A DESIGN PROJECT ON PRODUCTION OF 1000 TPD SYNGAS BY

THE GASIFICATION OF HANGU COAL USING FLUIDIZED BED

GASIFIER

Submitted to
Department of Chemical Engineering
University of Gujrat
In partial fulfilment of requirement
For the degree of B.Sc Chemical Engineering
Session 2019-2023

SUPERVISED BY:
ENGR. MUHAMMAD TAHSEEN SADIQ
SUBMITTED BY:
SYEDA MEMOONA KAZMI 19013123-025
SHAMOON SHAHID BUTT 19013123-038
DANYAL NASIR 19013123-051

DEPARTMENT OF CHEMICAL ENGINEERING

UNIVERSITY OF GUJRAT

1
 ACKENOWLEDGMENTS
We express gratitude and praise to Allah Almighty, The Creator of universe and most Beneficent and
Merciful, guided us in all difficulties. On the very beginning of this project, we would like to express our
sincere & heartfelt obligation towards our parents, family and friends. Without their active guidance, help,
cooperation & encouragement, we would not have made headway in this final year project.
We are highly grateful and pay gratitude to our honorable supervisor Engr. Muhammad Tahseen Sadiq
for his conscientious guidance and encouragement to work on such imperative topic.
We are extremely thankful and pay our gratitude to our worthy Chairperson, Prof. Dr Ghulam Abbas for
his valuable guidance and support.
 ABSTRACT
Energy is important for the whole world. So, every state intends and needs to be self-sufficient into energy
sector. These are our motivations to work for optimum utilization of the energy source of Pakistan especially
of coal. Coal is very potential source of energy that can be utilized in number of ways and methods.
In Pakistan, Nature has gifted abundant amount of coal, but of low quality, so it cannot be used directly
that's why it needs the process of gasification and purification before it can be utilized.
After purification, many products that can be natural gas, acetic anhydride, methyl alcohol and liquid fuels
can be obtained. As our project is concerned with the production of synthesis gas from Hangu coal using the
Fluidized bed Coal Gasification Technology, it includes Introduction to coal and Gasification,Litrature
Review, Preliminary Hazard Analyis, Coceptual Deisgn Analysis, Heat Integration & Process Flow
Diagram, Material and Energy balance, Instrumentation and process control and at the end cost evaluation
for the project is carried out.
 Table of contents

CHAPTER 01..........................................................................................................................................................................................
INTRODUCTION...................................................................................................................................................................................
1.1. Coalification......................................................................................................................................................................................
1.2. Chemistry..........................................................................................................................................................................................
Peat...........................................................................................................................................................................................................
Lignite....................................................................................................................................................................................................10
Bituminous Coal....................................................................................................................................................................................10
Anthracite Coal......................................................................................................................................................................................10
Table 1.1: Classification of coal.............................................................................................................Error! Bookmark not defined.
Table 1.2:Analysis of hangu coal...........................................................................................................Error! Bookmark not defined.
CHAPTER 2..........................................................................................................................................................................................14
LITERATURE REVIEW......................................................................................................................................................................14
Electricity Generation:-..........................................................................................................................................................................14
Production of Steel:-..............................................................................................................................................................................14
Industrial Use:-.......................................................................................................................................................................................14
Gasification and Liquefaction:-..............................................................................................................................................................14
Domestic Use:-.......................................................................................................................................................................................15
Coal reserves of Pakistan.......................................................................................................................................................................15
Market economic value..........................................................................................................................................................................15
World wide coal consumption...............................................................................................................................................................17
Table 2.2:Worldwide Coal consumption...............................................................................................Error! Bookmark not defined.
2.2 Physical Properties of Syn Gas:-......................................................................................................................................................18
2.3 Chemical Properties of Syn Gas:-....................................................................................................................................................18
2.4 Gasifiers:-.........................................................................................................................................................................................19
Fixed Bed Gasifier:-...............................................................................................................................................................................19
Fludized Bed Gasifier:-..........................................................................................................................................................................20
Blending of coals...................................................................................................................................................................................21
Entrained Flow Gasifier:-.......................................................................................................................................................................21
Steam Reforming:-.................................................................................................................................................................................21
CHAPTER 3.........................................................................................................................................................................................23
PRELIMINARY HAZARD ANALYSIS..............................................................................................................................................23
3.1 Safety And Environmental issue:-...................................................................................................................................................23
Air emissions:-.......................................................................................................................................................................................23
3.2 Coal Bottom Ash, Slag, and Fly Ash...............................................................................................................................................25
3.3 Material Safety:-..............................................................................................................................................................................26
3.4 Plant Safety:-....................................................................................................................................................................................29
CHAPTER 4.........................................................................................................................................................................................37
CONCEPTUAL DESIGN ANALYSIS.................................................................................................................................................37
4.1 Preliminary Reactor Optimization...................................................................................................................................................39
The Impact of Temperature....................................................................................................................................................................40
Material Balance:-..................................................................................................................................................................................47
Energy entering in gasifier from coal:...................................................................................................................................................58
Energy leaving from gasifier:................................................................................................................................................................58
CHAPTER 5..........................................................................................................................................................................................63
HEAT INTEGRATION AND PROCESS FLOW.................................................................................................................................63
Chapter 6................................................................................................................................................................................................64
Instrumentation and Process Control.....................................................................................................................................................64
6.9 Control loop around Waste Heat Boiler:.........................................................................................................................................72
CHAPTER 7..........................................................................................................................................................................................78
PROCESS EQUIPMENT DESIGN.......................................................................................................................................................78
Number of Tubes:...................................................................................................................................................................................84
Bundle dia and clearance........................................................................................................................................................................84
Tube Side Coefficient.............................................................................................................................................................................84
Shell Side Coefficient.............................................................................................................................................................................85
Baffle Spacing:.......................................................................................................................................................................................85
Shell Side Coefficient.............................................................................................................................................................................85
Pressure Drop.........................................................................................................................................................................................86
7.4 Absorption Column:..........................................................................................................................................................................86
Column Diameter...................................................................................................................................................................................87
Height of Column...................................................................................................................................................................................88
CHAPTER 8...........................................................................................................................................................................................93
COST ESTIMATION.............................................................................................................................................................................93
CHAPTER 9........................................................................................................................................................................................103
HAZOP STUDY AND ENVIRONMENTAL EFFECTS...................................................................................................................103
9.1. HAZOP Technique:.....................................................................................................................................................................105
9.2. Process of HAZOP Analysis:........................................................................................................................................................105
Guide words and parameters:...............................................................................................................................................................106
HAZOP study of Absorber:.................................................................................................................................................................109
Chapter 10............................................................................................................................................................................................110
Conclusion...........................................................................................................................................................................................110
Chapter 11...........................................................................................................................................................................................111
REFERENCES.....................................................................................................................................................................................111
 List of Tables
1.1. Classification of coal………………………………………………….….10
1.2. Analysis of Hangu coal……………………………………………….….11
1.3. Ultimate analysis of Hangu coal…………………………………………11
2.1. Countries and their coal reserves…………………...............................…14
2.2. Worldwide coal consumption…………………………………………....15
3.1 Air emission level for coal……………………………………………..…29
3.2 Air Effluent level for coal.……………………………………….……….29
4.1. Desirable syngas characteristics for different application…...…………..34
9.1. Hazop on reactor…………………………………………………………90
9.2.Hazop on heat exchanger………………………………………………....91
9.3. Hazop on separator……………………………………………………….91
9.4. Hazop on absorber…………………………………………………....…..92
 List of Figures

1.1 Types of Coal …………………………………………...........................08

1.2 Transformation of coal into subcategories……………………………….10
2.1Process Route for water gas……………………………………………….17
2.2 Fludized Bed Gasifier…………………………………………………….18
2.3 Steam Reforming…………………………………………………………19
3.1 Health SAFETY and Environment……………………………………….23
3.2 Safety Managemnent………………………………………………..……31
4.1. Process flow diagram………………………………………………….…37
4.2 Plant Layout……………………………………………………………...39
5.1. Process flow diagram after heat integration……………………………...54
6.1. Control loop around gasifier…………………………………………..…62
6.2. Control loop on heat exchanger……………………………………….…62
6.3. Control loop on compressor………………………………………….…..63
6.4. PNID………………………………………………………………..……64
 CHAPTER 01
INTRODUCTION
Coal is a combustible black or brownish black solid sedimentary rock, formed as rock
strata called coal seams. Coal comprises on carbon with different amounts of other elements,
Hydrogen, Sulfur, Oxygen and Nitrogen. Coal is formed when dead plants residue decays
into peat and is converted into coal by the heat and pressure of deep burial over million of
years.

The extraction of coal from the mines caused different types of suffocating problems and
other internal disease. In the last some decades, usage of coal damages the environment, due
to its high percentage of CO2 emission when burnt in open air. From a survey in 2018, 14
gigatons of gas emission which was 40% of fossil fuels and 25% of greenhouse gas. As
partner of world energy transition, many countries lessen their usage of coal from the
industries, also UN secretary had asked the govt to stop building new coal plants followed by
2020. It would increase the global warming and also tropical climate changes in different
regions of the world.

China is the largest coal importer and consumer. It demands almost half of the world coal.
Australia is the top exporter of coal following by Indonesia and Russia on the 2nd and third.

