty pe S ingle S egmentalB affle C ut 24%Tube Thic k nes s 2.1 mm
Tie R od Loc ationsA 178.6 -474.3B -178.6 -474.3C 487.8 -144.4D -487.8 -144.4E 487.8 144.4F -487.8 144.4G 178.6 474.3H -178.6 474.3
Tube Lay out
U nti tled 05
S hel l IDO .T.L.
1042.8 mm1030.1 mm
B affle c ut to C /L 268.1 mm
1 92 1 4
3 1 94 2 2
5 2 56 2 6
7 2 98 3 0
9 3 31 0 3 4
1 1 3 51 2 3 6
1 3 3 71 4 3 8
1 5 3 91 6 4 0
1 7 4 11 8 4 0
1 9 4 12 0 4 2
2 1 4 12 2 4 2
2 3 4 32 4 4 2
2 5 4 32 6 4 2
2 7 4 32 8 4 2
2 9 4 13 0 4 2
3 1 4 13 2 4 0
3 3 4 13 4 4 0
3 5 3 93 6 3 8
3 7 3 73 8 3 6
3 9 3 54 0 3 4
4 1 3 34 2 3 0
4 3 2 94 4 2 6
4 5 2 54 6 2 2
4 7 1 94 8 1 4
4 9 9
1 6 3 9
R o w H o l e s
AB
CD
EF
GH
23.8
11.9
20.6
1639
Figure 9 Tube layout of waste heat boiler
116
Bachelor Thesis Project 2010
Sectional View:
No te s :
Sc a l e :
Re v : Da te : De s c ri p t i o n Dwg Ck d Ap p d
Dwg No .: Re v :
ASM E VIII -1 2 0 0 7 A0 8
TEM A Ty p e : BEM
Si z e : 1 0 4 2 -3 0 4 8
TEM A Cl a s s : B
S Y N TE C H G A S C O . LTD .TA LC H E R , O R IS S A
Company NameC ity , S tate
Sec tiona l Plan
Unti tl ed 03Bolt ing
Ref No Bolt Dia. Bolt Lengt h Bolt Circle Bolt Hole
101 56 15. 88 210 1135 18. 88
102 56 15. 88 210 1135 18. 88
OD
110
6 I
D 1
080
3.2
1 0 1
6 9
OD
117
4
4 9 6
ID 1
042.
812
5 0
3 2 3
1 2
E l l i p . (2 : 1 )
8 1 9
7 8
5
8 3
2 8 8 6
ID 1
042.
812
7 8
5
8 3
3 0 4 2
OD
110
6 I
D 1
080
3.2
1 0 2
6 9
OD
117
4
1 1 9
1 2
E l l i p . (2 : 1 )
ID 1
042.
8
3 9 2
1 6
3 B a f f l e s , S p a c i n g 6 4 7 . 7 (S . S e g . )
OD 1 9 . 0 5 T k 2 . 1 1 P i t c h 2 3 . 8 1 T r i a n g u l a r
33 0 4 23
3 0 4 8
A l l D i m e n s i o n s
I n M i l l i m e t e rs
4 2 5 3
Figure 10 sectional view of waste heat boiler
Heat Exchanger 01
Material of Construction: Carbon Steel
117
Bachelor Thesis Project 2010
Design Specifications
TEMA Class Shell Side Tube Side Tubesheets
Design pressure bar 1 10
Vacuum design pressre bar
Test pressure bar 1.3 13
Design temperature C 132 160 160
Average metal temperature C 132 160 160
Corrosion allowance mm 1.59 1.59
Front tubesheet corrosion
allow
mm 1.59 1.59
Rear tubesheet corrosion
allow
mm 1.59 1.59
Radiographing Spot Spot
Number of passes 1 1
Nozzle flange rating
Post weld heat treatment Program Program
Code ASME Section VIII Div.1 2007 A08 TEMA 8th/9th Editions
Weights Empty: 6972 Full: 9772 Bundle: 5166 kgf
Cylinders/Covers
Front Head Shell Rear Head Shell Cover Tubes
Cover Cyl. Cyl. Cyl. Cover Cyl. Cove
r
Head type Ellipsoidal Ellipsoid
al
Outside
diameter
mm 1066.8 1066.8 1066.8 1066.8 19.05
Calculated
thk.
mm 5.43 6.12 2.04 5.43 0.12
TEMA mm 11.11 11.11 11.11 11.11
118
Bachelor Thesis Project 2010
minimum
thk.
Actual
thickness
mm 12 12 12 12 2.11
X-ray Spot Spot Spot Spot
Joint
efficiency
Spot Spot Spot Spot
Corrosion
allowance
mm 1.59 1.59 1.59 1.59
External
pressure
bar 1
Length
Ext.Press.
mm 3048
Maximum
Ext.Press.
bar 147.546
9
Minimum
thk.
Ext.Press.
mm 0.1
Max.length
Ext.Press.
mm 9144
Body Flanges
Front Head Shell Rear Head
Cove
r
at
TbSh
Front Rear at
TbSh
Cover
Flange type Ring Ring
Flange OD mm 1174 1174
Bolt circle mm 1135 1135
Bolt diameter mm 15.88 15.88
119
Bachelor Thesis Project 2010
Bolt number 52 52
Gasket OD mm 1106 1106
Gasket width mm 13 13
Gasket thk. mm 3.18 3.18
Flange calc. thk. mm 54 54
Flange overlay mm
Recess mm
Flange act. thk. mm 54 54
Lap jnt ring OD mm
Hub length mm
Hub slope in
Weld height mm 15 15
Tubesheets
Front Rear
Tubesheet diameter mm 1174 1174
TEMA minimum thickness mm 15.8
8
15.88
TEMA bending thickness mm 37.3
4
37.34
TEMA shear thickness mm 6.73 6.73
TEMA flange extension thk mm 20.8
4
20.84
TEMA effective thickness mm 38 38
Code thickness mm 29.8
2
29.82
Corrosion allowance - shell mm 1.59 1.59
Corrosion allowance - tube mm 1.59 1.59
Recess mm
Actual thickness mm 33 33
120
Bachelor Thesis Project 2010
Clad thickness (not included
above)
mm
Tube Details
Tube type Plain
Tube OD mm 19.05
Tube wall thickness mm 2.11
Number of tubes 1639
Tube length mm 3048
Tube pitch mm 23.81
Tube pattern 30
Outer tube limit diameter mm 1030.1
121
Bachelor Thesis Project 2010
Setting Plan:
4223
804 3042 3770 610
2440
Front Head
1067
Shell
1067
Rear Head
1067
Dimensions: mm
Design Specifications Shell Tube
Design Pressure
Test Pressure
Design Temperature
Number of Passes
Corrosion Allowance
Radiographing
bar
bar
C
mm
1
1.3
132
1
1.6
Spot
10
13
160
1
1.6
Spot
ASME VIII-1 2007 A08
TEMA Type: BEM
Size: 1042-3048
TEMA Class: B
Wt Empty: 6971 Full: 9771 Bundle: 5166 kgRev: Date: Description Dwg Ckd Appd
Dwg No.: Rev:
SYNTECH GAS CO. LTD.TALCHER, ORISSA
Company NameCity, State
Nozzles (1)
Label Size: Description Project.
Couplings / Supports (2)
Label Size: Description Project.
SS1 2 33.0 Bolt Holes 687
SS2 2 33.0 x 66.0 Slots 687
Setting Plan
mechanical 01
Figure 11 setting plan of Heat exchanger HE 01
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Bachelor Thesis Project 2010
Tube Layout:
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Bachelor Thesis Project 2010
Notes:
S cale:
Rev: Date: Description Dw g Ckd A ppd
Dw g N o.: Rev:
A S ME V III-1 2007 A 08
TE MA Type: B E M
S ize: 1042-3048
TE MA C lass: B
SYNTECH GAS CO. LTD.TALCHER, ORISSA
Company NameCity, State
Design SpecificationsNumber of Tube Holes 1639Tube Outside Diameter 19 mmTube P itch 23.8 mmTube Pattern TriangularTube Passes 1Number of Tie Rods 8Tie Rod Diameter 12.7 mmBaffle Diameter 1036.5 mmBaffle Type Single SegmentalBaffle Cut 24%Tube Thickness 2.1 mm
Tie Rod LocationsA 178.6 -474.3B -178.6 -474.3C 487.8 -144.4D -487.8 -144.4E 487.8 144.4F -487.8 144.4G 178.6 474.3H -178.6 474.3
Tube Layout
mechanical 05
Shell IDO.T.L.
1042.8 mm1030.1 mm
Baffle cut to C/L 268.1 mm
1 92 14
3 194 22
5 256 26
7 298 30
9 3310 34
11 3512 36
13 3714 38
15 3916 40
17 4118 40
19 4120 42
21 4122 42
23 4324 42
25 4326 42
27 4328 42
29 4130 42
31 4132 40
33 4134 40
35 3936 38
37 3738 36
39 3540 34
41 3342 30
43 2944 26
45 2546 22
47 1948 14
49 9
1639
Row Holes
AB
CD
EF
GH
23.8
11.9
20.6
1639
Figure 12 Tube layout of Heat Exchanger 01
Heat Exchanger 02
Design Specifications
TEMA Class Shell Side Tube Side Tubesheets
Design pressure bar 1 10
Vacuum design pressre bar
Test pressure bar 1.3 13
Design temperature C 110 115.56 115.56
Average metal temperature C 110 115.56 115.56
124
Bachelor Thesis Project 2010
Corrosion allowance mm 1.59 1.59
Front tubesheet corrosion
allow
mm 1.59 1.59
Rear tubesheet corrosion
allow
mm 1.59 1.59
Radiographing Spot Spot
Number of passes 1 1
Nozzle flange rating
Post weld heat treatment Program Program
Code ASME Section VIII Div.1 2007 A08 TEMA 8th/9th Editions
Weights Empty: 11134 Full: 15366 Bundle: 8662 kgf
Cylinders/Covers
Front Head Shell Rear Head Tubes
Cover Cyl. Cyl. Cyl. Cover
Head type Ellipsoidal Ellipsoidal
Outside
diameter
mm 1066.8 1066.8 1066.8 1066.8 19.05
Calculated
thk.
mm 5.43 6.12 2.04 5.43 0.12
TEMA
minimum
thk.
mm 11.11 11.11 11.11 11.11
Actual
thickness
mm 12 12 12 12 2.11
X-ray Spot Spot Spot Spot
Joint
efficiency
Spot Spot Spot Spot
125
Bachelor Thesis Project 2010
Corrosion
allowance
mm 1.59 1.59 1.59 1.59
External
pressure
bar 1
Length
Ext.Press.
mm 5185.4
Maximum
Ext.Press.
bar 148.8984
Minimum
thk.
mm 0.1
Max.length
Ext.Press.
mm 15748
Body Flanges
Front Head Shell Rear Head Shell
Cover at
TbSh
Front Rear at
TbSh
Cover Cover
Flange type Ring Ring
Flange OD mm 1174 1174
Bolt circle mm 1135 1135
Bolt diameter mm 15.88 15.88
Bolt number 52 52
Gasket OD mm 1106 1106
Gasket width mm 13 13
Gasket thk. mm 3.18 3.18
Flange calc. thk. mm 54 54
Flange act. thk. mm 54 54
Weld height mm 15 15
126
Bachelor Thesis Project 2010
Tubesheets
Front Rear
Tubesheet diameter mm 1174 1174
TEMA minimum thickness mm 15.8
8
15.88
TEMA bending thickness mm 38.3
7
38.37
TEMA shear thickness mm 5.24 5.24
TEMA flange extension thk mm 20.8
4
20.84
TEMA effective thickness mm 39 39
Code thickness mm 29.8
2
29.82
Corrosion allowance - shell mm 1.59 1.59
Corrosion allowance - tube mm 1.59 1.59
Recess mm
Actual thickness mm 33 33
Clad thickness (not included
above)
mm
Tube Details
Tube type Plain
Tube OD mm 19.05
Tube wall thickness mm 2.11
Number of tubes 1639
Tube length mm 5185.4
127
Bachelor Thesis Project 2010
Tube pitch mm 23.81
Tube pattern 30
Outer tube limit diameter mm 1030.1
Setting Plan
6361
804 5180 377
0 1040
4150
Front Head
1067
Shell
1067
Rear Head
1067
Dimensions: mm
Design Specifications Shell Tube
Design Pressure
Test Pressure
Design Temperature
Number of Passes
Corrosion Allowance
Radiographing
bar
bar
C
mm
1
1.3
110
1
1.6
Spot
10
13
116
1
1.6
Spot
ASME VIII-1 2007 A08
TEMA Type: BEM
Size: 1042-5185
TEMA Class: B
Wt Empty: 11134 Full: 15366 Bundle: 8662 kgRev: Date: Description Dwg Ckd Appd
Dwg No.: Rev:
SYNTECH GAS CO. LTD.TALCHER, ORISSA
Company NameCity, State
Nozzles (1)
Label Size: Description Project.
Couplings / Supports (2)
Label Size: Description Project.
SS1 2 33.0 Bolt Holes 687
SS2 2 33.0 x 66.0 Slots 687
Setting Plan
mechanical 01
Figure 13 Setting Plan of Heat Exchanger 02
128
Bachelor Thesis Project 2010
Tube Layout:
Notes:
S cale:
Rev: Date: Description Dw g Ckd A ppd
Dw g N o.: Rev:
A S ME V III-1 2007 A 08
TE MA Type: B E M
S ize: 1042-5185
TE MA C lass: B
SYNTECH GAS CO. LTD.TALCHER, ORISSA
Company NameCity, State
Design SpecificationsNumber of Tube Holes 1639Tube Outside Diameter 19 mmTube P itch 23.8 mmTube Pattern TriangularTube Passes 1Number of Tie Rods 8Tie Rod Diameter 12.7 mmBaffle Diameter 1036.5 mmBaffle Type Single SegmentalBaffle Cut 24%Tube Thickness 2.1 mm
Tie Rod LocationsA 178.6 -474.3B -178.6 -474.3C 487.8 -144.4D -487.8 -144.4E 487.8 144.4F -487.8 144.4G 178.6 474.3H -178.6 474.3
Tube Layout
mechanical 05
Shell IDO.T.L.
1042.8 mm1030.1 mm
Baffle cut to C/L 268.1 mm
1 92 14
3 194 22
5 256 26
7 298 30
9 3310 34
11 3512 36
13 3714 38
15 3916 40
17 4118 40
19 4120 42
21 4122 42
23 4324 42
25 4326 42
27 4328 42
29 4130 42
31 4132 40
33 4134 40
35 3936 38
37 3738 36
39 3540 34
41 3342 30
43 2944 26
45 2546 22
47 1948 14
49 9
1639
Row Holes
AB
CD
EF
GH
23.8
11.9
20.6
1639
Figure 14 Tube Layout of Heat Exchanger 02
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Bachelor Thesis Project 2010
Absorber
Mechanical Design of absorber
P 10 Bar 9
bar
guage 0.9 Mpa
H 13 M
Di 2.9 M
static water pressure head 1.3 bar
P design 1.03 Mpa
(Pd = P *1.05 or P + static water pressure head whichever is greater)
(Ref: Pg-14, B.C.B.)
Operating Temperature 40 oC
Design Temp 50 oC
(Ref: Pg-15, B.C.B.)
Assuming moc as Low
alloy steel
IS:2041-1962,
20Mn2
Tensile stress, f
1.37E+0
8 N/m2 f= 1.37E+02 MN/m2
(Ref: Pg-261, B.C.B.)
Taking corrosion Allowance as 3 mm (Ref: Pg-19, B.C.B.)
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Bachelor Thesis Project 2010
Assuming Class II Vessel with double welded lap joints,
J= 0.85 (Ref: Pg-19, B.C.B.)
Shell Thickness
t th 1.29E-02 M using t th = PdDi/(2fJ-Pd)
(Ref:Eq. 3.3.19, Pg-35, B.C.B.)
t th' 1.59E-02 M (t th'= t th+c.a.) (Ref: Pg-19, B.C.B.)
tstd 16 Mm
( 5mm is the minimum thickness for thin walled pressurized vessel)
(Ref: Pg-18, B.C.B.)
Do 2.932 M (Do=Di+2tstd)
Do/Di
1.011034
5 <1.5
Hence, condition satisfied for thin walled design
Design of Heads
Due to low pressure, Flanged Standard dished heads are to be designed because they are
used in the construction of vertical process vessels for low pressure.( Ref pg. 41, BCB)
t th = PdDoC/2fJ (Ref: Pg-52, B.C.B.)
Weld joint efficiency factor J 0.85
Initial Assumption
t th = 0.5* tstd (for shell)= 8 mm
Ri = Do = 2.932 M (Ref: Pg-53, B.C.B.)
ri= 0.06Do 1.7592 M (Ref: Pg-53, B.C.B.)
ro= ri + tth= 1.7672 M
ho = R0-[(R0-Do/2)*(Ro+Do/2-2*r0)]1/2 =
1.80681
7 m
131
Bachelor Thesis Project 2010
(Ref: Pg-53, B.C.B.)
(Doro/2)1/2
1.609569
9 M
(Ref: Pg-53, B.C.B.)
D02/4Ro 0.733 M (Ref: Pg-53, B.C.B.)
he 0.733 M (least of all three)
he/Do 0.25
t/D0 0.005 (Ref: table 4.1(A) Pg-53, B.C.B.)
C 1.14
t th 0.01466 M
t th' 0.01766 M (t th' = t th +c.a.)
Tstd 18 Mm (Ref: Pg-269, B.C.B.)
