Final BTP Report

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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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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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

32


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

33


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

34


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

35


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

36


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

37


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.

38


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.

39


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

40


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

41


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:

42


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:

43


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


not exceeding. 6049

D Exceeding 4200 but

not exceeding 4940


not Exceeding 5597

E Exceeding 3360 but

not exceeding 4200


not exceeding 5089

F Exceeding 2400 but

not exceeding 3360


not exceeding. 4324


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

45


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

46


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

47


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

48


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

49


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.

50


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

51


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


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

53


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

54


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

55


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.

56


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

57


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

58


S 403.15625 kg/h

O 9042.21875 kg/h

Steam(kg/h) 31666.7373 kg/h


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


Syngas(kg/

h)

149808.4945 kg/h

CO 89849.4534 kg/h

CO2 12004.6947 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


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

60


water 32358.58881 kg/h

CO 88.4794375 kg/h

CO2 297.765622 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

61


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


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



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


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

64



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

65


DEA 4837.09557 kg/h


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

66


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

67


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

68


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


∫ 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

70


Temperature, C 40 39 39.3 35.6


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


Enthalpy, watt -1.62E+09 -68895264 -1.63E+09 -57870391

Net heat transferred = -2.49E+04watt

71


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


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

72


D = 34.17 m

& H = 17.09 m

Syngas Storage Tank


Density of stream = 157.899 kg/m3 (@pressure = 15 bar)



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


Density of stream = 5.0 kg/m3



Capacity of tank required = (7419.946*5)/0.8 = 46374.66 m3 ~ 50000 m3


Assuming D/H = 2

= 25000

D = 39.92 m

& H = 19.96 m

73


Nitrogen Storage Tank





Capacity of tank required = (4206.496*5)/0.8 = 26290.6 m3 ~ 26000 m3


Assuming D/H = 2

= 13000

D = 32.10 m

& H = 16.05 m

DEA Storage Tank




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

74


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

75


*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

76


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

77


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


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))

79


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


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

81


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


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


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


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


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


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






Number of baffles 6

Tube passes 1

Tube number 1167



Ao/Ai ratio 1.21


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 out, SS 11032.44



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


889 / 3048 mm Type BEM 1 1m2 1

CC

/ / / // / / /

/ / / // / / /

Ao basedC

bar / / / /C

mmIn mm 1 / /

1 / /Nominal / /



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


10.21430

water

0.180.20684

911.22

30.28Cut(%d) 349.25Spacing: c/c


Carbon Steel TypeBaffle-crossing

Intermediate

1

-

3.18

-101.688.9

Connections

Channel or bonnet

Tube No.

Carbon Steel 889

508


0





Dew / Bubble point

Molecular wt, NC

0


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


Avg

-Channel cover -



Shell cover

10

0.06620.6741

Size/rating

442.1 Clean 493

-Out



bar


PressureVelocity

m2*K/Wbar

1m/s

Design temperature


1

0.00011 0.00011

132.22 160

kW

3.44738

MTD corrected2786.1

Sketch

0.00013

-


- - 508


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



89




Number of baffles 8

Tube passes 1

Tube number 1767



Ao/Ai ratio 1.21


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 out, SS 5843.96



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


1092.2 / 5486.4 mm Type BEM 1 2m2 2

CC

/ / / // / / /

/ / / // / / /

Ao basedC

bar / / / /C

mmIn mm 1 / /

1 / /Nominal 1 / /



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


14.66030

water

0.120.20684

1117.6

34.89Cut(%d)Inlet

596.9Spacing: c/c


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


0





Dew / Bubble point

Molecular wt, NC

0


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


Avg

-Channel cover -



Shell cover

10

0.06120.6583

Size/rating

364.4 Clean 398.3

-Out



bar


PressureVelocity

m2*K/Wbar

1m/s

Design temperature


1609.61

0.00011 0.00011

115.56 115.56

kW

3.44738

MTD corrected2782.8

Sketch

0.00013

-


- - 609.6


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


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


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")

93


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




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

94


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

95


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



96



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)

97


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

98


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

99


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

100


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




Cool Syngas outlet temp, C 80




water Inlet Pressure, bar 1.03


water outlet temp, C 95


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




Cool Syngas outlet temp, C 80


101




water Inlet Pressure, bar 1.03


water outlet temp, C 75.33


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

102


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

103


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.

104


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

105


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

106


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:

107


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

108


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.

109


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.

110


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

111


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

112


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

113


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

114


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

115


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


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






Test pressure bar 1.3 13

Design temperature C 132 160 160

Average metal temperature C 132 160 160



allow

mm 1.59 1.59


allow

mm 1.59 1.59



Nozzle flange rating

Post weld heat treatment Program Program



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


minimum

thk.