1.1. Coalification

The conversion of dead fossils fuels into coal called coalification. In the geological surveys,
the earth had dense forests in the low-lying wetlands areas. In these areas, when the process
of coalification began dead plants was protected from different biodegradable process,
oxidation due to mud and acidic water. Plants matter converted into peat. Then over the time
passes, due to heating process and heavy pressure under the earth crust caused loss of water,
methane and carbon dioxide and proportion of carbon black is increased.

The types of coal depends on the maximum pressure and temperature, percentage of carbon is
increased to lignite, sub-bituminous, bituminous coal and anthracite. Anthracite requires high
temperature of 180-250C to be formed under the crust while sub-bituminous form at mild
temperature of 35-80C.
 Figure 1.1 Types of Coal

1.2. Chemistry

i. Coal mining
Coal mining is the process of extracting coal from the deep ground. Coal is the major
energy source with large reserves and since the 1880s has been widely used to generate
electricity. Steel industries use coal as a fuel for extraction of iron from iron ore. In the
United Kingdom and South Africa, a coal mine and its structures are a colliery, coal mine
close to the ground is called a 'pit'.

ii. Production of coal

Worldwide coal production is expected to increase by a marginal 0.9% and reserves
of almost 8,126Mt in 2022, with output from India, China and South Africa crucial to this
increase. Collective production from these countries is expected to expand from 5.1 billion
tons in 2021 to 5.5 billion tons in 2022 – a 7.8% rise. Which is good signs for the safe energy
production.

Coal is mined commercially in over 50 countries. 7,921t (metric tons) of coal were produced
in 2019, a 70% increase over the 20 years since 1999. In 2018, the world production of brown
coal (lignite) was 803.2t, with Germany the world's largest producer at 166.3t. China is most
likely the second largest producer and consumer of lignite globally although specific lignite
production data is not made available. Coal production has grown fastest in Asia, while
Europe has declined.
iii. Types of coal
In the deep earth crust when heavy pressure is applied to biotic material for 100s of
years, results coal formed.
i.Peat
● Comprise on first stage of transformation.

● Contains less than 40 to 55 per cent carbon and more impurities.

● Contains sufficient volatile matter and lot of moisture [more smoke and more
pollution] are produced.

● It burns like wood, gives less heat, emits more smoke and leaves a lot of ash.

ii. Lignite
● Called Brown coal.

● Lower to high grade coal.

● 40 to 55 per cent carbon.

● Intermediate stage.

● Dark to black brown.

● Moisture content is high (over 35 per cent).

● It undergoes SPONTANEOUS COMBUSTION [Mostly creates fire accidents in

mines]

iii. Bituminous Coal

● Soft coal; most commonly available and used coal.

● Name derives from a liquid called Bitumen.

● Contains 40 to 80 per cent carbon.

● Less moisture and volatile content (15 to 40 per cent)

● Dense, compact, and is usually of black colour.

● Its calorific value is very high because of high proportion of carbon and least moisture
content.

● Used in production of coke and gas and also used as household cooking.

iv. Anthracite Coal

● Best quality and hard coal.

● 80 to 95 per cent carbon content.

 ● Very little volatile matter.

● Very small proportion of moisture.

● Ignites slowly, less loss of heat also highly efficient.

● Burns with a nice short blue flame means reaction is a complete combustion example
like LPG.

Figure 1.2 Transformation of coal into sub catagories

Cannel coal (sometimes called "candle coal") is a variety of fine-grained, high-rank coal with
significant hydrogen content, which consists primarily of lignite.

There are several international standards for coal. The classification of coal is generally
based on the content of volatiles. However the most important distinction is between
thermal coal (also known as steam coal), which is burnt to generate electricity via steam
and metallurgical coal (also known as coking coal), which is burnt at high temperature to
make steel.
Hilt's law is a geological observation that (within a small area) the deeper the coal is
found, the higher its rank (or grade). It applies if the thermal gradient is entirely vertical.
 Table 1.1 Classification of Coal

1.4 Hangu Coal

The coal is dull to shinning black and ranges from high volatile B to C bituminous in rank.
The Hangu area coal occurs in the form of discontinuous stringers and lenses and is less than
2 meters thick. The average analytical results on as received basis indicate, the coal bed
contains 0.52% moisture, 14.2% ash, 4.2% sulphur, 53% fixed carbon and 32.64% volatile
matter. Based on the average BTU/lb and fixed carbon content of the Hangu Kachai coal
samples collected from the field, with minor exception of variation in color, the Hangu coal is
analogous to the known coals of the Baluchistan and the Salt Range areas. On the basis of its
stratigraphic position, mode of origin and structure, the Hangu-Kachai coal is comparable
with the Makarwal coal of the Surghar Range.

i. Proximate Analysis of Hangu Coal

According to the Geological survey of Pakistan
 Table1.2:Analysis of hangu coal

ii. Ultimate Analysis of Hangu Coal Range

Table 1.3: Ultimate analysis of hangu coal

 CHAPTER 2
LITERATURE REVIEW
2.1 Uses of Coal
Coal is the most commonly used energy source across the world. Here is a list of all the
major uses of coal.
● Provide Electricity
● Steel Production
● Industrial Use
● Gasification and Liquefaction
● Domestic Use
i. Electricity Generation:-
Coal is used in thermal power plants which further helps to produce electricity. Powdered
coal is burnt at high temperature which further turns water into steam. This steam is used to
turn turbines at high speed with a strong magnetic field. After this, electricity is finally
produced.
ii. Production of Steel:-
Coal is used indirectly to make steel. Coal is baked in furnaces to form coal coke. Once this is
formed, manufacturers use coke to smelt iron ore into Iron and make Steel. Meanwhile,
ammonia gas is usually recovered from coke ovens and this is used to manufacture Nitric
acid, Ammonia salts and fertilizers.
iii.Industrial Use:-
Many industries use coal to manufacture a number of products. Major industries are the
cement industry, paper and aluminum industry, chemical and pharmaceutical industry. Coal
provides many raw materials like benzol, coal tar, sulphate of ammonia etc. to chemical
industries. Coal is the cheap source of energy which is the main need of today’s industries.
iv. Gasification and Liquefaction:-
Coal also turned into a synthetic gas which a mixture of carbon monoxide and hydrogen.
These gases are an intermediate product that can be further converted into different products
like urea, methanol, pure hydrogen. Coal can also be turned into liquid known as synthetic
fuels. However, these chemicals produced from coal are
used primarily to make other products. These products includes aspirins, solvents, soap, dyes,
plastics and fibers which include nylon and rayon.
 v. Domestic Use:-
Coal is now used as domestic source of energy. Used as heat source in the northern areas and
as cooking in the villages and far off areas.
2.2. Coal reserves of Pakistan
Pakistan holds 3,377 million tons (MMst) of proven coal reserves as of 2016, ranking 20th in
the World. Most of the coal buried in the Tharparkar, Sindh but its rank is too low and need
to be pre-treated before functioning. Pakistan has proven reserves equivalent to 331.1 times
its annual consumption. This means it has about 331 years of Coal left (at current
consumption levels and excluding unproven reserves).
2.3. Market economic value
Energy markets are eager to work to reduce the global energy crisis. While oil and natural gas
are receiving much of the attention, coal markets are also experiencing significant for many
Countries by coal reserve

Anthracite & bitu Subbituminous & l

Rank Country Total
minous ignite

Ton
nes Tonnes Tonnes
% % %
(mil (mil) (mil)
)

United 220,16
1 30% 30,052 9.4% 250,219 24%
States 7

2 Russia 69,634 9.5% 90,730 28.4% 160,364 15%

3 Australia 70,927 9.7% 76,508 23.9% 147,435 14%

130,85
4 China 17.8% 7,968 2.5% 138,819 13%
1

5 India 96,468 13.1% 4,895 1.5% 101,363 10%

6 Indonesia 26,122 3.6% 10,878 3.4% 37,000 4%

7 Germany 3 0% 36,100 11.3% 36,103 3%

8 Ukraine 32,039 4.4% 2,336 0.7% 34,375 3%

9 Poland 20,542 2.8% 5,937 1.9% 26,479 3%

10 Kazakhstan 25,605 3.5% 0 0% 25,605 2%

11 Turkey 551 0.1% 10,975 3.4% 11,526 1%

South
12 9,893 1.3% 0 0% 9,893 1%
Africa

New
13 825 0.1% 6,750 2.1% 7,575 1%
Zealand

14 Serbia 402 0.1% 7,112 2.2% 7,514 1%

15 Brazil 1,547 0.2% 5,049 1.6% 6,596 1%

16 Canada 4,346 0.6% 2,236 0.7% 6,582 1%

17 Colombia 4,881 0.7% 0 0% 4,881 0%

18 Pakistan 207 0% 2,857 0.9% 3,064 0%

19 Vietnam 3,116 0.4% 244 0.1% 3,360 0%

20 Hungary 276 0% 2,633 0.8% 2,909 0%

21 Greece 0 0% 2,876 0.9% 2,876 0%

Czech
22 110 0% 2,547 0.8% 2,657 0%
Republic

23 Mongolia 1,170 0.2% 1,350 0.4% 2,520 0%

24 Bulgaria 192 0% 2,174 0.7% 2,366 0%

25 Uzbekistan 1,375 0.2% 0 0% 1,375 0%

26 Mexico 1,160 0.2% 51 0% 1,211 0%

 27 Spain 868 0.1% 319 0.1% 1,187 0%

28 Thailand 0 0% 1,063 0.3% 1,063 0%

29 Venezuela 731 0.1% 0 0% 731 0%

734,90
– World 100% 319,879 100% 1,054,782 100%
3

Table 2.1: Countires and their coal reserves

Countries where coal remains a key fuel for electricity generation and a range of industrial
processes. At the same time, the world’s continued using excess amounts of coal is
heightening climate changes, as coal is the largest single source of energy-related carbon
dioxide (CO2) emissions. Since the release of annual Coal 2021 report last December,
Russia’s invasion of Ukraine has significantly disrupted global energy markets in 2022.
Globally the industries directly employ over 7 million workers, which create millions of
indirect jobs throughout the world.