Outer Diameter 2.932 M
Compensation for openings
Assumptions
MOC of nozzle is same as that of shell
Nozzle opening is made away from any longitudinal seam weld
Openings have been taken in heads , one for steam inlet and the other for outlet and in shell,
one for DEA inlet and the other for outlet
For head:
Assuming nozzle outer diameter do 100 mm 0.1 m
nozzle wall thickness tn 16 mm 0.016 m
length of nozzle above surface 0.05 m
Only external protrusion taken
Calculations
For a sphere having radius equal to crown radius (Ri), thickness can be calculated by the
Formula t th = 2PdRi/(4fJ-Pd) (Ref: Pg-96, B.C.B.)
Hence, tr = 1.30E-02 M
132
Bachelor Thesis Project 2010
For calculation purposes, we will be using tr 0.005 m
D = inner diameter of the nozzle = d0-2tn = 0.068 m
C = corrosion allowance = 2 mm for nozzle
J = 1
(as opening is assumed away from any
seam weld)
(Ref: Pg-91, B.C.B.)
A 9.36E+02 mm2 (A=(d+2c) *tr)
(Ref: Pg-88, B.C.B.)
Excess area available in the shell within boundary limit acting as reinforcement
As 7.23E+01 mm2 (As=(d+2c)*(tn-tr-c)) (Ref: Pg-88, B.C.B.)
A<As Hence no need for calculation of An, the ring pad is not required for compensation
in the heads
For shell:
Assuming nozzle outer diameter do = 100 mm 0.1 m
nozzle wall thickness 16 mm 0.016 m
length of nozzle above surface 0.05 m
Calculations
Hence, tr = 0.516 Mm
D = inner diameter of the nozzle = d0-2tn = 0.068 m
C = corrosion allowance = 2 mm
for
nozzle
J = 1
( as opening is assumed away from any
seam weld)
(Ref: Pg-91, B.C.B.)
A 37.152 mm2 (A=(d+2c) *tr)
(Ref: Pg-88,
B.C.B.)
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Bachelor Thesis Project 2010
Excess area available in the shell within boundary limit acting as reinforcement
As 970.848 mm2 (As=(d+2c)*(tn-tr-c)) (Ref: Pg-88, B.C.B.)
A<As Hence no need for calculation of An, the ring pad is not required for compensation
in the heads.
Calculation of Flange thickness
1. Gasket Design
For a low pressure operation. We use Narrow faced plain face flanges. We use narrow
faced flanges to ensure better leak proof joint, as gasket in between two
flanges can be presses properly.
Due to moderate temperature and low pressure operation, we have used Compressed
asbestos
sheet min actual gasket width 10 mm (Ref: Table 7.1,Pg-103, B.C.B.)
M 3.75 M (Ref: Table 7.1,Pg-103, B.C.B.)
Y 52.05 MN/m2 (Ref: Table 7.1,Pg-103, B.C.B.)
B = Di = 0.8 m (taking butt joints)
(Ref: Pg105, B.C.B.)
do/di
1.010861
9
Di 0.81 M (B+10mm)
Do
0.818798
1 M
N = minimum gasket width = (do – 0.004399
134
1/2
( 1)o
i
d y pm
d y p m
Bachelor Thesis Project 2010
di)/2 = 1
But, minimum nominal
gasket width
should be 10mm. therefore,
taking N = 0.01 M
Bo 0.005 M (bo = N/2 for plain face flange)
B 0.005 M (Ref: Table 7.2,Pg-104, B.C.B.)
New d0 = di +2*N = 0.83
G =Diameter at location of gasket load rxn = mean diameter of gasket contact face =
di+N
(b0<6.3 mm)
G 0.82 M
2.Estimation of bolt loads
Load due to design pressure
(Ref: Pg-108,
B.C.B.)
H
0.543944
8 MN
Load to keep tight joint under operation
Hp
0.099502
1 MN ()
(Ref: Pg-108, B.C.B.)
Min. bolt load required,
(Wo=H+Hp)
Wo=
0.643446
9 MN (Ref: Pg-108, B.C.B.)
Wg= Load too seat gasket under bolting up conditions
(Ref: Pg-108, B.C.B.)
Wg 0.670431 MN
135
*G *2b*mp pH
Wg Gby
2 / 4H G p
Bachelor Thesis Project 2010
6
Controlling loads greater of the two, W= Wo =
0.67043
2 MN
Allowable stress for bolting material at design temperature,
So 170 MN/m2 for moc 18 Cr 2 Ni steel
(Ref: Pg-108, B.C.B.)
Allowable stress for bolting material at atmospheric temperature,
Sg 212 MN/ m2 (Ref: Pg-108, B.C.B.)
Min bolting area
Am=A0
0.003162
4 m2 (Ag = Wg/ Sg )
(Ref: Pg-109,
B.C.B.)
3162.413
1 mm2
Minimum hub thickness or nozzle wall thickness,go = shell thickness 0.011 M
Maximum hub thickness,g1 0.015565 (g1 = 1.415 go )
Bolt Size
Root
area, Ar
Min no of
bolts
actual no.
of bolts Bs R
Cr=
B+2(g1+R)
M12X1.5 63.617 49.70785 52 75 20 1242.038 840.01
M14X1.5 95.0332 33.27536 36 75 22 859.8726 844.01
M16X1.5
132.732
3 23.82437 24 75 25 573.2484 850.01
M18X2 153.938 20.54245 24 75 27 573.2484 854.01
M20X2 201.061 15.72781 16 75 30 382.1656 860.01
136
1 /sC nB
Bachelor Thesis Project 2010
9
Therefore, we will use 36 bolts each of 11 mm diameter.
Bol circle diameter = C = 0.86 m
(Ref: Pg-107,
B.C.B.)
Bs 75
N 36
R 0.022 m
bolt dia 0.011 m
3. Calculation of flange outside diameter
A= C+bolt dia+.02 m
Bolt area Ab= 3421.195 mm2 (Ref: Pg-106, B.C.B.)
A= 0.891 m2 (Ref: Pg-106, B.C.B.)
Check if gasket
width = AbSg/( π GN) = 28.15<2y
therefore, condition is satisfied
4. Flange moment computations
For operating conditions
Total load, Wo = W1+W2+W3 (Ref: Pg-113, B.C.B.)
Hydrostatic end force on area inside the flange
(Ref: Pg-113, B.C.B.)
W1 0.5177345 MN
W2=H-W1 0.0262103 MN (Ref: Pg-113, B.C.B.)
W3=W0-H= Hp
0.0995020
93 MN
Moment arms for flange load,
a1 = (C-B)/2 0.03
137
21 / 4W B p
Bachelor Thesis Project 2010
a3=(C-G)/2 0.02
a2=(a1+a3)/2 0.025
Total flange moment,
M0
W1*A1+W2*A2+W3*A
3 0.018177334 MJ
For bolting up conditions
Total flange moment ,
Mg= W*A3
W=(Am+Ab)/2*Sg
0.6978624
81 MN
Mg= 0.0139572 MJ
taking larger of two
M= 0.0181773 MJ
5. Calculation of flange thickness
using flange moc as IS 2004-1962 class 2 type vessel
Sfo= 8.40E+07 N/m2 8.40E+01 MN/m2
(Ref: Pg-261,
B.C.B.)
K 1.11 (Ref: Pg-115, B.C.B.)
from graphs on Pg 115 BCB,
Y 12
Assuming
Sr=Sfo 84MN/m2 (Ref: Pg-117, B.C.B.)
Sz=1.5Sfo = 1.26E+02MN/m2
initially taking St = Sfo and assumig Cf=1 for first iteration,
Therefore, thickness of flange, t= 0.082
m
138
2 F
FO
MC Yt
BS
Bachelor Thesis Project 2010
Actual Bs 0.075 (Ref: Pg-113, B.C.B.)
Therefore, bolt pitch correction factor,
Cf 0.8492 (Cf =(Bs/(2d+t))^.5)
(Ref: Pg-117, B.C.B.)
Actual flange thickness
0.0756 m
(t’ = t*Cf^.5) (Ref: Pg-117, B.C.B.)
Design for Tall Vessels
Calculations
Thickness of insulation = 50 mm
y = specific weight of shell = 77000 N/m3
(Ref: Pg-269,Table A-8 B.C.B.)
ρs = specific density of shell = 7850 kg/m3
Stress due to dead loads
σzp=Axial stress due to pressure = PdDi2/(4*t*(Di+t))=
5.77E+01 MN/m2
Ws/X = Weight of shell per unit length = π*(Di+t)*ts*y =
1.13E-02 MN/m3
where X = length
σzs /X = Axial stress due to stress loads per unit length = Ws/( π*ts*(Di+ts)) =
0.01186
73 N/m3
Wa/X = Weight of all attachments per unit length = 18% of Ws/X =
2.03E-
03
MN/
m
(Ref: Pg-145, B.C.B.)
σza /X = Axial stress due to weight of attachments per unit length = Wa/X( π*ts*(Di+ts))=
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Bachelor Thesis Project 2010
0.01384
52
MN/
m3
σzw /X = σzs /X + σza /X =
0.0257124
79 MN/m3
(Ref: Pg-105,sec. 9.2.3.4, Eq. 9.3.6, B.C.B.)
Wi/X= weight of insulation for a length X meters=tins*Yins/t
0.01566
67
MN/
m
Period of vibration
W = Weight of column for a height (H-h)
= 26.07314 kN
T=Period of vibration = 6.35 * 10-5 * (H/D)3/2 * (W/t)1/2 =
2.71E-
02 Sec
(Ref: Pg-
151, Eq.
9. .3.23,
B.C.B.)
K2 = coefficient depending on period of one cycle of vibration of the vessel
= 1 (if T is less than or equal to 0.5 sec)
= 2 (if T is greater than 0.5 sec) (Ref: Pg-147, B.C.B.)
K1 = coefficient depending on the shape factor
= 1.4 for flat plate
= 0.7 for cylindrical vessel
(Ref: Pg-147, B.C.B.)
so K1= 0.7
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K2= 1
Stress due to wind loads
pw=wind pressure = 0.05Vw2 = 980 N/m2
Ref: Pg-146, Eq. 9.3.8, B.C.B.)
Vw = 140 kph
Pw = wind load = pw*(Di+t)* K1 * K2 = 2.00E+03 N/m
(Ref: Pg-146, Eq. 9.3.9, B.C.B.)
Mw/X2 = bending moment at the base of the vessel due to wind load = Pw/2 =
9.99E+0
2 J/m2
(Ref: Pg-146, Eq. 9.3.11, B.C.B.)
σzwm / X2 = bending stress in the axial direction = 4*Mw/( π*(Di+ts)2 *ts) =
0.00935
04
MN/
m2
(Ref: Pg-146, Eq. 9.3.13, B.C.B.)
σz (tensile)(max) = σzp - σzw + σzwm = fJ = 1.16E+02 MN/m2
hence, length = Xmax= 25.41 m >>11 m (Ref: Pg-146, Eq. 9.4.3, B.C.B.)
So, the column is stable under wind loads and no stiffners are required.
Design of skirt thickness
Pw= K1K2pwHD
For minimum weight condition Do= 2.932 m
For maximum weight condition Do= 2.982 m (insulated)
Pw(min)= 25862.2 N
Pw(max)= 26593.476 N
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Maximum and minimum wind moments are computed by
Mw(min)=Pw(min)*H/2 0.1681043 MJ
Mw(max)=Pw(max)*H/2
0.1728575
94 MJ
As the thickness of skirt is expected to be small, assume
Di=Do= 2.932 m
t*σzwm(min)= 0.0248978 MN/m
t*σzwm(max)= 0.0256018 MN/m
Wmin= 90 kN
Wmax= 510 kN
t*σzw(min)=Wmin/(πd)
0.0097707
67 MN/m
t*σzw(min)=Wmax/(πd)
0.0553676
81 MN/m
t*σz(tensile)= 0.015127
now, σz(tensile)=fJ 1.16E+02 MN/m2
t= 1.30E-01 mm
As per IS: 2825-1969, minimum corroded skirt thickness is 7 mm.
Providing a corrosion allowance of 1mm, a standard 8 mm thick plate can be used for skirt.
Stripper
Mechanical Design of Stripper
P 10 Bar 9
bar
guage 0.9 Mpa
H 14 M
Di 2.9 M
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static water pressure head 1.4 bar
P design 1.04 Mpa
(Pd = P *1.05 or P + static water pressure head whichever is greater)
(Ref: Pg-14, B.C.B.)
Operating Temperature 40 oC
Design Temp 50 oC
(Ref: Pg-15, B.C.B.)
Assuming moc as Low
alloy steel
IS:2041-1962,
20Mn2
Tensile stress, f
1.37E+0
8 N/m2 f=
1.37E+0
2 MN/m2
(Ref: Pg-261, B.C.B.)
Taking corrosion Allowance as 3 mm (Ref: Pg-19, B.C.B.)
Assuming Class II Vessel with double welded lap joints,
J= 0.85 (Ref: Pg-19, B.C.B.)
Shell Thickness
t th 1.30E-02 M using t th = PdDi/(2fJ-Pd)
(Ref:Eq. 3.3.19, Pg-35, B.C.B.)
t th' 1.60E-02 M (t th'= t th+c.a.) (Ref: Pg-19, B.C.B.)
tstd 16 Mm
( 5mm is the minimum thickness for thin walled pressurized vessel)
(Ref: Pg-18, B.C.B.)
Do 2.932 M (Do=Di+2tstd)
Do/Di
1.011034
5 <1.5
Hence, condition satisfied for thin walled design
Design of Heads
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Due to low pressure, Flanged Standard dished heads are to be designed because they are
used in the construction of vertical process vessels for low pressure.( Ref pg. 41, BCB)
t th = PdDoC/2fJ (Ref: Pg-52, B.C.B.)
Weld joint efficiency factor J 0.85
Initial Assumption
t th = 0.5* tstd (for shell)= 8 mm
Ri = Do = 2.932 M (Ref: Pg-53, B.C.B.)
ri= 0.06Do 1.7592 M (Ref: Pg-53, B.C.B.)
ro= ri + tth= 1.7672 M
ho = R0-[(R0-Do/2)*(Ro+Do/2-2*r0)]1/2 =
1.80681
7 m
(Ref: Pg-53, B.C.B.)
(Doro/2)1/2
1.609569
9 M
(Ref: Pg-53, B.C.B.)
D02/4Ro 0.733 M (Ref: Pg-53, B.C.B.)
he 0.733 M (least of all three)
he/Do 0.25
t/D0 0.005 (Ref: table 4.1(A) Pg-53, B.C.B.)
C 1.14
t th 0.01466 M
t th' 0.01766 M (t th' = t th +c.a.)
Tstd 18 Mm (Ref: Pg-269, B.C.B.)
Outer Diameter 2.932 M
Compensation for openings
Assumptions
MOC of nozzle is same as that of shell
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Nozzle opening is made away from any longitudinal seam weld
Openings have been taken in heads , one for steam inlet and the other for outlet and in shell,
one for DEA inlet and the other for outlet
For head:
Assuming nozzle outer diameter do 100 mm 0.1 M
nozzle wall thickness tn 16 mm 0.016 M
length of nozzle above surface 0.05 m
Only external protrusion taken
Calculations
For a sphere having radius equal to crown radius (Ri), thickness can be calculated by the
formula t th = 2PdRi/(4fJ-Pd) (Ref: Pg-96, B.C.B.)
Hence, tr = 1.31E-02 M
For calculation purposes, we will be using tr 0.005 m
D = inner diameter of the nozzle = d0-2tn = 0.068 m
C = corrosion allowance = 2 mm for nozzle
J = 1
(as opening is assumed away from any
seam weld)
(Ref: Pg-91, B.C.B.)
A 9.45E+02 mm2 (A=(d+2c) *tr)
(Ref: Pg-88, B.C.B.)
Excess area available in the shell within boundary limit acting as reinforcement
As 6.32E+01 mm2 (As=(d+2c)*(tn-tr-c)) (Ref: Pg-88, B.C.B.)
A<As Hence no need for calculation of An, the ring pad is not required for compensation
in the heads
For shell:
Assuming nozzle outer diameter do = 100 mm 0.1 M
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nozzle wall thickness 16 mm 0.016 M
length of nozzle above surface 0.05 m
Calculations
Hence, tr = 0.516 Mm
D = inner diameter of the nozzle = d0-2tn = 0.068 m
C = corrosion allowance = 2 mm
for
nozzle
J = 1
( as opening is assumed away from any
seam weld)
(Ref: Pg-91, B.C.B.)
A 37.152 mm2 (A=(d+2c) *tr)
(Ref: Pg-88,
B.C.B.)
Excess area available in the shell within boundary limit acting as reinforcement
As 970.848 mm2 (As=(d+2c)*(tn-tr-c)) (Ref: Pg-88, B.C.B.)
A<As Hence no need for calculation of An, the ring pad is not required for compensation
in the heads.
Calculation of Flange thickness
1. Gasket Design
For a low pressure operation. We use Narrow faced plain face flanges. We use narrow
faced flanges to ensure better leak proof joint, as gasket in between two
flanges can be presses properly.
Due to moderate temperature and low pressure operation, we have used Compressed
asbestos
sheet min actual gasket width 10 mm
(Ref: Table 7.1,Pg-103,
B.C.B.)
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Bachelor Thesis Project 2010
M 3.75 M
(Ref: Table 7.1,Pg-103,
B.C.B.)
Y 52.05 MN/m2
(Ref: Table 7.1,Pg-103,
B.C.B.)
B = Di = 0.8 m (taking butt joints)
(Ref: Pg105, B.C.B.)
do/di
1.010977
7
Di 0.81 M (B+10mm)
Do 0.818892 M
N
= minimum gasket width = (do –
di)/2 =
0.00444
6
But, minimum nominal
gasket width
should be 10mm. therefore,
taking N = 0.01 M
Bo 0.005 M (bo = N/2 for plain face flange)
B 0.005 M (Ref: Table 7.2,Pg-104, B.C.B.)