Actual

thickness

mm 12 12 12 12 2.11


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





119


Bolt number 52 52





Flange overlay mm

Recess mm


Lap jnt ring OD mm

Hub length mm

Hub slope in


Tubesheets

Front Rear


TEMA minimum thickness mm 15.8

8

15.88

TEMA bending thickness mm 37.3

4

37.34


TEMA flange extension thk mm 20.8

4

20.84


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


120


Clad thickness (not included

above)

mm

Tube Details

Tube type Plain

Tube OD mm 19.05



Tube length mm 3048

Tube pitch mm 23.81

Tube pattern 30


121


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)


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

122


Tube Layout:

123


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



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





Test pressure bar 1.3 13

Design temperature C 110 115.56 115.56

Average metal temperature C 110 115.56 115.56

124




allow

mm 1.59 1.59


allow

mm 1.59 1.59



Nozzle flange rating

Post weld heat treatment Program Program



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


Joint

efficiency

Spot Spot Spot Spot

125


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





Bolt number 52 52







126


Tubesheets

Front Rear


TEMA minimum thickness mm 15.8

8

15.88

TEMA bending thickness mm 38.3

7

38.37


TEMA flange extension thk mm 20.8

4

20.84


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


Clad thickness (not included

above)

mm

Tube Details

Tube type Plain

Tube OD mm 19.05



Tube length mm 5185.4

127


Tube pitch mm 23.81

Tube pattern 30


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:



Nozzles (1)


Couplings / Supports (2)


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


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



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

129


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


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.)

130


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)


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



(Doro/2)1/2

1.609569

9 M


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


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)


A 9.36E+02 mm2 (A=(d+2c) *tr)


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


Calculations

Hence, tr = 0.516 Mm


C = corrosion allowance = 2 mm

for

nozzle

J = 1

( as opening is assumed away from any

seam weld)


A 37.152 mm2 (A=(d+2c) *tr)

(Ref: Pg-88,

B.C.B.)

133



As 970.848 mm2 (As=(d+2c)*(tn-tr-c)) (Ref: Pg-88, B.C.B.)


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


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


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


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


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


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))=

139


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

140


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

141


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

142


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)


Operating Temperature 40 oC

Design Temp 50 oC


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)


Do 2.932 M (Do=Di+2tstd)

Do/Di

1.011034

5 <1.5

Hence, condition satisfied for thin walled design

Design of Heads

143


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


(Doro/2)1/2

1.609569

9 M


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

144


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


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


C = corrosion allowance = 2 mm for nozzle

J = 1

(as opening is assumed away from any

seam weld)


A 9.45E+02 mm2 (A=(d+2c) *tr)



As 6.32E+01 mm2 (As=(d+2c)*(tn-tr-c)) (Ref: Pg-88, B.C.B.)


in the heads

For shell:

Assuming nozzle outer diameter do = 100 mm 0.1 M

145


nozzle wall thickness 16 mm 0.016 M


Calculations

Hence, tr = 0.516 Mm


C = corrosion allowance = 2 mm

for

nozzle

J = 1

( as opening is assumed away from any

seam weld)


A 37.152 mm2 (A=(d+2c) *tr)

(Ref: Pg-88,

B.C.B.)


As 970.848 mm2 (As=(d+2c)*(tn-tr-c)) (Ref: Pg-88, B.C.B.)


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.)

146


M 3.75 M


B.C.B.)

Y 52.05 MN/m2


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


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

148

*G *2b*mp pH

Wg Gby


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.)

149

1 /sC nB


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

150

21 / 4W B p


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

151

2 F

FO

MC Yt

BS


(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

152


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) =

153


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

154


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.

155


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.

157


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

158


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

159


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.

160


Since Pressure

maintenance is also of

161

Figure 16 PID of Storage Tank


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


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


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


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

162


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


It is similar to absorber.

163


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


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

164


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

165


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

166


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

167


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;

168


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

169


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.

170


171


172


Environmental

Protection and

Energy

Conservation

173


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.

194

Typical COS hydrolysis flowsheet

Figure 20 Typical COS hydrolysis flowsheet


195


196


Plant Utilities

197


198


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


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

212


213


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-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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220


ORGANIZATIONAL

STRUCTURE AND

MANPOWER

REQUIREMENT

221


222


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

225


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

226


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

227


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

228


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:

229


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

230

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


8.3 Organization Chart

\

231


Figure 22. Organizational Structure

232


233


Economic

Evaluation and

Profitability of the

Project

234


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.

235


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.

236


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:

237


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

238


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

239


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.

240


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

241


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

242


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.

243


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.

244


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

245


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)

246


= 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

247


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

248


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.

249


References

250


251


Wayne Doherty., The effect of air preheating in a biomass CFB gasifier using ASPEN Plus

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252


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Astarita, G., Savage, D.W. and Bisio, A. Gas Trearing with Chemical Soluents John

Wiley and Sons, Chichester, UK (1983)

Sartori, G., Ho, W.S., Savage, D.W., Chludzinski, G.R. and Wiechart, S. Sep Purif

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253

Final BTP Report

Documents

Transcript of Final BTP Report