2.4. World wide coal consumption

Public Agriculture/ Fishig Non- Non-

Industry Transpot Residentil services forestry (TJ specifid energyuse
Year (TJ) (TJ) (TJ) (TJ) (TJ) ) (TJ) (TJ) Units

191047
1990 6 393108 6410149 2157683 599552 1642 1713336 1088049 TJ

193952
1995 9 135428 4755588 879330 535162 1308 1039938 91034 TJ
 167065
2000 4 25643 3223657 647477 322032 390 801412 95396 TJ

272922
2005 9 10974 3285987 1058912 517566 491 1110036 12496 TJ

362424
2010 1 7842 3221884 1359888 550811 454 1362475 1512448 TJ

369134
2015 0 2606 3182228 1440455 642446 24 1250176 2345575 TJ

316398
2020 1 37638 2336215 1009244 547234 100 873520 2236878 TJ
Table 2.2 Worldwide Coal consumption

2.5. Physical Properties of Syn Gas:-

As Syn gas comprises of carbon mono-oxide and hydrogen gas, combustible gas mixture
derived from solid fuel by gasification technology at high temperature and elevated pressure.
 Syn gas is combustible and can be used as a fuel.
 It has been used as a replacement for gasoline, when gasoline supply has been limited.
 Density of syn gas from coal is 1.0544kg/m3.
2.6. Chemical Properties of Syn Gas:-
The composition of syn gas can be vary significantly depending on the feedstock and the
gasification process involved. Syn Gas is 30% to 60% carbon mono-oxide (CO), 25% to 30%
hydrogen(H2), 0 to 5% of Methane(CH4), 5% to 15% of carbon dioxide(CO2).
It has lesser or grater amount of water vapour, smaller amounts of the sulfur compounds
hydrogen sulfide (H2S), Carbonyl Sulfide (COS) and finally some ammonia and other trace
contaminants are also present in it.
2.7. Gasifiers:-
Gasification is a process that converts organic or fossil-based carbonaceous materials at high
temperatures (>700°C), without combustion, with a controlled amount of oxygen and/or
steam into carbon monoxide, hydrogen, and carbon dioxide.

Figure 2.1 Process route of water gas

Types of Gasifiers:-
1. Fixed Bed Gasifier
2. Fludized Bed Gasifier
3. Entrained Flow Gasifier

i.Fixed Bed Gasifier:-

In this reactor, particle are moving downward and reacts with the gases that are
moving counter current to the coal particles. The particles for this reactor are of course sized
as the particles shows good permeability. The courser the size of that particles, the less the
chance of chemical burning either the chemicals are catalysts and also the pressure dropped
of that reactor. The top of gasifier is drying zone, Coal enter the reactor from the top and
dried heated and leave the reactor as product gas. The gas interacted with the fresh feed from
the reactor and as a result it cooled down these called carbonization zone (pyrolysis zone).
Next is Gasification zone, Char reacts with the CO2 and steam. Combustion happens in the
bottom of the reactor and O2 reacted with the Char. This is the exothermic zone as heat is
evolved from this zone. Here reactor have two different modes as Dry ash zone and ash
slagging zone.
The excess steam reacts with the Char and prevents the formation of ash but ash still
produced which is cooled by steam as it promotes solidification of ash.
ii. Fludized Bed Gasifier:-
Fluidized-bed gasifiers employ a reactor bed contained with a fluidizing solid, medium. Coal
is fed into the side of the reactor, while the oxidant (air or oxygen) are fed in from the bottom
of the reactor. Fluidized beds promote back-mixing, and efficiently mix feed coal particles
with coal particles already undergoing gasification. Due to the thorough mixing within the
gasifier, a constant temperature is sustained in the reactor bed. In fluidized reactor regimes,
the operating temperature should be high enough to decompose the tars and other liquid
products produced during pyrolysis and devolatilization. At the same time the temperature is
should be lower than the softening point of ash. This is to prevent ash from being formed,
because ash can cause problemssuch as defluidization as well as inhibit heat and mass
transfer. Due to this temperature constraints highly reactive coals, such as lignite are often
utilized so that a good carbon conversion can be achieved at the lower operating
temperatures. During Fluidization, some char particles are entrained in the raw syngas as its
leaves the top of the gasifier but are recovered and recycled back to the reactor via a cyclone.
Ash particles, removed below the bed, give up heat to the incoming steam and recycle gas. At
startup, the bed is heated externally before the feedstock is introduced. To sustain
fluidization, or suspension of coal particles within the gasifier, coal of small particles sizes
(<6 mm) are normally used.

Figure 2.2 Fludized Bed Gasifier

iii. Blending of coals

 This method involves blending high sodium/high sulfur lignite with a sub-bituminous
coal that has higher ash content, with lower sodium and sulfur. The idea behind this is that
the high melting point ash of the sub-bituminous enriches the coal with high melting point
ash and reduces the low melting point ash species.
iv. Entrained Flow Gasifier:-
In entrained-flow gasifiers, air or oxygen with steam is fed into the top of the gasifier
which causes the coal particles to become entrained within the reactor. In order for this
entrancement to occur the coal must be ground to a fine particle size of 100μm, this fine
particle size also ensures good mass transfer between the coal particles and oxidant.Entrained
flow gasifiers operate in a co-current flow pattern, and usually residence times for these types
of reactors are on the order of a few seconds. Entrained flow gasifiers operate at high
temperatures to ensure good conversion of carbon materials to syngas.
Draw Back:-
Although the reactor is versatile in the type of coal that is used certain coals are
avoided due to the properties of the coal. For example, lignite coal is often not desired for
entrained flow gasifiers because of its high moisture content,this requires more energy to be
put into the reactor to evaporate the excess moisture and is not as economical as the high
ranked coals. Coals with high ash contents are also not preferred because of the additional
energy required to melt the ash into slag.
2.8. Steam Reforming:-
Steam reforming is the most widely used technique for the production of Hydrogen.In steam
reforming plant ,the feed is normally desulferized mixed with steam and converted to syn gas
over a nickel containing catalyst. The process is completed by the adiabatic carbon
Monoxide(CO) shift and pressure swing adsorption unit to obtain high purity hydrogen.
Process option include feed compression and evaporation , adiabatic feed pre-reforming to
process heavier feeds and optimized feed consumption and steam production. Operating
conditions of steam reforming vary depending on the individual applications. It contains wide
range of established commercial application with outlet temperature of 740-950C and
pressure upto 50 bars.
 Figure 2.3Steam Reforming