New d0 = di +2*N = 0.83
G =Diameter at location of gasket load rxn = mean diameter of gasket contact face =
di+N
(b0<6.3 mm)
G 0.82 M
2.Estimation of bolt loads
Load due to design pressure
(Ref: Pg-108,
147
1/2
( 1)o
i
d y pm
d y p m
2 / 4H G p
Bachelor Thesis Project 2010
B.C.B.)
H
0.549225
8 MN
Load to keep tight joint under operation
Hp
0.100468
1 MN ()
(Ref: Pg-108, B.C.B.)
Min. bolt load required,
(Wo=H+Hp)
Wo=
0.649693
9 MN (Ref: Pg-108, B.C.B.)
Wg= Load too seat gasket under bolting up conditions
(Ref: Pg-108, B.C.B.)
Wg
0.670431
6 MN
Controlling loads greater of the two, W= Wo =
0.67043
2 MN
Allowable stress for bolting material at design temperature,
So 170 MN/m2 for moc 18 Cr 2 Ni steel
(Ref: Pg-108, B.C.B.)
Allowable stress for bolting material at atmospheric temperature,
Sg 212 MN/ m2 (Ref: Pg-108, B.C.B.)
Min bolting area
Am=A0
0.003162
4 m2 (Ag = Wg/ Sg )
(Ref: Pg-109,
B.C.B.)
3162.413
1 mm2
Minimum hub thickness or nozzle wall thickness,go = shell thickness 0.011 M
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*G *2b*mp pH
Wg Gby
Bachelor Thesis Project 2010
Maximum hub thickness,g1 0.015565 (g1 = 1.415 go )
Bolt Size
Root
area, Ar
Min no of
bolts
actual no.
of bolts Bs R
Cr=
B+2(g1+R)
M12X1.5 63.617 49.70785 52 75 20 1242.038 840.01
M14X1.5 95.0332 33.27536 36 75 22 859.8726 844.01
M16X1.5
132.732
3 23.82437 24 75 25 573.2484 850.01
M18X2 153.938 20.54245 24 75 27 573.2484 854.01
M20X2
201.061
9 15.72781 16 75 30 382.1656 860.01
Therefore, we will use 36 bolts each of 11 mm diameter.
Bol circle diameter = C = 0.86 m
(Ref: Pg-107,
B.C.B.)
Bs 75
N 36
R 0.022 m
bolt dia 0.011 m
3. Calculation of flange outside diameter
A= C+bolt dia+.02 m
Bolt area Ab= 3421.195 mm2 (Ref: Pg-106, B.C.B.)
A= 0.891 m2 (Ref: Pg-106, B.C.B.)
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Bachelor Thesis Project 2010
Check if gasket
width = AbSg/( π GN) = 28.15<2y
therefore, condition is satisfied
4. Flange moment computations
For operating conditions
Total load, Wo = W1+W2+W3 (Ref: Pg-113, B.C.B.)
Hydrostatic end force on area inside the flange
(Ref: Pg-113, B.C.B.)
W1 0.522761 MN
W2=H-W1 0.0264648 MN (Ref: Pg-113, B.C.B.)
W3=W0-H= Hp
0.1004681
33 MN
Moment arms for flange load,
a1 = (C-B)/2 0.03
a3=(C-G)/2 0.02
a2=(a1+a3)/2 0.025
Total flange moment,
M0
W1*A1+W2*A2+W3*A
3 0.018353813 MJ
For bolting up conditions
Total flange moment ,
Mg= W*A3
W=(Am+Ab)/2*Sg
0.6978624
81 MN
Mg= 0.0139572 MJ
taking larger of two
M= 0.0183538 MJ
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5. Calculation of flange thickness
using flange moc as IS 2004-1962 class 2 type vessel
Sfo= 8.40E+07 N/m2 8.40E+01 MN/m2
(Ref: Pg-261,
B.C.B.)
K 1.11 (Ref: Pg-115, B.C.B.)
from graphs on Pg 115 BCB,
Y 12
Assuming
Sr=Sfo 84MN/m2 (Ref: Pg-117, B.C.B.)
Sz=1.5Sfo = 1.26E+02MN/m2
initially taking St = Sfo and assumig Cf=1 for first iteration,
Therefore, thickness of flange, t= 0.082
m
Actual Bs 0.075 (Ref: Pg-113, B.C.B.)
Therefore, bolt pitch correction factor,
Cf 0.8492 (Cf =(Bs/(2d+t))^.5)
(Ref: Pg-117, B.C.B.)
Actual flange thickness
0.0756 m
(t’ = t*Cf^.5) (Ref: Pg-117, B.C.B.)
Design for Tall Vessels
Calculations
Thickness of insulation = 50 mm
y = specific weight of shell = 77000 N/m3
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FO
MC Yt
BS
Bachelor Thesis Project 2010
(Ref: Pg-269,Table A-8 B.C.B.)
ρs = specific density of shell = 7850 kg/m3
Stress due to dead loads
σzp=Axial stress due to pressure = PdDi2/(4*t*(Di+t))=
5.77E+01 MN/m2
Ws/X = Weight of shell per unit length = π*(Di+t)*ts*y =
1.13E-02 MN/m3
where X = length
σzs /X = Axial stress due to stress loads per unit length = Ws/( π*ts*(Di+ts)) =
0.01186
78 N/m3
Wa/X = Weight of all attachments per unit length = 18% of Ws/X =
2.03E-
03
MN/
m
(Ref: Pg-145, B.C.B.)
σza /X = Axial stress due to weight of attachments per unit length = Wa/X( π*ts*(Di+ts))=
0.01384
58
MN/
m3
σzw /X = σzs /X + σza /X =
0.0257135
88 MN/m3
(Ref: Pg-105,sec. 9.2.3.4, Eq. 9.3.6, B.C.B.)
Wi/X= weight of insulation for a length X meters=tins*Yins/t
0.01566
67
MN/
m
Period of vibration
W = Weight of column for a height (H-h)
= 28.97073 kN
T=Period of vibration = 6.35 * 10-5 * (H/D)3/2 * (W/t)1/2 = 3.18E- Sec
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02
(Ref: Pg-
151, Eq.
9. .3.23,
B.C.B.)
K2 = coefficient depending on period of one cycle of vibration of the vessel
= 1 (if T is less than or equal to 0.5 sec)
= 2 (if T is greater than 0.5 sec) (Ref: Pg-147, B.C.B.)
K1 = coefficient depending on the shape factor
= 1.4 for flat plate
= 0.7 for cylindrical vessel
(Ref: Pg-147, B.C.B.)
so K1= 0.7
K2= 1
Stress due to wind loads
pw=wind pressure = 0.05Vw2 = 980 N/m2
Ref: Pg-146, Eq. 9.3.8, B.C.B.)
Vw = 140 kph
Pw = wind load = pw*(Di+t)* K1 * K2 = 2.00E+03 N/m
(Ref: Pg-146, Eq. 9.3.9, B.C.B.)
Mw/X2 = bending moment at the base of the vessel due to wind load = Pw/2 =
9.99E+0
2 J/m2
(Ref: Pg-146, Eq. 9.3.11, B.C.B.)
σzwm / X2 = bending stress in the axial direction = 4*Mw/( π*(Di+ts)2 *ts) =
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Bachelor Thesis Project 2010
0.00935
08
MN/
m2
(Ref: Pg-146, Eq. 9.3.13, B.C.B.)
σz (tensile)(max) = σzp - σzw + σzwm = fJ = 1.16E+02 MN/m2
hence, length = Xmax= 25.41 m >>11 m (Ref: Pg-146, Eq. 9.4.3, B.C.B.)
So, the column is stable under wind loads and no stiffners are required.
Design of skirt thickness
Pw= K1K2pwHD
For minimum weight condition Do= 2.932 m
For maximum weight condition Do= 2.982 m (insulated)
Pw(min)= 27851.6 N
Pw(max)= 28639.128 N
Maximum and minimum wind moments are computed by
Mw(min)=Pw(min)*H/2 0.1949612 MJ
Mw(max)=Pw(max)*H/2
0.2004738
96 MJ
As the thickness of skirt is expected to be small, assume
Di=Do= 2.932 m
t*σzwm(min)= 0.0288756 MN/m
t*σzwm(max)= 0.029692 MN/m
Wmin= 90 kN
Wmax= 510 kN
t*σzw(min)=Wmin/(πd)
0.0097707
67 MN/m
t*σzw(min)=Wmax/(πd) 0.0553676 MN/m
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81
t*σz(tensile)= 0.0191048
now, σz(tensile)=fJ 1.16E+02 MN/m2
t= 1.64E-01 mm
As per IS: 2825-1969, minimum corroded skirt thickness is 7 mm.
Providing a corrosion allowance of 1mm, a standard 8 mm thick plate can be used for skirt.
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4.9 Process Control and Instrumentation
The process control system should be capable of withstanding certain adverse environmental
conditions, and at the same time, assure certain magnitude of accuracy, repeatability, time
response or other combinations of characteristics listed above.
Deciding a control system implies:
a) Identification of control objectives
b) Selection of appropriate measurements and manipulations.
c) Selection of a control configuration.
d) Take into account the interaction between the controlling loops.
e) Identification of proper control valves.
A good understanding of chemical and physical phenomena is important for the design of
simple, but yet effective, control systems. Several alternative control configurations exist for a
given process. The selection of a best configuration is possible by fixing the objectives of the
control system.
Hardware elements of a control system:
1. The chemical process: Material equipment together with the physical or chemical
operations occurring there.
2. Measuring Instruments / Sensors: These are the main sources of the information about
the current state of process and are used to measure the disturbances, the controlled output
variables, or the secondary variables (e.g. in inference control).
3. Transducers: Used to convert the control measurements into actual physical quantities
for easier transmission.
4. Transmission Lines: Carry the information from the measuring device to the controller,
and the control signal to the process. These are the two types transmission lines – a) the
pneumatic and b) the electrical.
5. Controller: It is an intelligent hardware element that receives information from the
measuring devices and decides upon the control actions.
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6. Final control element: This physically implements the control decision take by the
controller.
7. Recording Elements: These provide a visual demonstration of the behaviour of the
chemical process.
Design and Operation of typical Control Systems:
1. Level Control: This control is used to control the level of a fluid in equipment using
simple mass balances. A level transducer (LT) measures the level in tank and sends a signal to
the level controller (LC). The LC compares the signal with the set point value and sends a signal
to the control valve actuator that positions the control valve adjusting the flow out. Level
control can be float actuated devices coupled with various types of indicators and signal
converters, liquid level pressure devices etc.. Since we can achieve acceptable offset with the
moderate values of gain we can use simple proportional controller for this type of control
system.
2. Pressure Control: The pressure controller maintains the mass balances in the tank by
matching the flow out of the tank to the total mass flow into the tank. The pressure control
loop consists of the pressure transducer (PT) , the pressure controller and the control
valve. The control valve is fail-to-close type and this requires that the pressure controller be
direct acting, so when the pressure in the tank increases the controller increases its output
signal to open the valve and increase flow out of the tank. The PC does not set the actual outlet
flow because a steady state the outlet flow must be equal to the total flow into the tank. The PC
must actually adjust the control valve until the outlet flow matches the inlet flow. Similarly, the
PC could adjust a control valve on the inlet stream to match the gas demand from the tank.
Typical pressure measuring devices that are manometers with floaters or displacers, burden-
tube elements, strain gages, piezoelectric elements etc. A simple proportional controller can be
employed for pressure control.
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Bachelor Thesis Project 2010
3. Flow Control: Practically every unit operation in chemical industry requires the
transportation of fluids. In almost every control scheme the manipulated variable is the flow of
fluid. Therefore flow control becomes a very important aspect in the overall control scheme.
Air actuated control valves represent the most common way of manipulating flow in the
industrial control systems. The actual actuator converts the signal to the valve to lift ‘x’ , which
is the fraction the valve is opened. The flow through the valve then depends on the lift , the
inlet pressure and the outlet pressure. The rangeability or the turndown ratio of a control valve
is defined as the ratio of the controllable flow .
The most common final control element is the pneumatic valve. This is an air operated valve ,
which controls the flow through an orifice by positioning appropriately a plug. The plug is
attached at the end of the stream , which is supported on the diaphragm at the other end. As
the air pressure above the diaphragm increases , he stem moves down and consequently the
plug restricts the flow through the orifice. Such a valve is known as an air to close valve. If the
air supply above the diaphragm is lost , the valve will fail-open since the spring would push the
stem and the plug upward. There are pneumatic valves with opposite actions.
Flow can be measured by finding the pressure drop across a flow constriction like in the orifice
plates, venture flow nozzle , turbine flow meters etc. A proportional integral is normally used to
control flow. Since the response of a flow system is rather fast , the speed of the closed loop
remains satisfactory despite the slowdown caused by the integral control mode.
4. Temperature Control: The control maintains the desired temperature in the
equipments reactants stream etc. Temperature measurement can be done by sensors like
resistance temperature devices , thermocouples, resistance bulb thermometers, thermistors
etc. Unlike the pressure and flow sensors which are fast acting, temperature measurement is
subject to a time lag due to the capacitance of the sensor thermo well assembly. And the
resistance to heat transfer to the bulk of the fluid and thermo well. In order to compensate the
measurement lag , temperature controllers are typically proportional- integral derivative
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Bachelor Thesis Project 2010
controllers. The derivative mode compensates for the sensor lag by acting on the time rate of
change of the transmitter signal.
5. Composition Control: It is specific type of control system which is generally convenient
for on or two chemicals. Though it requires a long time for analysis manually but with
computers and advanced instrumentation technique it is now possible to implement
composition control online , e.g. the lab chip technique. The composition measurement can be
done with the help of chromatic analyzer,infra-red analyser, oscillometric analyzer and
differential thermal analyzer . but the basic disadvantage is that it is expensive for low cost
control loop.
6. Ratio Control: It is a specific type of feed forward control whre disturbances are
measured and held in constant ratio to each other . it is mostly used to control the ratio of flow
rates of two streams. Both flow rates can be measured but only one can be controlled. The
stream whose flow rat is not under control is usually referred as the wild stream.
7. Cascade Control: In a cascade control , there is one manipulated variable and more than
one measurement. In this scheme, the disturbances arising within the secondary loop are
corrected by the secondary controller before they can affect the valve of the primary controlled
output.
8. Spilt Range Control: It consists of on measurement only and more than one
manipulated variable. In this scheme , the control signal is split int several parts, each affecting
one of the variable manipulations. Thus a process output can be controlled by co-ordinating the
actions of several manipulated variables, all of which have the same effect on the controlled
output. These systems provide added safety and operational optimality whenever necessary.
Plant Control Systems:
Storage Tank Control Systems
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Bachelor Thesis Project 2010
Degree of freedom: 1
Level controller is used to maintain required liquid level within the storage tank. The level
transducer controls the outflow of the liquid stream from the bottom by providing signal to the
solenoid switch. This switch acts upon the pump by varying its speed and thus regulating the
flowrate of the outlet system.
Figure 15 PID of Storage tank
Gasifier
The level control of the slag in the gasifier is necessary to protect the walls of the gasifier, and
also to prevent the heat leakage. I heat is allowed to escape then not only is some heat wasted
but also to maintain the desired temperature in the gasifier a large amount of CO2 would be
formed which would disturb the output composition and adversely affect the efficiency of thee
process. For the same purpose, a level control is employed which monitors the level of the slag
in gasifier and accordingly modifies the outflow of the slag.
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Since Pressure
maintenance is also of
161
Figure 16 PID of Storage Tank
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vital importance, it is controlled by manipulating the flow of Syn-Gas mixture produced at the
outlet of the gasifier.
Here the level control is cascaded with the composition of raw syn-gas produced at the outlet
stream m7,so that we get raw syngas at required composition.
Since it is necessary to maintain fixed oxygen to gas (N2+coke) ratio, the flow of coke is
controlled by employing a ratio controller which multiplies the flow rate of oxygen with the
desired ratio to give the flow rate of coke required.
Similarly, to maintain the steam to gas ratio, a ration controller is employed which takes the
input value as the gas flow rate, multiplies it by desired ratio, and further controls the amount
of steam entering the gasifier.
Waste Heat Boiler System
Degree of freedom: 1
Here, we employ an override control to check the level as well as the pressure of the waste
heat boiler. Usually, the steam pressure in a boiler is controlled through the use of pressure
control loop, but if the level fails below a certain limit, level control is employed using a low
switch selector (LSS) and closes the valve on the outlet stream .
Scrubber
Degree of freedom: 1
The objective of the scrubber is to recover as much as possible of the solute absorbed.
Variables that affect the fraction of solute recovered for a given scrubber are the solubility if
the solute in solvent, a function of temperature and pressure, and the ration of the solvent rate
to feed gas rate.
To maintain L/G ratio, a ration controller is employed which receives the signal from the gas
flow transmitter, multiplies it by the ration set point and sends this prodct to the set point of
the solvent flow controller.
Absorber
Degree of freedom: 1
The objective of the absorber is to recover as much as possible of the solute absorbed.
Variables that affect the fraction of solute recovered for a given absorber are the solubility if
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the solute in solvent, a function of temperature and pressure, and the ration of the solvent rate
to feed gas rate.
To maintain L/G ratio, a ratio controller is employed which receives the signal from the gas flow
transmitter, multiplies it by the ratio set point and sends this product to the set point of the
solvent flow controller.
Figure 17 PID of Absorber
Stripper
Degree of freedom: 1
It is similar to absorber.
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To maintain L/G ratio, a ratio controller is employed which receives the signal from the gas flow
transmitter, multiplies it by the ratio set point and sends this product to the set point of the gas
flow controller(steam entering stripper)
Heat Exchanger system
Degree of freedom: 1
The exit temperature is an indication of how much heat is transferred in the heat exchanger. It
follows that the manipulation in flow of inlet stream will lead to the control of the exit stream
temperature.