The reliability and availability of hydrogen plant are secured by the following measurement:
● Plant related design e.g. the selection of moderate and technical proven process
parameters.
● Design of the equipment e.g use of proven equipment; use of redundant equipment
such as two pumps per 100% certain safety margins between operating and design
figures.
● Safety instruments design, e.g use of 2/3 voting trip system. The flexibility of a
hydrogen plant is largely denoted.
● Capability of processing different feedstock is provided or losses of one feedstock can
be compensated.
● Possible feedstock analysis variation can be covered without causing any problem.
● High turn-down ratio can be achieved.
 CHAPER 3
PRELIMINARY HAZARD ANALYSIS
3.1 Safety And Environmental issue:-
The safe operation of a chemical process is a primary requirement for the well-being of the
people in the plant and for its continued contribution to the economic development. Potential
environmental issues associated with coal processing projects include:
· Air emissions
· Wastewater
· Hazardous materials
· Wastes
· Noise
i. Air emissions:-
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.
i. To Control Air Polution:-
Recommendations to prevent and control fugitive sources of air pollutants include:
 Reduce fugitive emissions from pipes, valves, seals, tanks, and other infrastructure
components by regularly monitoring with vapor detection equipment and maintenance or
replacement of components as needed in a prioritized manner;
 Maintain stable tank pressure and vapor space by:
Coordination of filling and withdrawal schedules and implementing vapor balancing
between tanks, (a
process whereby vapor displaced during filling activities is transferred to the vapor space of
the tank being emptied or to other containment in preparation for vapor recovery.
 Use of white or other color paints with low heat absorption properties on exteriors of
storage tanks for lighter distillates such as gasoline, ethanol, and methanol to reduce heat
absorption. Potential for visual impacts from reflection of light off tanks should be
considered.
 Based on the tank storage capacity and vapor pressure of materials being stored, select a
specific tank type to minimize storage and working losses according to internationally
accepted design standards.
 For fixed roof storage tanks, minimize storage and working losses by installation of an
internal floating roof and seals.
ii. Greenhouse Gases (GHGs)
Significant amounts of carbon dioxide (CO2) may be produced in SynGas
manufacturing, particularly during the water-gas shift reaction, in addition to all combustion-
related processes (e.g., electric power production and by-product incineration or use in co-
generation). Recommendations for energy conservation and the management of greenhouse
gas emissions are project and site-specific but may include some of those discussed in the
General EHS Guidelines. At integrated facilities, operators should explore an overall facility
approach in the selection of process and utility technologies.
iii. Exhaust Gases
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.
ii. Waste Water:-
Process wastewater may become contaminated with hydrocarbons, ammonia and
amines, oxygenated compounds, acids, inorganic salts, and traces of heavy metal ions.
Recommended process wastewater management practices include:
 Prevention of accidental releases of liquids through inspections and maintenance of
storage and conveyance systems, including stuffing boxes on pumps and valves and
other potential leakage points, as well as the implementation of spill response plans.
 Provision of sufficient process fluids let-down capacity to maximize recovery into the
process and to avoid massive process liquids discharge into the oily water drain
system.
 Design and construction of wastewater and hazardous materials storage containment
basins with impervious surfaces to prevent infiltration of contaminated water into soil
and groundwater. Specific provisions for the management of individual wastewater
streams include the following:
 Amines spills resulting from the carbon dioxide alkaline removal system downstream
of the Gasification Unit should be collected into a dedicated closed drain system and,
after filtration, recycled back into the process;
 Effluent from the stripping column of the F-T Synthesis Unit, which contains
dissolved hydrocarbons and oxygenated compounds (mainly alcohols and organic
acids) and minor amounts of ketones, should be recirculated inside the F-T Synthesis
Unit to recover the hydrocarbons and oxygenated compounds in a stripping column;
 Acidic and caustic effluents from demineralized water preparation, the generation of
which depends on the quality of the raw water supply to the process, should be
neutralized prior to discharge into the facility’s wastewater treatment system;
 Blow-down from the steam generation systems and cooling towers should be cooled
prior to discharge. Cooling water containing biocides or other additives may also
require does adjustment or treatment in the facility’s wastewater treatment plant prior
to discharge; and
 Hydrocarbon-contaminated water from scheduled cleaning activities during facility
turn-around (cleaning activities are typically performed annually and may last for a
few weeks), oily effluents from process leaks, and heavy-metals.
 iii. Noise
 The principal sources of noise in coal processing facilities include the physical
processing of coal (e.g. screening, crushing, sizing and sorting), as well as large
rotating machines (e.g., compressors, turbines, pumps, electric motors, air coolers,
and fired heaters). During emergency depressurization, high noise levels can be
generated due to release of high-pressure gases to flare and / or steam release into the
atmosphere.
 Figure 3.1 Health Safety And Environment

3.2. Coal Bottom Ash, Slag, and Fly 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 flow-able 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 can not be recycled, they should be disposed of in a licensed landfill facility
designed and operated according to good international industry practice.

3.2.i Environmental regulations

Various federal and state laws may specify that the temperature, concentrations of
chemicals, and flow rates of the effluents from a plant be within certain limits.
3.3 Material Safety:-
There are three types of mining most widely available all over the world as these based on the
material which been extracted. These are:
Surface Mining
Highwall Mining
Underground Mining

3.3.i Surface Mining:-

1.Surface mine must have a standard operating procedure for the following—
● Transporting explosives at the mine;
● Inspecting and reporting on the safety of equipment used at the mine for
manufacturing, storing, transporting and delivering explosives;
● Taking appropriate action to make equipment mentioned in paragraph (b) safe;
● Accounting for explosives brought onto the mine;
● Checking for, and isolating, explosives that have deteriorated;
● Minimizing the risk of theft or misuse of explosives;
● Identifying and controlling hazards— (i) during the charging and firing of explosives;
and (ii) in particular places, including, for example in a storage bin feeder in which an
explosive is to be used to clear a blockage;
● Finding, recovering and detonating misfired explosives; (i) keeping a record about
misfired explosives.

2. The procedure for transporting explosives must address the following matters—
● Packaging explosives for transport;
● The design of vehicles and compartments in which explosives are to be transported;
● Marking packages, containers and vehicles used for transporting explosives; stowing
and segregating explosives during transport;
● The appropriate load limit for vehicles carrying explosives.
● Transport procedures necessary to reduce the probability and consequence of
incidents.
● The competence required of persons for transporting explosives, including handling
the explosives and mixing and discharging the explosives from vehicles;
● Temporary storage; (i) restricted areas; (j) emergency response.
 The procedure for identifying and controlling hazards during the charging and firing
of explosives must—
● Have regard to the following—
● The proximity of unrelated activities to the charging and firing;
● Ground conditions; and state the allowable period for the explosives to remain in the
ground before being detonated.

3.3.ii. High wall Mines:-

1. If highwall mining is carried out at a surface mine, the mine’s safety and health
management system must provide for conducting the highwall mining activity in a
way that controls the risk of unplanned highwall instability.
2. The system must include standard operating procedures for the following—
the entry of persons to, and the evacuation of persons from, an area where highwall mining is
carried out;
● Fire prevention, and fire fighting, associated with highwall mining;
● Identifying and marking areas near highwall mining where—
● Explosive atmospheres may occur.
● It is safe to use cutting and welding equipment, or smoke cigarettes;
● Continuously monitoring oxygen and methane in the atmosphere at the cutting face in
the highwall mining excavation during cutting if an explosive atmosphere that may
cause a risk is present, or suspected to be present, in the excavation;
● Working safely in areas where there is a potential for flooding from any source;
● Enabling a person to communicate with a person on the surface when work is being
carried out in the underground excavation.
● The procedure mentioned in subsection,must provide for.
● Monitoring the areas for the potential for the formation of an ERZ; and
● Deciding whether.
● Equipment used in the areas needs explosion protection; and
● Aluminium alloys used in the areas need protection to minimize the risk of explosion.
● The procedure mentioned in subsection.
● Must provide for ongoing risk assessment of the potential for inrush, out-rush and
flooding.

3.3.iii. Under Ground Mining:-

 Major Plan:
An underground mine must have principal hazard management plans that provide for at
the least the following—
● Emergency response;
● Gas management;
● Methane drainage;
● Mine ventilation;
● Spontaneous combustion;
● Strata control.

3.3.iv. Fire prevention and control

The site senior executive must ensure a building or structure located at a surface intake
opening, or in the underground mine, is constructed of a nonflammable material.

3.4. Plant Safety:-

A plant should produce the desired amounts and quality of the final products. Therefore a
control system is needed to ensure that the production level and the purity specifications are
satisfied. The most significant occupational health and safety hazards occur during the
operational phase of a coal processing facility and primarily include the following:
 Process Safety
 Oxygen-Enriched Gas Releases
 Oxygen-Deficient Atmospheres
 Inhalation hazards
 Fire and explosions

3.4.i. Process Safety

Process safety programs should be implemented due to industry-specific characteristics,
including complex chemical reactions, use of hazardous materials (e.g., toxic, reactive,
flammable or explosive compounds), and multi-step reactions. Process safety management
includes the following actions:
Physical hazard testing of materials and reactions;
 Hazard analysis studies to review the process chemistry and engineering practices,
including thermodynamics and Kinetics.
  Examination of preventive maintenance and mechanical integrity of the process
equipment and utilities;
 Worker training; and
 Development of operating instructions and emergency response procedures.
 Oxygen-Enriched Gas Releases
Oxygen-enriched gas may leak from air separation units and create a fire risk due to an
oxygen-enriched atmosphere Oxygen-enriched atmospheres may potentially result in the
saturation of materials, hair, and clothing with oxygen, which may burn vigorously if ignited.
Prevention and control measures to reduce on-site and off-site exposure to oxygen-enriched
atmospheres include:
 Installation of an automatic Emergency Shutdown System that can detect and warn of
the uncontrolled release of oxygen (including the presence of oxygen enriched
atmospheres in working areas7) and initiate shutdown actions thus minimizing the
duration of releases, and elimination of potential ignition sources.
 Design of facilities and components according to applicable industry safety standards,
avoiding the placement of oxygen-carrying piping in confined spaces, using
intrinsically safe electrical installations, and using facility wide oxygen venting
systems that properly consider the potential impact of the vented gas.
 Implementation of hot work and permit-required confined space entry procedures that
specifically take into account the potential release of oxygen.
 Implementation of good housekeeping practices to avoid accumulation of combustible
materials.
 Planning and implementation of emergency preparedness and response plans that
specifically incorporate procedures for managing uncontrolled releases of oxygen.
Provision of appropriate fire prevention and control equipment as described below
(Fire and Explosion Hazards).