Temperature controller is required to control the temperature of outlet stream .Hence, the
flowrate of the BFW entering as coolant is manipulated accordingly.
4.10 Material Storage, handling and safety
Syngas
Compressed gas storage is the most relevant large-scale stationary storage systems for syngas
production facilities, as it can be readily used for syngas and SNG containing either hydrogen or
methane. Compressed gas storage is the simplest storage solution as the only required
equipment required is a compressor and a pressure vessel. The main problem with compressed
gas storage is the low storage density, which depends on the storage pressure. Compressed gas
can be stored in high and low pressure above ground vessels, existing pipelines, and in
underground cavities.
Compressors
Compressed gas storage requires a compressor to provide the necessary mass flow of gas into
the storage vessel. No literature discusses syngas compression or compressor requirements for
syngas service, however reasonable estimates can be drawn from literature discussing
compressors for natural gas and hydrogen service. The density and molecular weight of the gas
to be compressed is an important consideration for compressor choice. Centrifugal
compressors, which are widely used for natural gas, are not generally suitable for pure
hydrogen compression as the pressure rise per stage is very small due to the low density and
low molecular weight. Positive displacement, reciprocating compressors may be the best choice
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for large-scale hydrogen compression, and hydrogen can be compressed using standard axial,
radial or reciprocating piston-type compressors with slight modifications of the seals to take
into account the higher diffusivity of the hydrogen molecules.
Technical Issues
Hydrogen Embrittlement
There is significant research on embrittlement and other metallurgical issues associated with
hydrogen and hydrogen-rich gases. The oil and gas industry has recognized internal and
external hydrogen attack on steel pipelines, described variously as hydrogen-induced cracking
(or corrosion) (HIC), hydrogen corrosion cracking (HCC), stress corrosion cracking (SCC),
hydrogen embrittlement (HE), and delayed failure. These issues are serious; corrosion damages
cause most of the failures and emergencies of trunk gas pipelines, and stress corrosion defects
of pipelines are extremely severe. Corrosion defects, such as general corrosion, pitting
corrosion and SCC, make up the major number of detected effects in pipelines. Hydrogen can
cause corrosion, hydrogen induced cracking or hydrogen embrittlement if there is a mechanism
that produces atomic hydrogen (H+). Atomic hydrogen diffuses 33 into a metal and reforms as
microscopic pockets of molecular hydrogen gas, causing cracking, embrittlement, and corrosion
which can ultimately lead to failure. The hardness of a metal correlates to the degree of
embrittlement; if a material has a Vickers Hardness Number (VHN) greater than 300, the
tendency for the material to fail due to plastic straining when there is significant absorption of
atomic hydrogen is greater than with a softer material. Molecular hydrogen (H2) alone does not
cause embrittlement of steel; however problems can arise if there is a mechanism that
produces atomic hydrogen. The two primary mechanisms leading to hydrogen induced cracking
are HIC due to wet conditions and HIC due to elevated temperatures. Temperatures greater
than 220°C can cause dissociation of molecular hydrogen into atomic hydrogen. Studies show
that molecular hydrogen should be water dry, or below 60 percent relative humidity, to provide
a sufficient margin for avoidance of moisture and water dropout. Molecular hydrogen then,
may be handled without problems with standard low-alloy carbon steel irrespective of the gas
pressure, provided that the conditions are dry (to prevent HIC due to wet conditions) and under
220°C (to prevent HIC due to elevated temperatures) (IEA GHG 2002). Because of the
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metallurgical issues associated with hydrogen, care must be taken when choosing metals for
hydrogen pipelines and storage. Surveys of existing hydrogen pipelines show that a variety of
steels, but primarily mild steel, is in use. Options for steel pipe for 100 percent hydrogen service
include Al-Fe (aluminum-iron) alloy; and variable-hardness pipe, with the harder material in the
interior and softer material toward the exterior, so that any hydrogen which diffuses into the
interior steel diffuses rapidly outward and escapes. Existing natural gas pipelines can be used
for less than 15 to 20 percent hydrogen, by volume, without danger of hydrogen attack on the
line pipe steel, however further hydrogen enrichment will risk hydrogen embrittlement. Existing
pipelines originally designed for sour service can provide additional protection against HIC and
hydrogen embrittlement due to their specific metallurgy (IEA GHG 2002). If hydrogen
embrittlement is found to be a potential problem for an unusual situation, costs for any
materials will be relatively low. Steel used for hydrogen transport and storage are low carbon
steel and low in alloy content. These steels may have a restriction of some alloy elements
(those that attract and stabilize H and a structure called austenite); however the cost should
not be affect by these restrictions. For large diameter pipelines and vessels, options include low
carbon steel plate, such as type X52, which is easy to make, readily available, easy to weld, and
easy to fabricate. Smaller pipes can be constructed from either seamless or welded pipe. The
main failure of the material is by hydrogen embrittlement in the zone near the weld. This area
is affected by the heating and cooling during welding and has more internal stress. Because of
the care required for welding, the most costly component is likely welding by certified welders.
Syngas Leakage
An additional potential problem resulting from the hydrogen content of syngas is that atomic
hydrogen is a small molecule and can diffuse through most metals. However industrial
experience with syngas and analogies with other industrial practices suggests that excessive
diffusion and leakage of syngas through a storage chamber wall is not an issue for diurnal and
relatively short-term storage.
Biological Fouling
The subsurface storage of gas raises the issues of microbial factors and the risks of biological
fouling. That is, conditions may exist underground where microbes can rapidly grow causing a
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number of potential problems such as contamination of the gas, plugging of the storage vessel,
degrading its capacity, and biocorrosion. We have discussed these issues with a number of
experts and professionals with significant industrial experience and conclude that biological
fouling is likely not an issues for diurnal gas storage. The rapid turnover and short residence
time of gas in an underground vessel is not likely to produce conditions conducive to rapid
microbial growth. Furthermore, should fouling occur, ‘work-overs’ are common and expected in
industrial practice.
Coal
Coal can be recovered from different mining techniques like:
shallow seams by removing the overburden to expose the coal seam
under-ground mining.
Once the coal is received the size reduction operations at the power plant are confined to
crushing. Coal particle size degradation occurs in transport and handling and must be taken into
account for size specifications. The coal handling plant is used to store, transport and distribute
coal which comes from the mine. The coal is delivered either through a conveyor belt system or
by rail or road transport. The bulk storage of coal at the power station is important for the
continuous supply of fuel. At our 2500 tons of coal are required per day. The coal handling plant
stores 12500 tons of coal, which consist of three stockpiles and an emergency stockpile. Usually
the stockpiles are divided into three main categories;
live storage
emergency storage
long term compacted stockpile
When coals from different sources are used, blending is required to supply the boiler with a
uniform feed of coal.
Coal is susceptible to spontaneous combustion, most commonly due to oxidation of pyrite or
other sulphidic contaminants in coal. Coal preparation operations also present a fire and
explosion hazard due to the generation of coal dust, which may ignite depending on its
concentration in air and presence of ignition sources. Coal dust therefore represents a
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significant explosion hazard in coal storage and handling facilities where coal dust clouds may
be generated in enclosed spaces. Dust clouds also may be present wherever loose coal dust
accumulates, such as on structural ledges. Recommended techniques to prevent and control
combustion and explosion hazards in enclosed coal storage include the following:
Storing coal piles so as to prevent or minimize the likelihood of combustion, including:
o Compacting coal piles to reduce the amount of air within the pile,
o Minimizing coal storage times,
o Avoiding placement of coal piles above heat sources such as steam lines or manholes,
o Constructing coal storage structures with noncombustible materials,
o Designing coal storage structures to minimize the surface areas on which coal dust can
settle and providing dust removal systems, and
o Continuous monitoring for hot spots (ignited coal) using temperature detection systems.
When a hot spot is detected, the ignited coal should be removed. Access should be provided for
firefighting
o Eliminating the presence of potential sources of ignition, and providing appropriate
equipment grounding to minimize static electricity hazards. All machinery and electrical
equipment inside the enclosed coal storage area or structure should be approved for use in
hazardous locations and provided with spark-proof motors;
o All electrical circuits should be designed for automatic, remote shutdown; and
o Installation of an adequate lateral ventilation system in enclosed storage areas to
reduce concentrations of methane, carbon monoxide, and volatile products from coal oxidation
by air, and to deal with smoke in the event of a fire.
Safety for storing coal
Recommended techniques to prevent and control explosion risks due to coal preparation in an
enclosed area include the following:
Conduct dry coal screening, crushing, dry cleaning, grinding, pulverizing and other
operations producing coal dust under nitrogen blanket or other explosion prevention
approaches such as ventilation;
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Locate the facilities to minimize fire and explosion exposure to other major buildings
and equipment;
Consider controlling the moisture content of coal prior to use, depending on the
requirements of the gasification technology;
Install failsafe monitoring of methane concentrations in air, and halt operations if a
methane concentration of 40 percent of the lower explosion limit is reached;
Install and properly maintain dust collector systems to capture fugitive emissions from
coal-handling equipment or machinery.
Ash
Depending on their toxicity and radioactivity, coal bottom ash, slag, and fly ash may be
recycled, given the availability of commercially and technical viable options. Recommended
recycling methods include:
Use of bottom ash as an aggregate in lightweight concrete masonry units, as raw feed
material in the production of Portland cement, road base and sub-base aggregate, or as
structural fill material, and as fine aggregate in asphalt paving and flowable fill;
Use of slag as blasting grit, as roofing shingle granules, for snow and ice control, as
aggregate in asphalt paving, as a structural fill, and in road base and sub-base applications;
Use of fly ash in construction materials requiring a pozzolanic material.
Where due to its toxic / radioactive characteristics or unavailability of commercially and
technically viable alternatives these materials cannot be recycled, they have to be disposed of
in a licensed landfill facility designed and operated according to good international industry
practice.
Diethyl Amine (DEA)
This should be protected against physical damage and store in a cool, dry well-ventilated
location, away from any area where the fire hazard may occur (Outside or detached storage
should preferred).It has to be separated from incompatibles. Containers should be bonded and
grounded for transfers to avoid static sparks. Storage and use areas should be No Smoking
areas. Non-sparking type tools and equipment should be used, including explosion proof
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ventilation. Empty containers may contain explosive vapors. Hence should be made aware of it.
Empty containers are flushed with water to remove residual flammable liquid and vapors.
Containers of this material may be hazardous when empty since they retain product residues
(vapors, liquid) hence we have to observe all warnings and precautions listed for the product.
So that risk can be avoided.
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Environmental
Protection and
Energy
Conservation
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5.1 ENVIRONMENAL ASPECTS:
5.1.1 Air Pollution:
In the plant, there is no release of harmful flue gases and hence there are not much air
pollution hazards associated with the plant. There are three independent ways to estimate air
pollution emission rates. One approach is to make a material balance across the entire process.
Another technique is use of emissive factors published data on the weight of the contaminants
generated per unit of fuel burnt or raw material processed. But The main sources of emissions
in coal processing facilities primarily consist of fugitive sources of particulate matter (PM),
volatile organic compounds (VOCs), carbon monoxide (CO), and hydrogen. Coal transfer,
storage, and preparation activities may contribute significantly to fugitive emissions of coal PM.
Recommendations to prevent and control fugitive coal PM emissions include the following:
Design of the plant or facility layout to facilitate emissions management and to reduce
the number of coal transfer points;
Use of loading and unloading equipment to minimize the height of coal drop to the
stockpile;
Use of water spray systems and/or polymer coatings to reduce the formation of fugitive
dust from coal storage (e.g. on stockpiles) as feasible depending on the coal quality
requirements;
Capture of coal dust emissions from crushing / sizing activities and conveying to a
baghouse filter or other particulate control equipment;
Use of centrifugal (cyclone) collectors followed by high-efficiency venturi aqueous
scrubbers for thermal dryers;
Use of centrifugal (cyclone) collectors followed by fabric filtration for pneumatic coal
cleaning equipment;
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Use of enclosed conveyors combined with extraction and filtration equipment on
conveyor transfer points; and·
Suppression of dust during coal processing (e.g., crushing, sizing, and drying) and
transfer (e.g., conveyor systems) using, for example, ware spraying systems with water
collection and subsequent treatment or re-use of the collected water.
Ambient air quality standards:
Pollutant Threshold limit
CO 50 ppm
CO2 5000 ppm
SO2 5 ppm
H2S 10 ppm
NO 25 ppm
NO2 5 ppm
NH3 100 ppm
Acceptable limit for pollutants:
Parameters
(mg/m3)
Industrial Area Residential and Agro
Area
Sesitive Area
SPM 500 200 100
Meatallic Dust 50 30 15
SO3&H2SO4 100 50 20
SO2(ppm) 500 200 100
CO(ppm) 100 50 30
Exhaust Gases
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Combustion of SynGas or gas oil for power and heat generation at coal processing facilities is a
significant source of air emissions, including CO2, nitrogen oxides (NOX), SO2, and, in the event
of burner malfunction, carbon monoxide (CO).
Guidance for the management of small combustion processes designed to deliver electrical or
mechanical power, steam, heat, or any combination of these, regardless of the fuel type, with a
total rated heat input capacity of 50 Megawatt thermal (MWth) is provided in the General EHS
Guidelines. Guidance applicable to processes larger than 50 MWth is provided in the EHS
As the syngas produced will be most probably used for electricity generation by combustion,
these emissions should be taken into account.
Emissions related to the operation of power sources should be minimized through the adoption
of a combined strategy which includes a reduction in energy demand, use of cleaner fuels, and
application of emissions controls where required. Recommendations on energy efficiency are
addressed in the General EHS Guidelines.
Venting and Flaring
Venting and flaring is an important operational and safety measure used in coal processing
facilities to ensure gas is safely disposed of in the event of an emergency, power or equipment
failure, or other plant upset conditions. Unreacted raw materials and by-product combustible
gases are also disposed of through venting and flaring. Excess gas should not be vented but
instead sent to an efficient flare gas system for disposal.
Recommendations to minimize gas venting and flaring include the following:
Optimize plant controls to increase the reaction conversion rates;
Utilize unreacted raw materials and by-product combustible gases for power generation
or heat recovery, if possible;
Provide back-up systems to maximize plant reliability; and
Locate flaring systems at a safe distance from personnel accommodations and
residential areas and maintain flaring systems to achieve high efficiency.
Emergency venting may be acceptable under certain conditions where flaring of the gas stream
is not appropriate. Standard risk assessment methodologies should be utilized to analyze such
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situations. Justification for not using a gas flaring system should be fully documented before an
emergency gas venting facility is considered.
5.1.2 Solid waste disposal:
Possible Sources:
There is no substantial solid waste in the plant, the only solid waste will be dried sludge from
the effluent treatment plant, canteen wastes, worn office equipment and tools , stationery,
cleaning rags, packing boxes, broken pallets and broken office chairs.
Disposal Technique:
Solid waste disposal is done by thermal incineration or by tipping. The design of a solid waste
incinerator is difficult to do due to the wide variety of feed to be disposed. it is important to
determine the burning characteristics of the solid waste material. A major problem with the
solid incinerator is fly ash control. Various methods employed for this purpose ate two-stage
combustion, filter baffle and provision of large secondary chambers where velocities are low
and settling takes place. If the fly ash problem is chronic , special separation devices like
electrostatic precipitators can be employed. The flash produced can be used as a land fill.
5.1.3 Noise Pollution:
The major sources of noise pollution in our plant are:
Pumps
Burners
Electric motors
Valves
Steam Vents
Various equipments, their noise levels and control measures are listed in the table below:
Equipment Sound level at 3 ft(dB)
Possible noise control
measures
Electric motors 90-110 Acoustically lined fan covers ,
enclosures and motor
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mutes , absorbent mounts.
Pumps
Vane(Industrial)
Vane(mobile)
Axial position
Screw type
Gear
75-82
84-92
76-85
72-78
78-88
Acoustically lined fan covers,
enclosures and motor mutes,
absorbent mutes.
Heaters and furnaces 90-110 Acoustic plenums, intake
mufflers, lined/ damped
ducts
Valves 80-108 Avoid sonic velocities, limit
pressure drop and mass flow
, replace with special low
noise valves.
Piping 90-105 Isolation and lagging, in liner
silencers, vibration isolators.
Apart from the listed noise sources, minor sources of the noise pollution may be pipes and
hoses hitting the floor, panels etc. i.e. rattling noises, which can be stabilized with adsorbent
mounts. All the bolts should be tightened to prevent vibration and clatter.
Venting of process gas out the condensers may result in serious noise pollutions. This is due to
turbulent mixing of high velocity gas with the stationary gas. Steam leaks and another common
noise problem with the sound level are reaching sometimes 100 dB at the distance of 25 feet of
the leak. All steam leaks should be timely repaired. Where noise levels cannot be reduced to
acceptable levels of a person, ear protection equipment should be used.
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5.2 Energy Integration and Conservation:
5.2.1 CONSERVATION:
Chemical plants have always been designed to operate and economically due to product
competition. However before 1970, the objectives of building a low cost plant was generally
considered more important than low operating cost. This concept changed due to the oil crisis
of 1973 and the subsequent action at several environment protection agencies in promoting
the use of non-low polluting attention has been paid to such topics such as energy conservation
schemes, process integration, heat exchanger network design, cogeneration etc. This attention
is evident by the large number of books and journals published on these topics in the recent
years.
The design engineer must consider appropriate energy conservation schemes that are designed
to:
(i) Utilize as much of the energy available within the plant.
(ii) Minimize the energy requirements for the plant.
The energy balances performed for the plant items provide the initial key to identify areas of
high energy availability or demand. An attempt can then be made to utilize excess energy in
those areas where energy must be provided. However, this is not always possible because:
(i) A high energy load may constitute a large volume of liquid at relatively low temperature,
exchanging this energy may require a large and expensive equipment.
(ii) This energy source may be distant from the sink and piping and insulating costs may
make utilization uneconomic, sometimes a rearrangement of the plant lay out required.
(iii) The energy source may be corrosive.
Any energy conservation scheme must also consider the costs involved in removing or
transferring the excess energy i.e. capital cost of heat exchangers, piping , valves, pumps,
insulation and operating costs of pumping and maintenance. Energy conservation is only
worthwhile if the reduction in energy costs exceed the cost of implementation . a scheme may
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be devised for a plant and then held over until energy prices make the proposal attractive. This
type of forward planning requires that the plant layout adopted can be easily modified.
Energy conservation can be achieved at three levels:
(i) Correct plan and operation and maintenance
(ii) Major changes to existing plant and processes.
(iii) New plants and new processes.
The time required to implement energy conservation measures, the capital cost required, and
the potential savings, all increase from level (i) t (iii) above. The cost of downtime for level (ii)
can be significant, and the level (iii) offers the greatest long term potential for energy
conservation. This latter objective can be achieved either by designing new, energy efficient
plants for established process routes, or adopting new and less energy- intensive process
routes. The areas immediately obvious for consideration of energy are the oxygen and steam
preheating section of the plant and the utilization of energy obtained from the gasifier and the
water gas shift reactors. The basic approach towards conservation of energy should be taken
into account:
(i) Operational modification
(ii) Research and development
(iii) Design modification
(iv) Insulation
(v) Maintenance
(vi) Process integration
(vii) Process modification
(viii) Waste utilization
In the near future all industrial operations that have reacted to the energy crisis must be
organised to institute a systematic approach towards conserving energy in all forms through
more efficient utilization of existing processes and carefully studied reduction of losses and
wastes. The following examples illustrate some application of the basic engineering principles t
the design of equipment for improved energy efficiency.
(i) Plant Operation:
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Energy savings can be achieved by good engineering practice and the application of established
principles. These measures may be termed as good housekeeping and include correct plant
operation and regular maintenance. The overall energy savings are usually small and may not
be easy to achieve and significant time may be required for regulate maintenance and checking.
However, such measures do help to establish commitment of a company to a policy of energy
conservation.
(ii) Heat Recovery:
Heat recovery is an important and fundamental method of energy conservation. The main
limitations of this method are:
(a) Inadequate scope for using recovered waste heat because it is too low grade for
existing heat requirements, and because the quantity of waste heat available exceeds existing
requirements for low- grade heat.
(b) Inadequate heat transfer equipment.
Developments and improvements are continuing in design and operation of different types of
heat exchangers including the use of extended heat transfer surfaces, optimizing heat
exchanger networks , heat recovery from waste fuels , heat exchanger fouling and the use of
heat pumps.
(iii) Combined Heat and Power Systems:
Significant energy conservation is achieved by well established method of combined heat and
power generation . this is often referred to as CHP or COGEN. The heat is usually in the form of
intermediate or low pressure steam and the power as direct mechanical drives or as electricity
generated with the turbo alternators. The choice of system is usually between back pressure
steam turbines or gas turbines with waste heat boilers for the process streams. The amount of
power generated is usually determined by the demand of heat.
It is not usually possible to balance exactly the heat and power loads in a system .the
best method of achieving this aim is to generate excess electricity for subsequent sale. other
balancing methods tend to be less efficient. Therefore it is important to fore cast the heat to
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power ratio accurately at the design stage to avoid large imbalances and reduced system
efficiency.
(iv) Power recovery systems:
A power recovery turbine can recover heat from an exchanger gas and then use this heat to
provide a part of the energy required to drive the shaft of a motor driven process air
compressor. Other examples are the use of the steam turbine drive and a two stage expansion
turbine with reheating between the stages.
A hydraulic turbine can be incorporated on the same shaft as a steam turbine . this
arrangement can be used to provide about 50% of the energy needed to recompress the spent
liquor in a high pressure absorption /low pressure stripping system.
Power generation using steam or gas turbine is now well established, however
power recovery by the pressure reduction of process fluids is more difficult and less common. in
general the equipment is not considered to be particularly reliable.rankine cycle heat engines
have been developed to use relatively low grade waste heat sources to generate power in the
form in the form of electricity or direct drives. They tend to be used when the heat source
would otherwise be completely wasted, the low efficiencies do not represent a significant
disadvantage.
(v) Furnace efficiency
Incorporating an air heater can be more economic than using a hot oil system which is
designed for high level heat only.
(vi) Air cooler v/s water cooler:
Air coolers have higher installed cost but lower operating cost water coolers.
(vii) Low pressure steam:
Energy savings can be achieved by the efficient use of low pressure steam.
(viii) Heat integration:
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Energy can be saved by optimum balance of heat sources and sinks in a process plant so as to
maximize recycling of energy input .thus however has to be done carefully as it leads to loss of
operational independence.
(ix) Thermal insulation :
Owing to the great size of the distillation column large amount of heat is dissipated from the
surface .This necessitates thermal insulation of distillation column reboiler and other piping
attached to it so that minimum heat is dissipated.Multi-layer energy saving insulation should be
used which provide protection from fire, liquid spillage and result in energy savings.Usually,
inner insulation layers are made from alumina silica fibres to reduce the heat loss from the
valves and joints to keep the system heat constant and prevent heat loss.
Instrumentation:
use of efficient instrumentation in the plant can result in consistent high quality of product and
lesser no. of rejections. In a plant design utmost care must be taken to conserve energy. The
reboiler and the heat exchanger should be set up after a long analysis
Energy conservation in the design of complete process may be achieved in four ways:
(i) Major modifications to the existing plants.
(ii) New plant using an existing process route.
(iii) New process routes and alternative raw materials.
(iv) New processes for new products that are less energy intensive.
Items (i) and (iii) represent short term and medium term energy conservation measures. Item
(iv) requiring the use of new products or processes is more appropriate for new technology in
the chemical industry. Although energy conservation is an obvious objective of all equipment
manufacturers and plant designers, more attention iis necessary in relation to education ,
training and the application of new and existing technology to ensure significant medium term
and long term savings.
Energy conservation must be considered at various stages of the project , e.g. feasibility study,
process selection , plant layout, energy balances and in conjunction with the detailed
equipment design. If he energy utilization is not only an afterthought , either unnecessary or
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costly modifications may be required to the design work, or the plant may not be economically
feasible as it originally appeared.
5.2.2 Energy Management:
The high value of energy should be acknowledged in plant operation by treating it as a product
with monetary value than can be sold or traded, just like the chemical product. This should be
the basis for operational policies concerned with the energy management or energy
conservation. These duties can be incorporated by the process engineer. EAM&T is a means to
efficient operation in this area, but there must be a commitment from all operational and
managerial personnel to the importance of these tasks if they are to be successful.
The reaction and product recovery areas have been identified as critical units from an energy
perspective. Detailed monitoring and targeting should be established in these areas. Variables
that should be recorded regularly for the gasifier include the feed and product flows and
temperature , yields of CO and H2 from the reactors, adsorbers and PSA , steam pressure and
reactor temperature profiles. A similar combination applies to condensers and heat exchangers.
Targets should be introduced and updated monthly or biannually. These targets, if constructed
correctly , allow performance to be measured easily accurately and provide an incentive for
operational staff to maintain and improve efficiency.
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5.3 Alternate Energy Resources
The fuel resources of the world are fast depleting and there is an urgent need to explore the
possibility of the alternate sources of energy. Although rapid breakthrough has been achieved
in the use of nuclear energy for the distillation of the steam, which in turn is used for the
generation of electricity, it is not used widely due to the lack of the flexibility in its utilization
and because of the non-feasibility of its operation on the smaller scale. Some of the alternate
energy sources being developed nowadays have been briefly discussed below:
Solar energy
Solar energy is the most important form of renewable energy for plant. The energy incident on
the solar panel installed in the roof and other areas of the plants are highly useful in heating up
the water and are converted to steam. This is one renewable source of the energy which is now
slowly finding wide acceptance in the process industry. In the process industry it is being used
widely for the heating the process water and in some cases for the production of the low
pressure steam. Energy conservation is not only concerned with the process industries but is
also concerned with other small household purposes carried out in the industrial areas. It can
also be used for the heating and providing warm water in the canteen and the other non
production areas in the process plant.
Energy from biomass conversion
Biomass in today’s Chemical Industries is going to play a vital role in the production of energy as
well as in different chemical products. The biomass have been widely used however
Major considerations include:
• Which raw materials will be needed in the new situation?
• How will biomass be processed?
• How will feedstock be made available at the appropriate location?
• What kind of storage facilities is needed?
• How can the production of bio-based bulk chemicals be integrated?
• How will products be shipped to the (geographic) area covered by the Port?
• Which are the most likely companies to produce new bio-based bulk chemicals?
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Two extremes can be envisioned by which the transformation to a biomass based chemical
industry may take place:
1. Biomass will be refined and ‘cracked’ into the familiar platform chemicals (i.e. ethylene,
propylene, C4-olefines and BTX) and synthesis gas (‘syngas’, a mixture of mainly carbon
monoxide and hydrogen gas). From these one- to six-carbon building blocks, all other chemicals
and materials can be produced. Provided that efficient processes will become available by
which oxygen-rich biomass of a varying composition can be transformed into basic hydrocarbon
building blocks, the big advantage is that the current petrochemicals infrastructure and
processes can be used. The fossil feedstock refining companies of today may then become the
bio-refineries of tomorrow.
2. A wide range of bio-based building blocks, in which as much of the functionality of
biomass as possible has been retained, become the raw materials from which all other
chemicals and materials are made. Not a few refineries that produce a limited number of
platform chemicals will be present, but a large number of (smaller scale) bio-refineries that
produce a whole array of building blocks.
Between these two extremes lies a whole spectrum of non-exclusive scenarios that are perhaps
more realistic. As a less extreme example of the first scenario: ethylene, one of the current
platform chemicals, can be produced from (bio) ethanol. In fact, the Brazilian company Braskem
and US based Dow Chemical will each start commercial production of polyethylene from bio-
ethanol. Bio-ethanol is currently made from sugar or starch. In the future, it is expected that
ethanol will be made from the more abundant lignocellulosic or ‘woody’ biomass.
The Gobar gas concept has found wide acceptance in the rural India. Although bioconversion
technology has been very successful in the waste treatment, the technology to generate energy
for the industrial uses is in early stages of the development. However, this technology holds
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great promise as its fundamental advantage is that apart from being a clean source of the fuel,
it is a renewable source of energy.
Ocean thermal energy:
The Ocean energy is one of the contributors in renewable energy. The temperature of the
water in the ocean varies drastically with the depth. The principal here is to run a heat engine
to retract heat energy from ocean by utilizing the difference in temperature of the ocean at
various depths. This technology is in the very early stages of the development and can only be
utilized if the plant is situated close to the coastlines.
Wind energy:
The unequal heating of the earth be the sun causes winds. This effect is particularly pronounced
in the coastal areas with a difference between the temperature for the land and the sea.
The force of the wind is used to rotate windmills, which are rotating blades to collect the force
of the wind. This mechanical energy produced can be used directly on it can be converted into
electrical energy. These have been used with partial success in the process industry, mainly to
pump water both process water and the water to effluent treatment plants. A 3.5 m diameter
develops about 0 to 60 hp in a 15 mph wind and can pump up to 35 gallons of the water per
minute to a height of about 10 m.
Potential for development of Renewable energy in India
SOURCE Installed capacity (MW) Potential (MW)
Small Hydro Power 1905 15000
Wind Power 6315 45695
Biomass Power 620 16881
Bagasse Cogeneration 602 5000
Solar Photovoltaic 3 500
Energy from Waste 52 2700
TOTAL 9497 85276
Source: Ministry of New and Renewable Energy, GoI ;as on 31.01.2007
Sector-wise Clean Technology market size
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Sectors Market Size ($billions) Estimated Growth Rate
Energy Efficiency & Renewable
Energy
3.00 15.00
Water & Wastewater Treatment 1.24 6.00
Solid Waste Management 0.41 10.00
Air Pollution Control 0.41 15.00
Environment Consulting* 0.12 20.00
Hazardous Waste Management 0.10 7.00
Total 5.29 15.00
* Providing knowledge based services for implementing environmental initiatives **Data as on
Jan 31, 2007
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5.4 Protection measures
5.4.1 Effluent Treatment Plant
Liquid Pollution
As such there are no liquid pollutants but the gases emitted in the form of THF , GBL and BDO
could result in acid rain which can create problems. These may get added to water bodies and
can cause pollution. Hence must be handled and stored carefully. The standards set by Water
(prevention control of pollution) Act are mentioned below:
Effluent Standards
Spent wash Condensate water Final effluentParameter Min. Max. Ave. Min. Max. Ave. Min. Max. Ave.
pH 4.2 5.1 4.5 7.3 8.0 7.7 4.4 5.5 4.9
COD, (mg/L) 70280 98000 87600 15.6 20.0 17.7 16640 74260 50950
BOD, (mg/L) 24300 38900 31750 4 11 6.4 8200 42300 20878
Total solids, 67344 94304 83154 416 It 1581 909 16588 59120 46666(mg/L) (8.3%)
Suspended 4796 10520 4619 4 310 111 948 20720 9088Solids, (mg/L) (0.46%)
Total volatile 44936 64296 56392 274 1078 542 12520 44398 32676solids, (mg/L) (5.63%)
Suspended 3828 9324 6701 28 196 112 880 14570 5492volatile (0.63%)solids, (mg/L)Total 896 1596 1232 - - - 392 1260 852Nitrogen as (0.123%)N, (mg/L)Total 15 68 34 - - - 5 27 17Phosphorous (0.0034)as P, (mg/L)
Source: Legislation: Water (prevention control of pollution) Act, 1974
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Water is used for in gasification plant for producing steam in the form of heat recovery as well
as for water scrubbing various impurities in the scrubber column. Most common effluent
treatment these days is activated sludge process. A block diagram is given below
Figure 18 Flow sheet of Activated Sludge System
Activated sludge plant involves:
1. wastewater aeration in the presence of a microbial suspension
2. solid-liquid separation following aeration
3. discharge of clarified effluent
4. wasting of excess biomass, and
5. return of remaining biomass to the aeration tank.
In activated sludge process wastewater containing organic matter is aerated in an aeration
basin in which micro-organisms metabolize the suspended and soluble organic matter. Part of
organic matter is synthesized into new cells and part is oxidized to CO2 and water to derive
energy. In activated sludge systems the new cells formed in the reaction are removed from the
liquid stream in the form of a flocculent sludge in settling tanks. A part of this settled biomass,
described as activated sludge is returned to the aeration tank and the remaining forms waste or
excess sludge.
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Screening and Grit Units - The purpose of this prestep is to remove large objects such as logs,
branches, rags, and small fish that could damage pumps and clog pipes and channels if they are
not removed. This step can also be used for grinding waste to reduce particle size.
Primary Settling Tanks - The oldest and most widely used form of water and wastewater
treatment uses gravity settling to remove particles from water. The shape of the tanks can be
round, square or rectangular. Sedimentation takes place in the primary settling tanks and is
relatively simple and inexpensive. Particulates suspended in surface water can range in size
from 10-1 to 10-7 mm in diameter, the size of fine sand and small clay respectively. Turbidity or
cloudiness in water is caused by those particles larger than 10-4 mm, while particles smaller
than 10-4 mm contribute to the water’s color and taste. Such very small particles may be
considered for treatment purposes, to be dissolved rather than particulate
Aeration Tanks - The waste water flows into an aeration chamber usually constructed of steel,
poly, fiberglass, or concrete. The aeration chamber normally provides 6 to 24 hours retention
time for the waste water. The contents of the aeration tank are referred to as mixed liquor, and
the solids are called mixed liquor suspended solids (MLSS). The latter includes inert material as
well as living and dead microbial cells. In the aeration tank, microorganisms are kept in
suspension for 4 to 8 hours by mechanical mixers and/or diffused air, and their concentration in
the tank is maintained by the continuous return of the settled biological floc from a secondary
settling tank to the aeration tank.
Final Settling Tanks - Like primary tanks, final tanks may be rectangular or circular, and
occasionally square, but they provide longer detention (2h) and lower overflow rates (30 to 50
m3/m2.day). The Final Settling Tanks can also be referred to as The Settling Chamber or a
Secondary Clarifier. The Final Settling Tanks receives the overflow of the aeration chamber.
When the sludge settles to the bottom of the tank, it is still active and it is able to remove more
BOD from the waste water. Returning the activated sludge to the aeration chamber on a
continuous basis maintains and increases the microorganism concentration in the aeration
chamber. This is a key factor to increase BOD removal from the waste water. The sludge will
continue to build up. Occasionally, some of the sludge should be drained to keep the effluent
from deteriorating.
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5.4.2 SULFUR
The sulfur compounds from the feedstock of a gasification-based process are generally
removed from the synthesis gas as a concentrated stream of hydrogen sulfide and carbon
dioxide, known as acid gas. Depending on the design of the upstream AGR unit, the acid gas
may contain other sulfur species, such as COS, as well as ammonia and hydrogen cyanide. It is
unacceptable to emit H2S, a highly toxic, foul-smelling gas, to the atmosphere, so it is necessary
to fix it in one form or other.
There are essentially two alternative products in which the sulfur can be fixed, either as liquid
or solid elemental sulfur, or as sulfuric acid. The choice of product will depend on the local
market. Where there is a strong local phosphate industry, then there will be a good local
market for sulfuric acid. If this is not the case, then elemental sulfur will probably be the better
choice, since bulk transport of this material is much easier than of the concentrated sulfuric
acid.