3.4.ii. Oxygen Deficit Atmosphere:-

The potential releases and accumulation of nitrogen gas into work areas can result in
asphyxiating conditions due to the displacement of oxygen by these gases. Prevention and
control measures to reduce risks of asphyxiant gas release include:
Design and placement of nitrogen venting systems according to recognized industry
standards; Installation of an automatic Emergency Shutdown System that can detect and warn
of the uncontrolled release of nitrogen (including the presence of oxygen deficient
atmospheres in working areas8), initiate forced ventilation, and minimize the duration of
releases; and Implementation of confined space entry procedures as described in the General
EHS Guidelines with consideration of facility-specific hazards.

3.4.iii. Inhalation Hazards:-

Chemical exposure in coal processing facilities is primarily related to inhalation of
coal dust, coal tar pitch volatiles, carbon monoxide, and other vapors such as methanol and
ammonia. Workers exposed to coal dust may develop lung damage and pulmonary fibrosis.
Exposure to carbon monoxide results in formation of carboxyhemoglobin (COHb), which
inhibits the oxygen-carrying ability of the red blood cells. Mild exposure symptoms may
include headache, dizziness, decreased vigilance, decreased hand-eye coordination,
weakness, confusion, disorientation, lethargy, nausea, and visual disturbances. Greater or
prolonged exposure can cause unconsciousness and death.

3.4.iv. Fire and Explosion Hazards

Coal is susceptible to spontaneous combustion, most commonly due to oxidation of
pyrite or other sulphidic contaminants in coal.9, 10 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
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:
1. Storing coal piles so as to prevent or minimize the likelihood of combustion, including:
 Compacting coal piles to reduce the amount of air within the pile,
 Minimizing coal storage times,
 Avoiding placement of coal piles above heat sources such as steam lines or manholes,
 Constructing coal storage structures with noncombustible materials,
 Designing coal storage structures to minimize the surface areas on which coal dust can
settle and providing dust removal systems, and
 Continuous monitoring for hot spots (ignited coal) using temperature detection systems.
When a hot spot is detected, the ignited coal should be removed.
2. 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;
3. All electrical circuits should be designed for automatic, remote shutdown; and
4. 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 afire.

3.4.iv.i. To Control Fire Hazard:-

Recommended measures to prevent and control fire and explosion risks from process
operations include the following:
 Provide early release detection, such as pressure monitoring of gas and liquid
conveyance systems, in addition to smoke and heat detection for fires;
 Limit potential releases by isolating process operations from large storage inventories;
 Avoid potential ignition sources (e.g., by configuring piping layouts to avoid spills over
high temperature piping, equipment, and / or rotating machines);
 Control the potential effect of fires or explosions by segregating and using separation
distances between process, storage, utility, and safe areas. Safe distances can be derived
from specific safety analyses for the facility, and through application of internationally
recognized fire safety standards.
Limit areas that may be potentially affected by accidental releases by:
 Defining fire zones and equipping them with a drainage system to collect and convey
accidental
releases of flammable liquids to a safe containment.

3.4.iv.ii. Control Explosion Risks

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.
 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 fail-safe 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.

Safety Regulations and Guidelines:-

For indicating safety and health concern some of the performance indication and
monitoring being made for the general coal gasification plants which are based on the
government rules and regulations. Some of the rules are under:

Environmental Monitoring:-
Environmental monitoring activities should be based on direct or indirect indicators of
emissions, effluents, and resource use applicable to the particular project. Monitoring
frequency should be sufficient to provide representative data for the parameter being
monitored. Monitoring should be conducted by trained individuals following monitoring and
record-keeping procedures and using properly calibrated and maintained equipment.
Monitoring data should be analyzed and reviewed at regular intervals and compared with the
operating standards so that any necessary corrective actions can be taken. Additional
guidance on applicable sampling and analytical methods for emissions and effluents is
provided in the General EHS Guidelines.

Emissions and Effluent Guidelines:-

Guideline values for process emissions and effluents in this sector are indicative of good
international industry practice as reflected in relevant standards of countries with recognized
regulatory frameworks. These guidelines are achievable under normal operating conditions in
appropriately designed and operated facilities through the application of pollution prevention
and control techniques.

Energy Consumption, Emission and Waste Generation:-

Industry benchmark values are provided for comparative purposes only and individual
projects should target continual improvement in these areas. Relevant benchmarks for coal
processing plants can be derived from coal gasification for large power plants. Emissions of
gasification plants producing SynGas for Fischer- Tropsch (F-T) synthesis should be
substantially lower, due to the purity requirements of synthesis catalyst.
 Air emission level for coal processing plant

Polutant Units Guidelines

Thermal Dryer Mg/Nm3 70
Particles
Sox Mg/Nm3 150/200
NOx Mg/Nm3 200/400
VOC Mg/Nm3 150
H2S Mg/Nm3 10
Heavy metals Mg/Nm3 1.5
COS+CS2 Mg/Nm3 3
Ammonia Mg/Nm3 30
Table3.1 Air Emission Level of Coal

Effluent level for Coal Processing Plant

Polutant Units Guidelines

Ph Mg/l\ 6-9
BODs Mg/l\ 30
COD Mg/l\ 150
N2 Mg/l\ 10
Phosphorus Mg/l\ 2
Sulphides Mg/l\ 1
Oil & Gress Mg/l\ 10
TSS Mg/l\ 35
Other Matels Mg/l\ 14
Table 3.2 Air Effluent Level of Coal

3.5 Occupational Health and Safety Performance

3.5.i. Occupational Health and Safety Guidelines
Occupational health and safety performance should be evaluated against internationally
published exposure guidelines, of which examples include the Threshold Limit Value
(TLV®) occupational exposure guidelines and Biological Exposure Indices (BEIs®)
published by American Conference of Governmental Industrial Hygienists (ACGIH), the
Pocket Guide to Chemical Hazards published by the United States National Institute for
Occupational Health and Safety (NIOSH), Permissible Exposure Limits (PELs) published by
the Occupational Safety and Health Administration of the United States (OSHA), Indicative
Occupational Exposure Limit Values published by European Union member states, or other
similar sources.
3.5.ii. Accident and Fatality Rates
Projects should try to reduce the number of accidents among project workers (whether
directly employed or subcontracted) to a rate of zero, especially accidents that could result in
lost work time, different levels of disability, or even fatalities. Facility rates may be bench-
marked against the performance of facilities in this sector in developed countries through
consultation with published sources (e.g. US Bureau of Labor Statistics and UK Health and
Safety Executive).

3.5.iii. Occupational Health and Safety Monitoring

The working environment should be monitored for occupational hazards relevant to the
specific project. Monitoring should be designed and implemented by accredited professionals
as part of an occupational health and safety monitoring program. Facilities should also
maintain a record of occupational accidents and diseases and dangerous occurrences and
accidents. Additional guidance on occupational health and safety monitoring programs is
provided in the General EHS Guidelines.
Figure 3.2 Safety Managemnts
 CHAPTER 4
CONCEPTUAL DESIGN ANALYSIS
Gasification is a technological process that converts any carbonaceous (carbon-based) raw
material, such as coal, into fuel gas, also referred to as synthesis gas (syngas for short).
Gasification takes place in a gasifier, which is typically a high temperature/pressure vessel
where oxygen (or air) and steam come into direct contact with the coal or other feed material,
resulting in a sequence of chemical processes that convert the feed to syngas and ash/slag
(mineral residues). Syngas got its name from its use as an intermediary in the manufacturing
of synthetic natural gas. Syngas, which is largely composed of the colourless, odourless,
extremely combustible gases carbon monoxide (CO) and hydrogen (H2), has a wide range of
applications.By adding steam and reacting over a catalyst in a water-gas-shift reactor, the
syngas can be further transformed (or shifted) to nothing but hydrogen and carbon dioxide
(CO2). When hydrogen is consumed, it produces only heat and water, allowing it to generate
electricity with no carbon dioxide in the exhaust gases. Additionally, hydrogen produced
from coal or other solid fuels can be used to refine oil or to manufacture items like ammonia
and fertilizer. Furthermore, hydrogen-enriched syngas can be utilized to produce gasoline and
diesel fuel. Gasification technologies make it possible to build polygeneration facilities that
produce various products. Carbon dioxide can be efficiently absorbed from syngas, avoiding
greenhouse gas emissions to the atmosphere and allowing it to be used.
Why Gasification
Gasification was performed for the following reasons:
 Petroleum resource depletion
 Price increases for oil and natural gas
 Struggle for independence from less stable oil and petrol supplies and shifting costs.
 Interested in reducing greenhouse gas emissions from energy generation Gasification
produces three basic products.
1. Hydrocarbon gases (sometimes known as syngas)
2. Hydrocarbon liquids (oils)
3. Char (carbon black and ash)

Pakistan Requires Coal Gasification

Pakistan can benefit from the following advantages if it uses coal as its primary energy
source.
 Coal resources are plentiful and may be used to generate energy for an extended period
of time; its price is more stable than that of oil and gas.
 It does not require high security or high pressure pipes for transportation and production
to obtain energy from coal reserves.
 The energy derived from coal deposits is not affected by weather conditions.

The Critical Role Of Coal Gasification

The following factors contribute to the importance of coal gasification:
 Environment Clean coal technology utilisation
 Sequestration technology expected Flexibility Advanced technology
 Poor quality feedstock acceptance
 Economics Competitive with alternatives
 Volatility in global oil prices Energy security
 Coal resource size Distribution of resources Reduced reliance on foreign oils and natural
gas

Gasification Background
The Gasification Systems Program and its predecessors were critical in the development of
efficient coal-power systems in the United States. Notable among these were extremely
efficient and low-polluting integrated gasification combined cycle power plants, which were
among the best-performing coal-based facilities of their day when they were built in the late
twentieth century. The Gasification Systems Program has continued to develop coal
gasification and syngas technologies, with transport gasification and warm syngas cleanup
being important examples. However, coal syngas-based power plants and other uses are
struggling in the current market scenario, both domestically and internationally.
To compete with other kinds of electricity generation, future coal-fired facilities will need to
be extremely efficient, flexible, reliable, and ecologically responsible. The inherent benefits
of gasification in terms of efficiency and environmental performance highlight the
significance of the Gasification Systems Program technology development in accomplishing
these goals. Fundamentally, new gasification-based coal plants must be competitive in terms
of efficiency and cost (especially dispatch costs considering the increasing demand for load
following induced by the increasing presence of renewable power assets on the grid). To
compete on a domestic level, new power generation technologies must be adaptable, capable
of cycling quickly and managing numerous fuel types (e.g., coal and natural gas, coal and
biomass).

Gasification Fundamentals
Gasification is a type of partial oxidation. The phrase partial oxidation refers to the use of less
oxygen in gasification than would be necessary for combustion (burning or complete
oxidation) of the same amount of fuel. Gasification typically uses 25 to 0% of the potential
oxidant (either pure oxygen or air) to generate enough heat to gasify the remaining
unoxidized fuel, resulting in syngas. Carbon monoxide (CO) and hydrogen (H2) are the
principal combustible products of gasification, with only a little quantity of carbon entirely
oxidized to carbon dioxide (CO2) and water. The heat produced by partial oxidation provides
the majority of the energy required to break up the chemical bonds in the feedstock, drive
subsequent endothermic gasification reactions, and raise the temperature of the final
gasification products.

4.1 Preliminary Reactor Optimization

Gasification reactions are reversible. The direct reaction and its conversion are subjected to
the constraints of thermodynamic equilibrium and reaction kinetics. The combustion
reactions are:

1) C + 1/2Ο2→CΟ (-111MJ/kmol)

2) CΟ+1/2Ο2→CΟ2 (-283MJ/kmol)

3) Η2+1/2Ο2→Η2Ο (-22MJ/kmol)

Essentially go to completion (to the right). The thermodynamic equilibrium of the

gasification reactions are relatively well defined and collectively impose a strong
influence on the thermal efficiency and the produced syngas composition of a
gasification process

7) CΟ +Η2Ο⟷ CΟ2+Η2 “Water gas shift reaction”(-1MJ/kmol)

8) CΗ4+Η2Ο⟷ CΟ2+Η2 “Steam methane reformingr eaction”(+20MJ/kmol)

4.2. The Impact of Temperature
 The temperature is normally chosen based on the ash characteristics (i.e. below the
softening point of the ash for fluidized bed and dry ash for moving bed gasifiers and
above the melting point for slagging gasifiers).
 A high temperature and a significant amount of steam in excess of the stoichiometric
requirement are necessary to produce a syngas with a low methane content.
 High-temperature gasification, on the other hand, will increase oxygen consumption and
reduce overall process efficiency.

4.2.i. Pressure Effect

All current processes work at pressures of at least 10 bars and up to 100 bars.
The reasons for pressurized gasification are as follows:
 Compression energy savings Equipment size reduction
 Gasification involves a number of reactions, some of which are exothermic and some of
which are endothermic. Because of thermodynamic limits, the reaction of the fuel with
oxygen is always complete and exothermic, whereas the reaction with steam or carbon
dioxide is always endothermic and never complete.
 Steam at 300-00°C is the most commonly utilized moderator in the gasification process.
 This superheat is required at pressures exceeding 0 bar; otherwise, the steam becomes
moist during expansion.
 There are many advantages to performing gasification under pressure. The syngas
composition changes very little as a function of operating pressure at a typical entrained
flow gasifier operation temperature of 2,600°F (1,500°C) (Higman, 2008), but significant
reductions in compression energy and cost reduction can be gained by using smaller
equipment.
The kinetic behavior of the gasification process is more complex than the thermodynamic
understanding. There is very little trustworthy kinetic information on coal gasification
processes, partially because it is extremely dependent on process settings and the nature of
the coal feed, which can vary greatly in terms of composition, mineral impurities, and
reactivity. In reality, some impurities have been shown to have catalytic activity in some
gasification reactions.

4.2.ii. Process screening

 The composition of syngas can vary significantly depending on the feedstock and the
gasification process involved; however typically syngas is 30 to 0% carbon monoxide (CO),
25 to 30% hydrogen (H2), 0 to 5% methane (CH), 5 to 15% carbon dioxide (CO2), plus a
lesser or greater amount of water vapor, smaller amounts of the sulfur compounds hydrogen
sulfide (H2S), carbonyl sulfide (COS), and finally some ammonia and other trace
contaminants.
The composition of syngas is an important topic to explore because the composition and
impurities required vary depending on the final usage of the syngas. The table below shows
the widely varying characteristics desirable for the main uses of syngas, which include use as
fuel gas to fire boilers or turbines in power cycles, use of syngas as feedstock for the
production of synthetic fuels such as gasoline, use as feedstock for methanol synthesis, and
use as feedstock for hydrogen production.

Product Syntheticgas Methanol Hydrogen

Fuel gas
It is
Boiler turbine

H2/CO ~0. ~2.0 high Unimportant unimportant

Carbondioxide low low - Notecritical Notecritical

hydrocarbons low low low High High

Nitrogen low low low Note note

Watervapor low low high Low note

contaminants <1ppm <1ppmsulphur <1ppm Note Low part

sulphur sulphur
Lowmetals

Heatingvalue unimportant unimportant unimportant High high

dependent on the type of catalyst. For iron catalysts, the value indicated is adequate; for
cobalt catalysts, a number close to 2.0 should be utilized.
 To convert CO to H2, water gas shift must be employed; carbon dioxide (CO2) in syngas
can be eliminated at the same time as CO2 produced by the water gas shift reaction.
 Some CO2 can be tolerated if the H2/CO ratio is more than 2.0 (as can occur during
natural gas steam reforming); if adequate H2 is available, the CO2 will be transformed to
methanol.
 Methane and heavier hydrocarbons must be recycled in order to be converted to syngas,
which represents a system inefficiency.
 Nitrogen (N2) reduces heating value, but the level is immaterial as long as turbine or
boiler system efficiencies are enough. Therefore, the presence of extra N2 may be
problematic in carbon capture settings.
 The water gas shift reaction necessitates the presence of water.
 Can withstand relatively high water levels; steam is occasionally injected to reduce
combustion temperature to control the generation of nitrogen oxides (NOX).
 As long as the H2/CO and contaminants limits are met, the heating value is unimportant.
 As heating value increases, efficiency improves.
 This is dependent on the type of catalyst; iron catalysts often work at greater
temperatures than cobalt catalysts.
 Minimum levels of pollutants can be tolerated

4.2.iii. Economic Evaluation

According to the exergoeconomic analysis, air-steam coal gasification has the lowest syngas
unit cost of 0.5 $/kg for the two-step process, while biomass gasification with air-steam agent
has the lowest syngas unit cost of 0.5 $/kg for the single-step method.
Syngas, also known as synthesis gas, is a fuel gas that contains carbon monoxide, hydrogen,
carbon dioxide, and trace gases. It is created by gasifying a carbon-containing fuel, such as
coal, in a closed environment with heat, air, and water. Because syngas has more than half the
energy density of natural gas, it can be easily burned and utilized as a fuel. It contains a lot of
carbon and is often utilized to make Synthetic Natural Gas (SNG), oxo-chemicals, dimethyl
ether, hydrogen, ammonia, and methanol for industrial purposes. It is also used to make
fertilizers, solvents, fuels, and synthetic materials.
One of the primary aspects driving market expansion is rising demand for syngas from the
chemical industry. Additionally, syngas is generally utilized to make SNG, which is used in
the rail, marine, and road transportation industries as Liquified Natural Gas (LNG) and
Compressed Natural Gas (CNG). Because of benefits such as lower energy prices, improved
stability and predictability, it can also be utilized to feed gas engines for power supply.
Furthermore, the advancement of the underground coal gasification (UCG) method is
enhancing the market's outlook. It speeds up the completion of the in-situ gasification
process, which turns coal into syngas.
This is accelerating market growth since it eliminates the need to transport feedstock to
gasification units, resulting in significant cost savings. Furthermore, rising environmental
consciousness and tight government laws governing the use of clean fuels are driving market
expansion. Syngas is critical in minimizing landfill waste pollution and greenhouse gas
emissions.
The global syngas market is expected to grow at a CAGR of around .% during 2022-2028.