The Claus process
The basic Claus process for substoichiometric combustion of H2S to elemental sulfur was
developed as a single-stage process on the basis of below reaction at the end
3H 2S+112O2↔3H 2O+ 3
8S8
of the nineteenth century. During the 1930s it was modified into a two-stage process in which
initially one-third of the H2S was combusted to SO2 and water and, in a second low
temperature catalytic stage, the SO2 was reacted with the remaining H2S to sulfur. Operating
the second stage at a comparatively low temperature (200–300°C) used the more favorable
equilibrium to achieve much higher sulfur yields than had been possible with the original
process.
A typical standard Claus process is shown in the next page.
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Figure 19 Typical two-stage Claus unit
(source: Weiss, 1997).
In the first combustion stage all the H2S is combusted with an amount of air corresponding to
the stoichiometry of reaction (8.8) at a temperature in the range 1000–1200°C. The
thermodynamics of the three main reactions above are such that about half the total sulfur is
present in the outlet gas as elemental sulfur vapor, the rest as an equal mix of H2S and SO2. The
hot gas is cooled by raising steam, and the sulfur already formed is condensed out. The removal
of sulfur at this point assists in driving reaction (8.7) further to the right in the subsequent
catalytic stage. The gas is reheated and passed over an alumina catalyst at a temperature of
about 250–300°C, and cooled again to condense the sulfur formed. This may be performeda
number of times to remove further amounts of sulfur. Typically, two (as shown in the above
figure) or three catalytic stages are used.
COS hydrolysis
In all synthesis gases produced by gasification, sulfur is present not only as H2S, but also as COS.
Typically, a syngas from the gasification of a refinery residue with 4% sulfur may contain about
0.9 mol% H2S and 0.05 mol% COS. While some washes such as Rectisol can remove the COS
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along with the H2S, others, particularly amine washes, require the COS to be converted
selectively to H2S if the sulfur is to be substantially removed. This is best achieved by catalytic
COS hydrolysis, according to the reaction:
cos+H 2O↔H 2S+CO2
Commercially, this reaction takes place over a catalyst at a temperature in the range of 160–
300°C. Various catalysts are available, including promoted chromium oxide-alumina, pure
activated alumina or titanium oxide. Lower temperatures favor the hydrolysis equilibrium.
Typically, the optimum operating temperature is in the range 150–200°C.
Depending on process conditions, the residual COS can be reduced to the range of 5-30
ml/Nm³. This catalyst also promotes the hydrolysis of HCN. The catalyst operates in the
sulfided state, and is not poisoned by heavy metals or arsenic. Halogens in the gas will,
however, reduce activity, selectivity and lifetime- a fact that needs to be addressed carefully in
coal gasification applications. In applications downstream gasification of refinery residues,
nickel and iron carbonyls, which may have formed upstream, can decompose, depositing nickel
or iron sulfide on
the catalyst bed and
thus creating an
increased
pressure drop
over the system.
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Typical COS hydrolysis flowsheet
Figure 20 Typical COS hydrolysis flowsheet
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Plant Utilities
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INTRODUCTION:
Basically defining utility may be considered as an auxiliary resource , which must be within the
plant for the successful operation of the plant and production of the product.Improper
selection of utilities can basically affect the process parameters and yield of the product.
6.1 TYPES OF UTILITIES:
Primary Utilities:
1. Water
2. Steam
3. Power and fuel
4. Air
5. Storage and internal transport of raw material and product
6. Refrigeration system and air conditioning
Secondary utilities:
1. Maintenance facilities
2. Roadways
3. Rail/road facilities
4. Fire protection
5. Plant sewer system and waste disposal
6. Plant buildings
7. Plant security
6.1.1 PROCESS AND INSTRUMENTATION AIR:
Air is used in chemical plants both in process as well as pneumatic control systems. In our case
only instrumentation air is required. All pneumatic controls in the plant require instrument air
which is supplied in air compressor house. A slight malfunctioning of this unit may result in
complete failure of all the units. The piping is over designed and extreme care is taken to
prevent piping failure.
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Specifications of compressed air:
CHARECTERISTIC SPECIFICATION
1. Oxygen,% vol 21
2. Nitrogen, % vol 79
3. Carbon dioxide ,ppm by vol 5
4. Water vapour, mg/m3 4
5. Dust, ppm wt 15
6. Oil/ grease, ppm wt 10
7. Pressure , Kg/cm2 5
8. Temperature
9. Dew point , ºC -40
6.1.2 HEAT TRANSFER MEDIA:
Heat transfer media are defined as fluids which absorb are providing thermal energy to the
process equipment.
Properties of heat carriers:
1. High rate of heat exchange
2. Absence of corrosion effects
3. Cheap and easily available
4. Low viscosity
5. Non-toxic
6. Non-inflammable and thermally stable
The heat transfer media being used in our plant is:
1. Steam
2. Water
Liquid water is being used as a coolant in the heat exchangers, coolers and condensers.
Steam offers the following advantages over the other heat carriers:
1. It is thermally stable over the entire range of operation. Also it has less corrosive effects.
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2. Water is the cheapest and most commonly available heat carrier.
3. It has a high heat transfer coefficient during condensation.
The steam used is being generated in the boiler house.
6.2 WATER:
The water being fed to the boiler has to be treated first to remove all impurities in the solution
and suspension. These impurities can produce scale or other deposits in the boiler which may
restrict water circulation or retard transfer of heat from the tube wall to the boiler. They can
also corrode the metal surface in contact with the water. High concentration of the suspended
solids in boiler water can give rise to formation of stable foam above the water surface. This can
lead to a severe form of water carry over in which large volumes of water are ejected from the
boiler with the steam.
The purpose of water treatment for boiler feed is to ensure that all parts of the boiler
plant in contact with the water remain clean and intact. The prevention of scale or deposits
requires that all water entering the boiler through the feed system must be free from
suspended solids or any substance in solution which may precipitate as solids. Prevention of
corrosion requires that were possible the aggressive component should be removed or
neutralized. Further aim of water treatment is to reduce the concentration of all or some of the
impurities present in the makeup water so that a safe maximum concentration of solids in the
boiler water can be maintained with a practical and economic level of blow down.
Specifications of boiler feed water:
Water is required in the plant for the following purposes:
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Component ppm
Iron
Hardness
Copper
Caustic alkaline
Soda alkaline
Excess soda ash
0.1
Less than 0.2
0.05
0.15- 0.45
0.45-1.00
0.30-0.55
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1) Cooling water: This water is used for cooling in the various overhead condensers, main
stream condenser and partial condensers. All this water cannot be supplied as fresh water and
has to be re circulated in the system. For the fresh water we propose to pump river water or
from any water source nearby.
The circulating water can either be corrosive or scale forming and undesirable because they
tend to reduce the heat transfer coefficient of processes. The other undesirable material id due
to the biological growth like algae formation which may cause partial or complete plugging at
various places and can cause untimely shut downs.
In addition, a water treatment plant is to be installed to treat circulating water to
remove all desirable materials. Cooling water in heat exchangers are likely to come in contact
with steam being cooled. Water is first sent to cooling tower, a controlled amount of chlorine is
to be added before hand to reduce changes of algae formation in cooling tower. Cooling tower
has I.D fans which induce air to rise in the cooling water columns. The water discharge header
at the top of the tower is divided into a number of distribution pipes fitted with spray nozzles,
so that water should fall in form of fine droplets. These droplets trickle down the wooden
baffles and in doing so meet with rising column of air. A part of water droplets vaporize with air
and take away heat of vaporization from hot water stream, which is thus cooled.
Here, it is treated with sulphuric acid to remove methyl orange alkalinity and so
adjust of water. Sodium hexamethaphosphate is added to precipitate fouling and scaling agents
like calcium and magnesium salts. Chlorine is added to avoid algae formation in lines. The
controlled amount of these chemicals is mixed with cold water which is then pumped to
circulating cold header. Provision should be there to mix fresh water as makeup in this main
header.
Alum or ferric sulphate or sodium aluminates is added to raw water so that the
impurities coagulate. Lime and soda ash are added for removal of permanent hardness. To
destroy organism’s chloride is added in form of calcium hypo chloride or sodium hypo chloride.
Sodium hexamethaphosphate is added to reduce the amount of scale forming and fouling
materials. In exchange which is the important step, removes all dissolved mineral matters which
are in ionic form. It is done by ionic exchange resins which are made up of cross linked
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polystyrene. Also this step water is fed to iron remover filters and then to degassers. After this
stage water is completely demineralised this is then sent to D.M. water tanks.
Specifications for cooling water:
Total hardness as caco3
M alkalinity as CaCo3
P alkalinity as CaCo3
Free CO2
Free acid as CaCO3
Fluoride
Sulphates
Iron
Copper
TDS
pH
cooling water supply temperature
cooling water return temperature
supply pressure
21
11 mg/l
2 mg/l
Nil
Nil
4 mg/l
8 mg/l
2 mg/l
1 mg/l
33 mg/l
9.3
25ºC
50ºC
4.5 Kg/cm2
2) Sanitary water:
Sanitary water, which has common uses like drinking , washing and other cleaning purposes , is
essentially fresh water. It must be potable and free from disease causing bacteria. In cities as in
our case, water is often purchased for this purpose and an elevated tank is installed to ensure
uninterrupted water supply.
3) Dilution water:
Dilution water is used to wash off accidental spillage or for cleaning. For emergencies or
hazardous operations water should be kept handy in very large amounts.
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4) Process water:
Water treatment
Pressure Sand Filter:
It is a pressurized filter in which suspended impurities present in water are trapped in the filter
media which can be either single media (i.e. only sand) or dual media (i.e. sand and anthracite).
It is generally designed to handle loads up to 50 ppm. In PSF, before backwashing the filter
normally air scouring (the operation in which the filter media is loosened by introducing air
from the bottom of the filter so that the trapped impurities can be easily removed during
backwash) is done for 3-5 mins. After backwash is completed, filter is taken back to service.
Activated Carbon Filter:
It is a pressurized vessel in which odor, color and chlorine present in water can be removed by
the bed of activated carbon. After continuous use (normally after every 24 hrs) when the bed is
exhausted, the filter is backwashed using raw water normally. Then, the filter is taken back to
service by introducing water from top.
Ion exchange Process: Removal of Dissolves Salts
Dissolved salts are in ionic form in the water. Replacing these undesirable ions with harmless
ions is known as ion exchange process. Depending on the application of the final product, it can
be done in two ways:
1. Demineralization Plant
2. Water Softening
WATER SOFTENING:
i. Water Softening Process:
Softening the water means removal of the hardness. Calcium and magnesium salts impart
hardness to the water. Since sodium salts are soluble, they do not contribute to the hardness of
water. Hence, softening involves replacing the calcium and magnesium by sodium ions in the
water. E.g.: Indion resins.
Sodium ions are loosely held on resin matrix. When water comes in contact with resin, it gives
up sodium ions and takes up calcium and magnesium from the feed water. Thus, resin
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exchanges the ions. Water coming out of the softener now contains all kinds of sodium salts
and hence is soft.
ii. Regeneration of softener:
The resin has specific capacity of exchanging ions. After loosing all sodium ions, the resin cannot
work anymore and is said to get exhausted. At this stage, it needs to be regenerated. In
softening application, the resin is regenerated with solution of common salt which contains
sodium ions. When the resin comes in this solution, it gives up calcium and magnesium ions and
takes up sodium ions, hence becoming ready to take up more water fro treatment.
DEMINERALIZATION PROCESS:
Demineralization is the process in which all mineral or ionic impurities are removed. It has the
following stages:
a) Removal of cations in cation exchange unit
b) Removal of carbon dioxide in degasser
c) Removal of anions in anion exchange unit
d) Removal of traces of cations and anions of together in mixed bed.
# Depending upon the feed available and the quality of product water required, a combination
of above stages can be used.
A. Cation Exchange Unit:
1. Weak acid cation (WAC):
Though this system is highly efficient, it has limitation in use. The WAC resin- Indion 236 can
only remove hardness associated with bicarbonate alkalinity and hence choice offered by this
unit is limited. Usually, a strong acid cation (SAC) unit follows a WAC unit.
2. Strong acid cation (SAC):
Basically calcium (Ca++), magnesium (Mg++) and sodium (Na+) ions are replaced with hydrogen
(H+) ions with the help of cation exchange resin (Indion 225H+). H+ ions are loosely held on
resin matrix. When water comes in contact with it, it gives up H+ ions and takes all the cations
like Ca++, Mg++, Na+, etc. The H+ ions imparted convert water into respective acids like HCl,
HSO, HCO, etc. Hence water coming out from SAC unit is acidic.
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B. Cation Exchanger Regeneration:
After loosing all H+ ions cation exchange resins get exhausted and need to be regenerated. It is
regenerated with acid which contains H+ group. When it comes in contact with acid, it again
takes up H+ ions and comes into its original form and gets ready to take charge of water
treatment.
C. Degasser:
Decationised water contains large amount of dissolved CO. This is blown off in the degasser
unit. Water flows in the downward direction in the tower and air in the reversed direction.
Forced air removes CO.
D. Anion Exchange Units
1. Weak base anion unit (WBA):
As is the case with WAC, weak base anion unit is also very efficient and has the same limitation.
It can only remove chlorides, sulfates and nitrates, i.e., EMA from water, but not carbonates,
bicarbonates and silica. Because of its efficiency, it is only offered when EMA is high. Usually a
SBA is the following unit to a WBA unit.
2. Strong base anion unit (SBA):
Anion exchanger unit removes anions like chloride (Cl-), sulfates (SO42-), residual carbon
dioxide (CO2) and silica (SiO2). In anion exchanger units, these ions are replaced with hydroxyl
(OH-) ions with the help of anion exchanger resins (Indion FFIP/NIP). OH- ions are loosely held
on anion exchange resin matrix. When decationised water comes in contact with resin, it gives
off OH- ions and takes Cl-, SO42-, silica, thus water leaving the anion exchanger is free from
anions. The H and OH ions gained from the cation and anion exchanger units combine to form
water molecules. Thus the water is free from all anions and cations and is known as
Demineralised or Deionised water. Still some impurities in traces exist in this treated water
which are further removed in mixed be unit.
E. Regeneration of Anion Exchanger
After losing OH- ions, resin gets exhausted and needs to be regenerated. Anion exchanger
resins are regenerated by alkali which contains hydroxyl (OH-) ions, eg sodium hydroxide
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(NaOH). When resin comes in contact with alkali, it takes up hydroxyl ions and returns to its
original form, thus getting ready to take up the next charge of water for treatment.
F. Mixed Bed Unit (MB):
Mixed bed unit is the unit which gives final polish to the water, making it totally different
demineralised. This unit contains cation and anion resin in mixed form. Traces of remaining
cations and anions are removed here. Water containing residual sodium ions and silica comes
into contact with the mixed resin. Sodium ions and silica are exchanged by H and OH ions
respectively which are held on the resin. Water coming out of the mixed bed unit is free from
almost all ionic impurities thus becoming demineralised in true sense.
G. Regeneration of Mixed Bed Unit
While regenerating, cation and anion resins are separated and regeneration of both resins is
carried out separately. Cation exchange resin is regenerated with acid and anion resin with
alkali. After regeneration, both the resins are mixed well by blowing air with force. Thus, the
unit is then ready to take up the next charge.
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6.3 REFRIGERATION:
For the purpose of getting chilled water a refrigeration unit is set up. For this purpose
absorption machine is used. It consists of heat transfer tubes in a closed vessel operated under
vacuum. Low pressure in the vessel makes the water evaporate at low temperature, thus
removing the latent heat and making the water chilled. The evaporated water is absorbed by
LiBr thus maintaining the vacuum i the evaporator. Diluted LiBr while passing through various
heat exchangers get concentrated and again agets collected in the absorber for a new cycle.
Air conditioning:
General requirements: Necessary considerations while designing an environmental control
system are ventilation requirements, adequacy of controls, minimizing the influence of dust or
other contaminants, freeze protection and good air distribution.
Clean air requirements: It is done to reduce body odours and maintaining comfortable
conditions. It is concerned with control of dust, fumes, vapours and gases.
Air distribution requirements: Distribution of air is specific to an application. the application
may include from general ventilation , spot cooling and makeup air and dilution ventilation.
6.4 ELECTRICITY AND POWER REQUIREMENTS:
Power is required for pumps, compressors and lighting purposes. For further distribution of
power, a substation in the plant is essential. We shall use a captive power plant, the pressure of
steam is brought down in turbines and the electricity generated is used to run the plant. If any
extra power is required at any time, we can buy some grid grid power. The plant consumes
electricity in the following areas:
1. All pumps require electrical power for their operation.
2. All blowers and compressors require electrical power for their operation.
3. Control room requires power for its operation.
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6.5 SECONDARY UTILITIES:
1. Maintenance Facilities: For maintenanceof theprocess plant while under operation, a
separate department will be established because early shut downs cause money such as salary
for the regular mechanical labour, cost of replacement units etc. To avoid its continuity of
product and storage problem of raw materials, repairing etc. Timely checking of plant
conditions and equipment and their performances will be done so that the product quality will
remain within specified limits.
2. Plant roadways: They are located for intra transportation of material so that every area
of plant may become accessible to a wheeler. Reinforced concrete is used to be used for roads
so that it can bear without cracking the pressure exerted by fully loaded trucks etc.
3. Rail/Road facilities: For transportation of various required raw materials and products,
both rail and road facilities should be taken care of so that the product may reach the market
without spoilage. Raw material flow should be continuous to avoid interruption.
4. Fire Protection: Fire water lines should run throughout the plant. Emergency doors
should be provided for each building. Insulation used extinguishers, water-sand bucket system
should be provided at critical points.
5. Plant Security and Safety: Plant will be surrounded by fence or brick wall twice the
height of man topped with glass pieces in cement to prevent entrance of unauthorized visitors.