4.3. Process Flowsheeting

4.3.i. Process Flow Diagram

Figure 4.1 Process Flow Diagram

Oxygen Supply
The air separation unit (ASU) uses cryogenic air separation to separate ambient air
into gaseous oxygen and gaseous nitrogen streams. Gasification process requires a
compressed oxygen feed to the gasifier.
Gasification
Preheating of coal feed at 400k is done in preheater installed prior to gasifier. The
gasifier selected is a fluidized bed type gasifier commercially named as Winkler
gasifier. Powdered coal is injected in the gasifier from bottom
4.3.ii. Plant layout
Figure 4.2 Plant Layout
4.4. Material Balance:-
Stream S1
Description Feed Inlet
Temperature 298 K
Pressure 24.13 Bar
Components Mass (TPD) Mass%
Carbon 0 0
Hydrogen 2.3 0.5%
Nitrogen 364.2 78%
Oxygen 98.1 21%
Sulphur 0 0
Ash 0 0
Total 1000 100

Stream S2
Description Fresh Air
Temperature 298 K
Pressure 1 Bar
Components Mass (TPD) Mass%
Carbon 0 0
Hydrogen 2.3 0.5
Nitrogen 364 78
Oxygen 98.1 21
Sulphur 0 0
Ash 0 0
Total 464.6 100
Stream S3
Description Water Inlet
Temperature 298 K
Pressure 1 Bar
Components Mass (TPD) Mass%
Carbon 0 0
Hydrogen 0 0
Nitrogen 0 0
Oxygen 0 0
Sulphur 0 0
Ash 0 0
Water 262.79 100
Total 262.79 100

Stream S4
Description Feed after treatment
Temperature 400 K
Pressure 24.13 Bar
Components Mass (TPD) Mass%
Carbon 628.1 62.81
Hydrogen 56.5 5.61
Nitrogen 10.6 1.06
Oxygen 175.4 17.54
Sulphur 39.2 3.92
 Ash 92 92
Water 0 0
Total 1000 100

Stream S5 (A)
Description Grinder to reactor 1
Temperature 400 K
Pressure 24.13 Bar
Components Mass (TPD) Mass%
Carbon 314.05 62.81
Hydrogen 28.25 5.61
Nitrogen 5.3 1.06
Oxygen 87.7 17.54
Sulphur 19.6 3.92
Ash 46 92
Water 0 0
Total 500 100
.
Stream S5 (B)
Description Grinder to reactor 2
Temperature 400 K
Pressure 24.13 Bar
Components Mass (TPD) Mass%
Carbon 314.05 62.81
Hydrogen 28.25 5.61
Nitrogen 5.3 1.06
Oxygen 87.7 17.54
Sulphur 19.6 3.92
Ash 46 92
Water 0 0
Total 500 100

Stream S6
Description Steam Distribution
Temperature 775 K
Pressure 1 Bar
Components Mass (TPD) Mass%
Carbon 0 0
Hydrogen 0 0
Nitrogen 0 0
Oxygen 0 0
Sulphur 0 0
Ash 0 0
Water 262.79 100
Total 262.79 100

Stream S7
Description Oxygen & Nitrogen Through Air Separation
Temperature 298 K
Pressure 5 Bar
Components Mass (TPD) Mass%
Carbon 0 0
Hydrogen 0 0
Nitrogen 23.3 5
Oxygen 443.81 95
Sulphur 0 0
Ash 0 0
Water 0 0
Total 467.1 100

Stream S8
Description Reactor 1 outlet
Temperature 1073 K
Pressure 27 Bar
Components Mass (TPD) Mass%
CO 484.7 62.81
CO2 202.335 26.1
H2 37.2 4.82
H2S 16.4 2.12
N2 4.4 0.57
Ash 26.505 3.4
Water 0 0
 Total 771.575 100
.
Stream S9
Description Reactor 2 outlet
Temperature 1073 K
Pressure 27 Bar
Components Mass (TPD) Mass%
CO 484.7 62.81
CO2 202.335 26.1
H2 37.2 4.82
H2S 16.4 2.12
N2 4.4 0.57
Ash 26.505 3.4
Water 0 0
Total 771.575 100

Stream S10
Description Ash
Temperature 1073 K
Pressure 27 Bar
Components Mass (TPD) Mass%
CO 0 0
CO2 0 0
H2 0 0
H2S 0 0
N2 0 0
Ash 22.65 100
Water 0 0
Total 22.65 100

Stream S11
Description Cyclone Separator gas
Temperature 1073 K
Pressure 27 Bar
Components Mass (TPD) Mass%
CO 941.01 62.81
CO2 52.8 26.1
H2 1.79 4.82
H2S 0.34 2.12
N2 0.025 0.57
Ash 0.90 3.4
Water 0 0
Total 996.86 100

Stream S12
Description Ash from cyclone separator
Temperature 1073 K
Pressure 27 Bar
Components Mass (TPD) Mass%
CO 0 0

CO2 0 0

H2 0 0

H2S 0 0

N2 0 0

Ash 1.87 100

Water 0 0
Total 1.87 100

Stream S13
Description Heat exchanger to scrubber
Temperature 393 K
Pressure 1 Bar
Components Mass (TPD) Mass%
CO 941.01 62.81
CO2 391.97 26.1
H2 72.21 4.82
H2S 31.75 2.12
N2 8.53 0.57
Ash 50.932 3.4
Water 0 0
Total 1498.2 100

Stream S14
Description Scrubber to Absorption Column
Temperature 368 K
Pressure 1 Bar
Components Mass (TPD) Mass%
CO 941.01 62.81
CO2 391.97 22.1
H2 1.79 4.82
H2S 0.34 2.12
N2 0.025 0.57
Water 50.06 4.18
Ash 0.90 3.4
Total 1437.50 100

Stream S15
Description Absorption Column to Compressor
Temperature 358 K
Pressure 1 Bar
Components Mass (TPD) Mass%
CO 941.01 62.81
CO2 391.97 26.1
H2 72.21 4.82
H2S 31.75 2.12
N2 8.53 0.57
Water 0 0
Ash 50.932 3.4
Total 1498.2 100
Stream S16
Description Toxic gas removal
Temperature 358 K
Pressure 1 Bar
Components Mass (TPD) Mass%
CO 0 0
CO2 0 0
H2 0 0
H2S 31.17 100
N2 0 0
Water 0 0
Ash 0 0
Total 31.17 100

Stream S17
Description Pure liquefier
Temperature 358 K
Pressure 1 Bar
Components Mass (TPD) Mass%
CO 941.01 93
CO2 0 0
H2 72.21 7
H2S 0 0
N2 0 0
Water 0 0
Ash 0 0
Total 1023.02 100
 Stream S18
Description Water Extraction
Temperature 358 K
Pressure 1 Bar
Components Mass (TPD) Mass%
CO 0 0
CO2 0 0
H2 0 0
H2S 0 0
N2 0 0
Water 50 100
Ash 0 0
Total 50 100

4.5. Energy Balance

F3=19465.6kg/hr
Steam=100%
F2=10949.49kg/hr
Water=100%

F5=64298.035kg/hr
F1=34855 kg/hr Gasifier
C=62.81%
F4=944.01kg/hr
Ash
 4.5.i. Energy entering in gasifier from coal:
Q=mCp∆T

Feed Cp ∆T (K) ∆H (KJ/kghr)

Coal 1.45 400-298 2579745.7

Oxygen 0.941 400-298 934173.6

Steam 1.901 400-298 86969851.5

Total entering in both gasifiers= 180967542.6 KJ/kghr

4.5.ii. Energy leaving from gasifier:

Feed Cp ∆T (K) ∆H (KJ/kghr)

CO 1.25 775 98984368.3

H2 15.3 1073-298 18386239.5

CO2 1.26 1073-298 833632692.2

N2 1.18 1073-298 169045.3

H2S 1.36 1073-298 1113586.5

Ash 0.514 1073-298 438720.7

Total leaving from both gasifiers= 405493206.4

Qout-Qin=224525663 KJ/kghr
4.5.iii. Heat Exchanger
Component Cp ∆T(K) ∆H (KJ/kghr)

CO 1.25 775 197968736.7

H2 15.3 775 36772479

CO2 1.26 775 167265385.8

N2 1.18 775 338090.65

H2S 1.36 775 2271072.692

Ash 0.514 775 147269.995

Total Entering: 405493206.4 KJ/kghr

4.5.iv. Leaving From Heat Exchanger

Component Cp ∆T(K) ∆H (KJ/kghr)

CO 1.047 393-298 163479579.4

H2 14.47 393-298 4283064.5

CO2 0.933 393-298 152471831.4

N2 1.043 393-298 36631.72

H2S 1.042 393-298 1028106.06

Ash 0.47 393-298 14752.51

Total leaving: 321293965.7 KJ/kghr

4.5.v. Entering into Scrubber:

Component Cp ∆T(K) ∆H (KJ/kghr)

CO 1.047 393-298 163479579.4

H2 14.47 393-298 4283064.5

CO2 0.933 393-298 152471831.4

N2 1.043 393-298 36631.72

H2S 1.042 393-298 1028106.06

Ash 0.47 393-298 14752.51

Total entering: 321293965.7 KJ/kghr

Leaving:

Component Cp ∆T(K) ∆H (KJ/kghr)

CO 1.042 368-298 162408086.5

H2 14.45 368-298 3137297.96

CO2 0.91 368-298 129095006.3

N2 1.042 368-298 26965.91

H2S 1.032 368-298 928525.71

Total leaving: 295595882KJ/kghr

4.5.vi.Entering into Absorption Column

Component Cp ∆T(K) ∆H (KJ/kghr)