A security room will be maintained at both gates of the plant, which will check incoming and
outgoing persons and vehicles.
6. Plant Buildings: For the proper working conditions and keeping the materials away from
the elements of nature and also to lay the equipment for easy flow of material with least power
requirement plant buildings should be engineered.
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6.6 AIR, OXYGEN, NITROGEN:
AIR separation unit:
Non-cryogenic air separation processesare cost effective choices when demand is relatively
small (tens of tons per day) and when very high product purity is not required. A typical purity
for non-cryogenic oxygen systems is 83%.
Non-cryogenic air separation plants are compact and operate at near-ambient temperature and
pressure. Once installed, they can usually be brought on-line in less than half an hour.Unlike
cryogenic plants which use the difference between the boiling points of nitrogen, oxygen and
argon to separate and purify those products, non-cryogenic air separation processes use
physical property differences such as molecular size and mass, to produce nitrogen and oxygen
at sufficient purity
In this process we use Vacuum-Pressure Swing Adsorption (VPSA).Oxygen VPSA units are
usually more cost effective than oxygen PSA units when the desired production rate is greater
than about 20 tons per day. They are often the most cost-effective oxygen production choice up
to 60 tons per day or more, providing high purity oxygen is not required.
Vacuum Swing Adsorption (VSA or VPSA)
For oxygen purification includes a variety of zeolite molecular sieve which selectively adsorbs
nitrogen, moisture and carbon dioxide gas. This allows the oxygen molecules to pass through
the unit and produce low purity oxygen, typically at 80 to 85% purity.
Components of VSA
The main components are:
Two carbon or zeolite sieve containers
Nitrogen or oxygen receiver
Refrigerated dryer
Feed air compressor
Air receivers
Air filters
Oxygen enriched air
Vacuum blower
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VSA Process
The process is similar to that of PSA. The only difference is that the differential pressure takes
place at lower absolute pressures. The main steps are:
* The VSA process begins by charging the first vessel with low-pressure air, initiating the N2
adsorption process.
* Before the zeolite reaches equilibrium, or when O2 is adsorbed, the pressurized gas in the
first vessel is vented to the second vessel at lower pressure (vacuum).
* Residual N2 in the first vessel is then "desorbed" from the zeolite and vented at
atmospheric pressure.
* All required valving operations are done automatically by carefully calculated timing cycles
controlled by a PLC.
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Site Selection
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Site Selection:
If one is to design a chemical plant the site must be known. The cost of energy and raw
materials, the type of transportation to be used, and the availability of labour all depend on the
plant site. There are examples which show that a particular plant site is chosen because of the
presence of a specific raw material or energy source.The geographical location of the final plant
can have strong influence on the success of an industrial venture.
Figure 21 Coal Reserves in India
Various Sites considered:
Following sites were considered based on availability of raw material:
1. Bokaro, Jharkhand
2. Talcher, Orissa
3. Korba, Chhattisgarh
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Maoists are more active in Jharkhand and Chhattisgarh state. Recent massacre of 76 CRPF
personnel in Dantewada, Chhattisgarh is shows their formidable presence in Chhattisgarh.
Hence Orissa is a better place to setup an industry.
Moreover Orissa govt. has offered various incentives for setting up of new industries. New
industrial units with contract demand up to 100 KVA will be exempted from the payment of
electricity duty for a period of 5 years from the date of availing power supply for commercial
production. To attract Mega Projects into the State, Special package of incentives may be
considered for new Industrial Projects with a capital investment of Rs.300 crore and above on a
case to case basis keeping in view the National Policy on Sales Tax related incentives.
(Ammended Industries Department Resolution No.17462/I dated.18.09.2002)
Furthermore, political condition is less stable in Jharkhand. For a steady growth of any industry,
political condition must be stable.
Talcher:
It is known as city of black diamond(coal) as Talcher is rich with coal .it is situated in the heart of
orissa, 135 KM from Bhubaneswar (State capital) , known to be a state's industrial capital ,
because of so many big and heavy industries like two NTPC (power Plant), NALCO, Nalco's own
Captive Power plant, F.C.I (Asia's largest coal base urea plant), Heavy Water Plant (Atomic
Energy Dept.), ORICHEM, Jindal'Steel plant, now laxmi Narayan Mittal is about set up a steel
plant near by Talcher and many small industries along with so many coal mines on which all
industries are based on. It is very rich in heritage and culture.
Angul Talcher area is situated at an average height of 139 meters above mean sea level (MSL)
and about 110 km from the state capital Bhubaneshwar. The area lies between 20 37' N to 21
10'E latitude and 84 53'E to 85 28'E longitude. The rich cultural heritage, forests, mineral
resources, natural beauty, industrial landscape give Angul a place of pride. To-day Angul is a
bustling and dynamic district. The locational advantages, abundant stock of manpower, raw
materials have played an important role in the development of the district.
The climate of the area is continental type being arid and dry except in monsoon season. Due
to marked variations in temperature and rainfall, the area is divisible into four distinct seasons-
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summer (March-may), Monsoon (June September), Post monsoon (October-November) and
winter (December-February ).
Meteorological data was collected from meteorological stations established on the top of CME
Field Office, Vikash Nagar, Angul and Central Workshop Colony, Talcher. Both the locations
were free from obstruction of free flow of air from all the directions. Accordingly, the wind rose
diagram of Angul and Talcher region During Summer 2007, the predominant wind direction in
Angul and Talcher area was from South-East and North-West for 20.99 % and 16.66 % of time,
respectively. The predominant wind speed of 1-5 km/h was observed for 40.49 % of the total
time. Similarly in Talcher area, the predominant wind direction was from North-West and
South-West for 26.75 and 8.68 % of time, respectively and the predominant wind speed of 1-5
km/h was observed for 37.28 % of the total time.
The minimum and maximum temperatures recorded during this period were 22.90C & 44.20C
and 24.40C & 45.7 C for Angul and Talcher areas, respectively. The maximum and minimum
relative humidity was observed as 100% & 45 % and 100% & 39.8 % for Angul and Talcher
areas, respectively. The highest rainfall of 21.2 and 19.5 mm was recorded on 18.6.07 and 10.
6.07 for Angul and Talcher areas, respectively.
Special Incentives:
Transportation:
Road Transport
National Highways :
National Highway-42 : 96.00 km
National Highway-23 : 84.545 km
National Highway-06 : 11.542 km
National Highway-200: 43.383 km
Railways
The Talcher line and Sambalpur line of the south-eastern railway runs in the district. Railway
line was laid primarily on account of the Talcher coal field and the first passenger and goods
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traffic along this line was opened on 20th January 1927. Railway Stations: Talcher , Angul (20
km), Cuttack (110 KM), Bhubaneswar (130 KM), Sambalpur (180 KM)
Water ways
The river Mahanadi & Brahmani are the main waterways of the district. The Mahanadi is
navigable for a period of 7 months from September to March for 77 kms. from village Daruha in
Athamallik sub-division to village Kataranga in Angul sub-division. The goods like Bamboos,
timbers and other commodities are transported through the river.The important ferry ghats of
river Mahanadi are Kuleswar, Kudagoan, Olath, Bahali, Lunahandi, Deuli, Kiakata etc.
The river Brahmani is navigable for a period of three months from July to September.The
important ferry ghats of river Brahmani are Talcher, Durgapur, Karnapal, Talapada, Burukuna,
Bijigole, Karadei, Rangali etc.
MINERAL RESOURCES
Coal
The earliest record of exploration in Talcher coal fields dates back to 1837 when coal was
discovered at Gopalprasad. G.S.I. took up surface mapping in 1855. The State PWD department
sank six shafts in 1875 in Gopalprasad area to obtain 80 tones of coal sample. East Indian
Prospecting Syndicate found good quality of coal near Talcher town in 1920. The Indian Bureau
of Mines and NCDC, a forerunner of CMPDIL Ltd. Carried out detailed exploration in the eastern
part of Talcher coalfields in late fifties. GSI entered this field for regional exploration in 1963 &
are continuing their endeavor. Exploration findings are depicted below.
Coal is the prime mineral resource of the district. The coal is non-coking in nature & mostly
suitable for thermal power. Superior coal also available is relatively small quantity is consumed
by sponge iron plants, Ferro alloy plants, refractories, cement plants, paper mills, sugar mills
steel plants and many other industries. The inferior grade coal is mostly used in brick burning.
As many as 12 workable coal seams of various thickness have been reported in Talcher. The
basinal area of Talcher coal field is 1813 sq.km. The total geological reserve has been worked
out to be about 36,868.12 M.Ts up to a depth of 1200m, which constitute about 18.7% of the
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country’s total non-coking coal reserve. Out of this, mine able reserve would be in the region of
9,500 M.Ts. (Million Tones).
Graphite
Graphite occurs in villages Dhandatopa, Taleipathar, Adeswar, Akharakata, Bhandarimunda,
Girida, Sanrohilla, Lanchi, Govindpur etc. of Athamallik sub-division having Fc from 7.46% to
44.4% Detailed exploration needs to be carried out to prove the reserve & its economic
viability.
CLIMATE
The climatic condition of Angul is much varied. It has mainly 4 seasons. The summer season is
from March to Mid June, the period from Mid June to September is the Rainy season, October
and November constitute the post monsoon season and winter is from December to February.
The best time to visit this district is during winter.
RAIN FALL
The average annual rainfall of the district is 1421 mm. However there is a great variation of
rainfall from year to year. The rainfall in the district during the last 10 years varied between
896 mm & 1744 mm. There are 70 rainy days on an average in a year, but it varies from 66 at
Athamallik to 80 at Pallahara. The distribution of rainfall is also quite erratic causing wide
spread drought year after year.
TEMPERATURE
The hot season commences by beginning of March. May is the hottest month with a mean daily
maximum temperature at 44 degree Celsius. With the onset of monsoon, early in June day
temperature drops appreciably. After withdrawal of monsoon by the 1st week of October both
day and night temperature began to diminish steadily. December is usually coldest month of a
year with a mean daily minimum temperature of 12 degree Celsius. In association with the
passage of western disturbances across north India during winter months short spells of cold
occur and the minimum temperature drops down to 10 degree Celsius. The highest maximum
temperature recorded at Angul was 46.90 degree Celsius on dt.30.05.98. The lowest minimum
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temperature was 6.0 degree Celsius on 16.01.03 in Angul and neighborhood are hottest part of
the district and have lower rainfall. The summer temperature has shown as increasing trend in
recent past.
HUMIDITY
The humidity of the air is generally high, especially in the South West monsoon and post
monsoon months. In other months, the afternoons are comparatively drier. In the summer
afternoons the relative humidity varies between 25 and 40 percent. Low relative humidity
means easy coal storage in open fields.
CLOUDINESS
During the South-West monsoon season the sky is generally heavily clouded. In the summer
and the post monsoon months there is moderate cloud.
WINDS
Winds are generally light to moderate with some increase in force in the summer and
southwest monsoon seasons. Winds usually blow from southwest and northwest directions in
the monsoon. In the post monsoon and cold seasons winds blow between the west and north.
In the summer months the winds become variable in direction.
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ORGANIZATIONAL
STRUCTURE AND
MANPOWER
REQUIREMENT
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8.1 Organizational structure:
Organization is a prescribed pattern of relations among the various tasks and the individuals
who perform the tasks. Organizations are characterized by explicit, common parts which
require the co-ordination of individuals and group efforts towards their attainment. The co-
ordination is achieved by the establishment of vertical and horizontal network of relationships
among various components of the organization.
The basic goals of the organization are three-folds:
1. To produce the best quality product at the lowest cost
2. To sell the product to the consumer in a manner that maximizes profit, both in the short
as well as long tem.
3. To do these in a manner that is sustainable and is in the interest of the society.
In order to achieve these goals, an effective organizational structure is required both at the
management and operational levels. There are various steps involved in specifying the kind of
organization and the total labor requirement of the plant complex, before beginning the
construction and commissioning of the plant. We briefly take some of the important points.
Consideration of objectives:
One should be very clear as to what are the objectives of the enterprise. Objectives determine
the various activities, which need to be performed and the type of organization, which needs to
be built for the purpose.
Grouping of activities into departments:
Identify the activities necessary to achieve the objectives and group the similar or related
activities into well defined groups or departments.
Deciding key departments:
Key departments are those which render activities that are essential for the achievement of
goals. These are primary departments, the others exist merely to serve these
Determine decision levels:
The levels at which all the major and minor decisions in each department are to be made must
be determined. The amount of decentralization and spread of authority are at the discretion of
each firm
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Span of Management
The next step to be taken in designing a structure is the number of sub-ordinates who will
report to each executive.
Coordination mechanism
The whole structure should be like a well-oiled machine, with cohesion and co-ordination at all
levels.
Duties of organization and administration:
Principles of work administration and control, labor organization and control,raw
material and their storage
Selection of site, layout of works, building and plants
Problem of internal transport and material handling
Construction work
Proper equipment selection
Minimization of labor
Office administration and finance
Marketing and distribution of products
Organization is a structure framework for carrying out the functions of planning, decision-
making, control, communication, motivations, etc. the formal structure of an organization is
two dimensional: horizontal and vertical. The horizontal dimensions depict differentiation of
the total organizational job into different departments. The vertical dimension refers to the
hierarchy of the authority relationship with a number of levels from top to bottom. Authority
flows downwards along these levels.
The usual way of depicting a formal organization is by means of an organization chart. It is a
snapshot of an organization at a particular point in time, which shows the flow of authority,
responsibility and communication among the various departments which are located at
different levels of hierarchy.
The organization structure of a company can be broadly classified into-
1. The top management organization
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2. The operating line management
The management gives the general direction to the organization while the operational level
produces tangible results from the plans developed. The top management organization of the
company is basically of the line type with levels of management differing with function and
responsibility of the individual. It consists of the general management who controls and
manages the departmental management personnel. At the top of hierarchy is the board of
directors, presided over by the chairman of the board. The board exists to represent, safeguard
and further the interests of all the stakeholders. It determines the basic policies and the general
course business, appraises the adequacy of overall results and in general, protects and the
makes the most efficient use of the company’s assets.It is responsible for determining the
direction in which the company will precede and reviewing the performance keeping in mind
the basic policies which are closest to the company's vision. The managing directors act as a link
between the board and the executive level.
At the next level are the Vice-Presidents of the various divisions, namely, Operations,Technical
Services, Sales & Marketing, Finance, Administration and Legal.
They are supported by general managers, managers, engineers, operators, cleric staff and
technical and non-technical labor. The general management includes the active planning,
direction, coordination and control of the business as a whole within the scope of the basic
policies established and basic authority delegated by the board. The divisional department's
function includes the management of various divisions or department of the company by
executives fully responsible and accountable to the general management.
8.2 Manpower requirement
The general division of an organization can be divided into various departments or categories
which are responsible for the smooth functioning of the organization. They are listed as follows:
General Manager:
A general manager leads the factory organization. He has to perform the following duties:
Utilities Division
Administration of various departments
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Ensure smooth running of the factory with maximum profits
Plan and implement diversification programs
Prompt and implement decisions to simplify the execution of work
Operations
Production Division
Production manager heads this department. He is highly experienced and has good technical
skills. He is responsible for overall production and proper functioning of the plant
Utilities division
Maintenance Division
At par with the production manager is the maintenance manager. The maintenance
department has a very important role to play in plant operation. In continuous plants, all
maintenance activities are tended during the annual turnaround of the plant.
Storage Division
Business Development and Marketing Division
A market manager heads it. He is responsible for the development of new marketing strategies
and also publicity, advertising and sales of the product.
Personnel Division
The personnel officer heads it. He is concerned with overseeing the recruitment, training,
welfare, medical facilities and an overall maintenance of harmony in the relationship within the
organization.
Technical Services
Quality control, maintenance and R&D department
Legal Department
Staff and Labor
Staff and Labor can be classified into
Technical
Skilled (engineer)
Unskilled (operator)
Non Technical
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Manpower requirements:
Designation Educational QualificationNumbe
r
Grad
e
CEOB.Tech + MBA with 20yr
experience1 E0
Board of directors B.Tech + MBA 6 E1
Managing Director B.Tech + MBA 1 E2
Operations
Vice PresidentB.Tech(chem) + MBA.12 yrs
exp1 E3
Productions
General Manager M.tech(chem) with 10yrs exp 1 E4
Production
managerB.Tech/M.Tech with 6yrs exp 3 E5
Engineer B.Tech Chemical 21 E6
operators Diploma in chemical 42 B0
Labor High School 60 B2
Utilities
General ManagerM.Tech Chemical with 10 yrs
exp1 E4
Utility managerB.Tech Mechanical with 8 yrs
exp3 E5
Engineer B.Tech Mechanical 21 E6
Operator Diploma in Mechanical 42 B0
Maintenance
General manager M.tech chemical with 10yrs 1 E4
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exp
manager B.tech chemical with 8yrs exp 3 E5
EngineerB.tech mechanical with 5yrs
exp9 E6
operator Diploma in mechanical 18 B0
Labor High school 30 B2
Safety
ManagerM.tech chem/elec with 5yrs
exp1 E5
Operator Diploma in chemical 6 B0
Storage
manager M.tech chemical 1 E5
Engineer B.tech chemical 3 E6
operator Diploma in chemical 6 B0
Labor high school 30 B2
Vice president TS M.Tech + MBA 1 E4
Instrumentation
Engineer B.tech electrical 3 E6
operator Diploma in electrical 6 B0
Labor High School 9 B2
Administration
General Manager MBA 1 E4
Manager M.Tech 1 E5
security Officer Retired SI 1 E5
Medical Officer MBBS 6 E5
labor High school 6 B2
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Quality Control
andRD
General manager M.Tech + MBA 1 E4
Manager M.Tech 1 E5
Chief Chemist Ph.D in chemical 2 E5
Chemist M.Sc Chemistry 2 B0
Sales and
marketing
Vice president MBA with 10yrs exp 1 E4
Senior manager MBA sales + 5yrs exp 1 E4
Manager MBA sales 1 E5
Support staff Graduate + 2yrs exp 2 B0
Frontline sales
execGraduates 5 B0
Finance
Vice president CA with 5yrs exp 1 E4
manager accounts M.Com accounts 1 E5
Manager auditing M.Com 1 E5
Cleric Staff B.Com 3 B1
Legal
Vice President CA + CFA 1 E4
Lawyer/legal
advisorLLB with 3 yrs exp 1 E5
Paralegal LLB 2 E6
8.2.1 Salary Structure:
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The salaries are assigned as per the grade that has been designated to the post. This is done
because the grade shows the level of responsibility and labor required in the fulfillment of the
job.
The following salary structure is the approximated gross salary per month. The figure includes
all perks
Grade Gross salary (per month in Rs)
E0 2,00,000
E1 1,25,000
E2 1,00,000
E3 70,000
E4 60,000
E5 50,000
E6 35,000
B0 13,000
B1 13,000
B2 10,000
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PE/ME/IE PE/ME/IE PE/ME/IE PE/ME/IE PE/ME/IE PE/ME/IE
PRESIDENT
ADMINISTRATION FINANCEPRODUCTION MARKETING
VICE PRESIDENT
MANAGER
Public Relation Officer
Security Officer
Fire & Safety Officer
VICE PRESIDENT
MANAGER 1 MANAGER 2 MANAGER 3
VICE PRESIDENT
MANAGER
Marketing Officer 1Marketing Officer 2Marketing Officer 3
VICE PRESIDENT
MANAGER
Account Officer (2)
Shift Engineers
Shift Operators
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8.3 Organization Chart
\
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Figure 22. Organizational Structure
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Economic
Evaluation and
Profitability of the
Project
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Chemical plants are built to make a profit, and an estimate of the investment required and the
cost of production are needed before the profitability of a project can be assessed. Before an
industrial plant can be set up into operation, a large sum of money must be supplied to
purchase and install the necessary machinery and equipment, land services must be obtained,
and the plant must be erected complete with all piping, controls and services well within time.
In addition, it is necessary to have money available for the payment of expenses involved in the
plant operation.
FIXED AND WORKING CAPITAL
Fixed Capital: Fixed capital is the total cost of the plant ready for start-up. It is the cost paid to
the contractors.
It includes the cost of:
1. Design, and other engineering and construction supervision.
2. All items of equipment and their installation.
3. All piping, instrumentation and control systems.
4. Buildings and structures.
5. Auxiliary facilities, such as utilities, land and civil engineering work.
It is a once-only cost that is not recovered at the end of the project life, other than the scrap
value.
Working Capital: Working capital is the additional investment needed, over and above the fixed
capital, to start the plant up and operate it to the point when income is earned.
It includes the cost of:
1. Start-up.
2. Initial catalyst charges.
3. Raw materials and intermediates in the process.
4. Finished product inventories.
5. Funds to cover outstanding accounts from customers.
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Most of the working capital is recovered at the end of the project. The total investment needed
for a project is the sum of the fixed and working capital. Working capital can vary from as low as
5 per cent of the fixed capital for a simple, single-product, process, with little or no finished
product storage; to as high as 30 per cent for a process producing a diverse range of product
grades for a sophisticated market, such as synthetic fibres. A typical figure for petrochemical
plants is 15 per cent of the fixed capital.
The direct-cost items that are incurred in the construction of a plant, in addition to the cost of
equipment are:
1. Equipment erection, including foundations and minor structural work.
2. Piping, including insulation and painting.
3. Electrical, power and lighting.
4. Instruments, local and control room.
5. Process buildings and structures.
6. Ancillary buildings, offices, laboratory buildings, workshops.
7. Storages, raw materials and finished product.
8. Utilities (Services), provision of plant for steam, water, air, firefighting services (if not costed
separately).
9. Site, and site preparation.
The contribution of each of these items to the total capital cost is calculated by multiplying the
total purchased equipment by an appropriate factor.
In addition to the direct cost of the purchase and installation of equipment, the capital cost of a
project will include the indirect costs listed below. These can be estimated as a function of the
direct costs.
Indirect costs
1. Design and engineering costs, which cover the cost of design and the cost of “engineering”
the plant: purchasing, procurement and construction supervision. Typically 20 per cent to 30
per cent of the direct capital costs.
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2. Contractor’s fees, if a contractor is employed his fees (profit) would be added to the total
capital cost and would range from 5 per cent to 10 per cent of the direct costs.
3. Contingency allowance, this is an allowance built into the capital cost estimate to cover for
unforeseen circumstances (labour disputes, design errors, adverse weather). Typically 5 per
cent to 10 per cent of the direct costs.
Storage Tanks:
Storage tank for No. Volume (m3) Cost ($)
Coal 2 20000 533696.4741
Water 1 15675 466758.2343
Syngas 6 20000 3202178.845
DEA 1 722.9982 85951.46924
oxygen 2 25000 1206770.92
nitrogen 1 13000 842222.182
Cyclone Separator:
Cyclone separator Gas flow rate(m3/min) Cost($)
Big 1336.758927 640784.3936
Shell and Tube Heat Exchangers:
Exchanger Area Cost($)
Heat Exchanger-1 174.6 50000
Heat Exchanger-2 1090.6 250000
Gasifier :
Title Volume (m3) Cost($)
Gasifier 112.879 993428.2833
Absorber, Stripper and Scrubber:
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Title Gas flow rate(m3/min) Cost($)
Absorber 306.5156 9652.620601
Stripper 993.5404 30634.16233
Scrubber 702.4015 22119.64151
Column Packing:
Title Size (mm) Cost($)
Absorber 76 (Ceramic Intallox
Saddle)
73512
Stripper 76 (Ceramic Intallox
Saddle)
73512
Scrubber 25 (Berl Saddle) 185792.4
Waste Heat Boiler:
Title Area (m2) Cost($)
WHB-1 229.6 77126
WHB-2 229.6 77126
Coal Pretreatment Equipment Cost:
Title Power Cost($)
Gyratory Crusher 7.1819 kHP 38100
Pneumatic
Conveyor 431700
Rod Mill 962.0613 kW-h 80000
Boiler:
Title flow rate (kg/h) Cost($)
Boiler 91041.863 1113202.454
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Compressor:
Title No. Cost($)
Centrifugal 3 830995.1458
Reciprocating 1 389528.9746
Pumps:
Title No. Cost($)
Pump 7 29400
Total Purchase Cost = $11657066.2
FCI = Fixed Capital Investment
Fixed Capital Cost:
S.No. Fixed Capital Cost
facto
r
1 Equipment Installation 0.4
2 Piping (installed) 0.7
3
Instrumentation & controls
(installed) 0.2
4 Electrical (installed) 0.1
5 Building (including services) 0.15
6 Utilities 0.5
7 Site development 0.05
8 Ancillary Buildings 0.15
PPC = $ 38509713.19
9 Engineering & Supervision 0.3
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10 Contractor's fee 0.05
11 Contingency expenses 0.1
Fixed capital = $ 54933924.47
Working Capital = $ 8240088.67
Total Capital Investment = $ 63174013.14
OPERATING COSTS:
An estimate of the operating costs, the cost of producing the product, is needed to judge the
viability of a project, and to make choices between possible alternative processing schemes.
These costs can be estimated from the flow-sheet, which gives the raw material and service
requirements, and the capital cost estimate. The cost of producing a chemical product will
include the items listed below. They are divided into two groups.
1. Fixed operating costs: costs that do not vary with production rate. These are the bills that
have to be paid whatever the quantity produced.
2. Variable operating costs: costs that are dependent on the amount of product produced.
Fixed costs
1. Maintenance (labour and materials).
2. Operating labour.
3. Laboratory costs.
4. Supervision.
5. Plant overheads.
6. Capital charges.
7. Rates (and any other local taxes).
8. Insurance.
9. Licence fees and royalty payments.
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Variable costs
1. Raw materials.
2. Miscellaneous operating materials.
3. Utilities (Services).
4. Shipping and packaging.
The division into fixed and variable costs is somewhat arbitrary. Certain items can be classified
without question, but the classification of other items will depend on the accounting practice of
the particular organisation. The items may also be classified differently in cost sheets and cost
standards prepared to monitor the performance of the operating plant. For this purpose the
fixed-cost items should be those over which the plant supervision has no control, and the
variable items those for which they can be held accountable.
Company’s general operating expenses include:
1. General overheads.
2. Research and development costs.
3. Sales expense.
4. Reserves.
How these costs are apportioned will depend on the Company’s accounting methods. They
would add about 20 to 30 per cent to direct production costs at the site.
Miscellaneous materials (plant supplies)
Under this heading are included all the miscellaneous materials required to operate the plant
that are not covered under the headings raw materials or maintenance materials.
Miscellaneous materials will include:
1. Safety clothing: hard hats, safety glasses etc.
2. Instrument charts and accessories
3. Pipe gaskets
4. Cleaning materials
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Bachelor Thesis Project 2010
An accurate estimate can be made by detailing and costing all the items needed, based on
experience with similar plants. As a rough guide the cost of miscellaneous materials can be
taken as 10 per cent of the total maintenance cost.
Utilities (services)
This term includes, power, steam, compressed air, cooling and process water, and effluent
treatment; unless costed separately. The quantities required can be obtained from the energy
balances and the flow-sheets. The prices should be taken from Company records, if available.
They will depend on the primary energy sources and the plant location.
Shipping and packaging
This cost will depend on the nature of the product. For liquids collected at the site in the
customer’s own tankers the cost to the product would be small; whereas the cost of packaging
and transporting synthetic fibres or polymers to a central distribution warehouse would add
significantly to the product cost.
Maintenance
This item will include the cost of maintenance labour, which can be as high as the operating
labour cost, and the materials (including equipment spares) needed for the maintenance of the
plant. The annual maintenance costs for chemical plants are high, typically 5 to 15 per cent of
the installed capital costs. They should be estimated from a knowledge of the maintenance
costs on similar plant. As a first estimate the annual maintenance cost can be taken as 10 per
cent of the fixed capital cost; the cost can be considered to be divided evenly between labour
and materials.
Operating labour
This is the manpower needed to operate the plant: that directly involved with running the
process. The costs should be calculated from an estimate of the number of shift and day
personnel needed, based on experience with similar processes. It should be remembered that
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Bachelor Thesis Project 2010
to operate three shifts per day, at least five shift crews will be needed. The figures used for the
cost of each man should include an allowance for holidays, shift allowances, national insurance,
pension contributions and any other overheads.
Supervision
This heading covers the direct operating supervision: the management directly associated with
running the plant. The number required will depend on the size of the plant and the nature of
the process. The site would normally be broken down into a number of manageable units. A
typical management team for a unit would consist of four to five shift foremen, a general
foreman, and an area supervisor (manager) and his assistant. The cost of supervision should be
calculated from an estimate of the total number required and the current salary levels,
including the direct overhead costs.
Laboratory costs
The annual cost of the laboratory analyses required for process monitoring and quality control
is a significant item in most modern chemical plants. The costs should be calculated from an
estimate of the number of analyses required and the standard charge for each analysis, based
on experience with similar processes. As a rough estimate the cost can be taken as 20 to 30 per
cent of the operating labour cost, or 2 to 4 per cent of the total production cost.
Plant overheads
Included under this heading are all the general costs associated with operating the plant not
included under the other headings; such as, general management, plant security, medical,
canteen, general clerical staff and safety. It would also normally include the plant technical
personnel not directly associated with and charged to a particular operating area. This group
may be included in the cost of supervision, depending on the organisation’s practice. The plant
overhead cost is usually estimated from the total labour costs: operating, maintenance and
supervision. A typical range would be 50 to 100 per cent of the labour costs; depending on the
size of the plant and whether the plant was on a new site, or an extension of an existing site.
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Bachelor Thesis Project 2010
Capital charges
The investment required for the project is recovered as a charge on the project. How this
charge is shown on an organisation’s books will depend on its accounting practices. Capital is
often recovered as a depreciation charge, which sets aside a given sum each year to repay the
cost of the plant. If the plant is considered to “depreciate” at a fixed rate over its predicted
operating life, the annual sum to be included in the operating cost can be easily calculated. The
operating life of a chemical plant is usually taken as 10 years, which gives a depreciation rate of
10 per cent per annum. The plant is not necessarily replaced at the end of the depreciation
period. The depreciation sum is really an internal transfer to the organisation’s fund for future
investment. If the money for the investment is borrowed, the sum set aside would be used to
repay the loan. Interest would also be payable on the loan at the current market rates.
Normally the capital to finance a particular project is not taken as a direct loan from the market
but comes from the company’s own reserves. Any interest charged would, like depreciation, be
an internal (book) transfer of cash to reflect the cost of the capital used.
Rather than consider the cost of capital as depreciation or interest, or any other of the
accounting terms used, which will depend on the accounting practice of the particular
organisation and the current tax laws, it is easier to take the cost as a straight, unspecified,
capital charge on the operating cost. This would be typically around 10 per cent of the fixed
capital, annually, depending on the cost of money.
Local taxes
This term covers local taxes, which are calculated on the value of the site. A typical figure would
be 1 to 2 per cent of the fixed capital.
Insurance
The cost of the site and plant insurance: the annual insurance premium paid to the insurers;
usually about 1 to 2 per cent of the fixed capital.
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Bachelor Thesis Project 2010
Royalties and licence fees
If the process used has not been developed exclusively by the operating company, royalties and
licence fees may be payable. These may be paid as a lump sum, included in the fixed capital, or
as an annual fee; or payments based on the amount of product sold. The cost would add about
1 per cent to 5 per cent to the sales price.
Variable Costs:
S.No
.
Nature of expenses Cost($)
1 Raw materials
(a) Coal 15833333.
3
(b) DEA 13648111.
1
2 Miscellaneous materials 189427.32
6
3 Utilities
(a) Water 353326271
Fixed Costs:
4 Maintenance 1894273.2
6
5 Operating Labour 2462555.2
3
6 Supervision 37885.465
2
7 Plant Overheads 1231277.6
2
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Bachelor Thesis Project 2010
8 Laboratory 738766.57
9 Capital Charges 2273127.9
1
10 Insurance 378854.65
2
11 Local Taxes 1136563.9
5
12 Royalties 378854.65
2
13 Depreciation 3662261.6
3
Direct Production Costs = $417580726.9
14 Sales Expense 19859578.
2
15 General Overheads 19859578.
2
16 Research and Development 39719156.
3
Annual Operating Costs = $476629875.8
ESTIMATION OF GROSS PROFIT AND SELLING PRICE
Assuming Rate of Return (ROR) = 25%
Profit = ROR*Total Capital Investment
= $ 15793503.29
Payback Period = Fixed Capital / (Profit + Depreciation)
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Bachelor Thesis Project 2010
= 2.823529412 years
Total Selling Price = (Production Cost + Gross Profit) / Annual Production
= $ 0.559503886 per kg
Cash Flow Chart for the project
Yea
r
Sales ($) Production
Cost ($)
Net Income
($)
Depreciation
($)
Cash Flow
($)
Cum. Cash flow
($)
1 49242337
9
476629875.
8
15793503.29 3662261.631 19455764.9
2
23118026.55
2 49242337
9
476629875.
8
15793503.29 3662261.631 19455764.9
2
42573791.46
3 49242337
9
476629875.
8
15793503.29 3662261.631 19455764.9
2
62029556.38
4 49242337
9
476629875.
8
15793503.29 3662261.631 19455764.9
2
81485321.3
5 49242337
9
476629875.
8
15793503.29 3662261.631 19455764.9
2
100941086.2
6 49242337
9
476629875.
8
15793503.29 3662261.631 19455764.9
2
120396851.1
7 49242337
9
476629875.
8
15793503.29 3662261.631 19455764.9
2
139852616
8 49242337
9
476629875.
8
15793503.29 3662261.631 19455764.9
2
159308381
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Bachelor Thesis Project 2010
9 49242337
9
476629875.
8
15793503.29 3662261.631 19455764.9
2
178764145.9
10 49242337
9
476629875.
8
15793503.29 3662261.631 19455764.9
2
198219910.8
11 49242337
9
476629875.
8
15793503.29 3662261.631 19455764.9
2
217675675.7
12 49242337
9
476629875.
8
15793503.29 3662261.631 19455764.9
2
237131440.6
13 49242337
9
476629875.
8
15793503.29 3662261.631 19455764.9
2
256587205.5
14 49242337
9
476629875.
8
15793503.29 3662261.631 19455764.9
2
276042970.5
15 49242337
9
476629875.
8
15793503.29 3662261.631 19455764.9
2
295498735.4
-4 -2 0 2 4 6 8 10 12 14 16
-100000000
-50000000
0
50000000
100000000
150000000
200000000
250000000
Series2
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Bachelor Thesis Project 2010
Break Even Analysis:
N = f/(S-V)
F = fixed charges + plant overhead cost + general expenses (per kg of product)
S = Selling price = $ 0.559503886 per kg of product
V = Variable Price (per kg of product)
Plant capacity = 116206.5107*24*300 = 836686877 kg per annum
f = $ 63588202.66 per annum
f = $ 0.076 per kg
V = Direct Production Cost / Total Capacity
= 386447261.4/836686877= $ 0.461878 per kg
N = 0.076/(0.559503886 -0.461878)
= 0.7784
Conclusion: The Plant must be operated at 77.84% capacity to achieve breakeven.
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Bachelor Thesis Project 2010
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250
Bachelor Thesis Project 2010
251
Bachelor Thesis Project 2010
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