CO 1.042 368-298 162408086.5

H2 14.45 368-298 3137297.96

CO2 0.91 368-298 129095006.3

 N2 1.042 368-298 26965.91

H2S 1.032 368-298 928525.71

Total entering: 295595882KJ/kghr

Total Leaving:

Component Cp ∆T(K) ∆H (KJ/kghr)

CO 1.044 358-298 161991952.8

H2 14.44 358-298 2686879.6

CO2 0.899 358-298 128953115.9

N2 1.02 358-298 23173.6

H2S 1.041 358-298 909756.6

Total leaving: 294564877.2 KJ/kghr

CHAPTER 5
HEAT INTEGRATION AND PROCESS FLOW
Heat integration is essentially a way of developing heat recovery networks from within the
process flow diagram by introducing heat exchangers. This allows heat to be exchanged
between hot and cold streams already present in the process, thus reducing complete reliance
on external utilities and hence the cost. (ref pinch analysis book..)The software HINT is used
to configure the heat integration network design by the
pinch analysis technique. Streams that are found to be compatible with one another i.e. where
heat exchange is possible are given in Table x, and the process flow diagram after heat
integration and in accordance to the results obtained by HINT.
Streams

Hot Cold

S1 S3

S11 S13

A Heat Exchanger will operate between stream 11 and 13 and the cold & hot utility will be
used in stream 1 and stream 3 respectively.

Process Flow Diagram After Heat Integration

Figure 5.1 Process Flow Diagram After Heat Integration

 Chapter 6
Instrumentation and Process Control

6.1 Instrumentation

Instrumentation is carried out to monitor the key process variables during plant
operation and instruments may be incorporated in automatic control loops or used for
the manual monitoring of the process operation. Industry pursuit of increasingly
stringent process control and safety requirements led to an early adaptation of
computational techniques in this field. Today, a wide range of computing devices,
ranging from embedded microprocessors to dedicated computers, is commonly
employed throughout the industry. This class explores the technical foundations of
process and control instrumentation in use, and covers the practical aspects of its
deployment and control.

Measurements
1. Pressure
2. Flow
3. Temperature
4. Level
5. Density
6. Viscosity
7. Radiation
8. Frequency
9. Current
10. Voltage
11. Inductance
12. Capacitance
13. Resistivity

6.2. Control
In addition to measuring field parameters, instrumentation is also responsible for providing
the ability to modify some field parameters to keep the process variables at a desired value.
6.3. Incentives for Chemical Process Control
A chemical plant is an arrangement of processing units (reactor, heat exchanger, pumps,
distillation columns, absorbers, evaporators, tanks etc.), integrated with one another in a
systematic and rational manner. The plants overall objective is to convert certain raw
materials into desired products using available sources of energy, in the most economical
way. In its operation, a chemical plant must satisfy several requirements imposed by its
designers and the general technical, economic and social conditions in the presence of ever-
changing external
influences (disturbances). Among such requirements are the following.
6.3.i. Safety
The safe operation of a chemical process is a primary requirement for the well-being of the
people in the plant and for its continued contribution to the economic development.
6.3.ii. Production Specification
A plant should produce the desired amounts and quality of the final products. Therefore a
control system is needed to ensure that the production level and the purity specifications are
satisfied.
6.3.iii. Environmental regulations
Various federal and state laws may specify that the temperature, concentrations of chemicals,
and flow rates of the effluents from a plant be within certain limits.
6.3.iv. Operational Constraints
The various types of equipment’s used in a chemical plant have constraints inherited to their
operation. Such constraints should be satisfied throughout the operation of the plant .e.g.
pumps must maintain a certain net positive suction head etc.
6.3.v. Economics
The operation of a plant must conform to the market conditions, that is, the availability of the
raw materials and the demand of the final products. Furthermore, it should be as economical
as possible in its utilization of raw materials, energy, and capacity and human labor. Thus it is
required that the operating conditions are controlled at given optimum levels of minimum
operating cost, maximum profit and so on.
6.4. Elements of Control System
In almost every control configuration, we can distinguish the following hardware elements.
i. The chemical process
ii. Measuring element or sensors
iii. Transducers
iv. Transmission line
v. Controllers
vi. The final control element
6.4.i. The Chemical Process
It represents the material equipment together with physical or chemical operations that occur
to convert raw materials into valuable end products.
6.4.ii. Measuring Instruments or the Sensor
Such instruments are used to measure the disturbances, the controlled output variables, the
necessary secondary output variables and are the main sources of information about what is
going on in the process. The measuring means depend upon the types of variable, which is to
be measured, and these variables must be recorded also. Following are some typical sensors,
which are used for different variables measurements.
  Pressure sensors
  Temperature sensors
  Flow rate sensors
  Level sensors
 Thermocouples or resistance thermometers for measuring the temperature, also used for
severe purpose some radiation detectors may also be used.
 Venturi meters also flow nozzles for flow measurements.
 Gas chromatograph for measuring the composition of the stream,
A good device for the measurement depends upon the environment in which it is to be used.
Like a thermometer, it is not, a good measuring device, as its signal is not rapidly
transmitted. So signal transmission is very important in selecting the measuring device.
Some measuring device must be ragged and reliable for industrial environment.
6.4.iii. Transducers
Many measurements can’t be used for control quantities such as electric voltage and current a
pneumatic signal. For example, a stream gauges are metallic conductors whose resistance
changes when mechanical strain is imposed on it. Thus they can be used to convert a
mechanical signal to electric one.
6.4.iv. Transmission lines
These are used to carry measurements signal from measuring device to the controller. In the
past, mostly transmission lines were pneumatic nature that they are using the compressed air
or liquid to transmit the signal but with the automation of industry and advent of electronic
controllers, electric lines have over-ruled the pneumatic operations. Many times the
measurements coming from a device are very weak and these must be amplified to get the
things right. So it is very often to find amplifies in the transmission lines to the controller. For
example the output of a thermocouple is only a few milli-volts so they must be amplified to
few volts to get the controller.
6.4.v. Controller
This is the hardware element that has “intelligence”. It receives the information from the
measuring device and decides what action must be carried out. The older controllers were of
limited intelligence, could perform very limited and simple operations and could implement
very simple control laws. The use of digital computers in this field has increased the use of
complicated control laws.
6.4.vi. Final Control Element
This is the hardware element that implements the decision taken by the controller. For
example, if the controller decides that flow rate of the outlet stream should be increased or
decreased in order to keep the level of liquid in a tank then the final control element which is
a control valve in this case implements the decision by slightly opening or closing the valve.
6.5. Modes of Control
There are various modes in which the process can be controlled. The different modes depend
upon the types of controllers and the action it takes to control any process variable .Actually
the controller action is dependent on the output signal of the transmitter (sensor with
transducer). This signal is compared with the set point to the controller and the error between
these two is used to control the process. Different controllers react in different manner to
control this off-set between the controlled variable and the set point.
6.5.i. Different types of Control Actions
On the prescribed basis, following are the different types of control actions:
  On-off control
  Proportional control
  Integral control
  Rate or derivative control
  Composite control
6.5.ii. Composite control modes
Also there are combined actions of different types of controllers. Actually in different
operations, it is very rare that only one of the above control actions is found but a composite
control action is more often practice. Following are typical composite control mode, which
are usually used:
  Proportional-Integral controller (Pl-controller)
  Proportional-Derivative controller (PD-controller)
  Proportional-Integral-Derivative controller (PID-controller)
In general the process controllers can be classified as:
  Pneumatic controllers
  Electronic controllers
  Hydraulic controllers
While dealing with the gases, the controller and the final control element may be
pneumatically operated due to the following reasons.
Pneumatic controller is very rugged and almost free of maintenance. The maintenance men
don’t have sufficient training and background in electronics, so pneumatic equipment is
simple.
Pneumatic controller appeals to be safer in a potentially explosive atmosphere which is often
present in the industry.
Transmissions distances are short pneumatic and electronic transmissions system are
generally equal up to about 200 to 300 feet. Above this distance electronic system beings to
offer savings.
6.6 Selection of Controller
Actually in industry, only P, PI and PID control modes are the usual practice. The selection
of most appropriate type of controller for any particular environment is a very systematic
procedure. There are many ways and means that how a particular type of system may be
controlled through which type of controller. Usually type of controller is selected using only
quantitative considerations stemming from the analysis of the system and ending at the
properties of that particular controller and the control objective. Proportional, Integral and
Derivative control modes also affect the response of the system. Following is the summarized
criterion to select the appropriate controller for any process depending upon the detailed
study of the controller and control variable along with process severity.
i. If possible, use a simple proportional controller:
Simple P-controller can be used if we can achieve acceptable off-set with not too high values
of gain. So for a gas pressure and liquid level control, usually a simple proportional controller
may
be used.
ii. If a simple P-controller is not acceptable, use PI-controller:
A steady-stat error always remains proportional controller so in systems where this off-set is
to be minimized, a PI-controller is incorporated. So in flow control applications, usually PI-
controller is found.
iii. Use PID controller to increase the speed of the closed loop response and retain
robustness:
The anticipatory characteristic of the derivative control enables to use somewhat higher
values of proportional gains so that off-set is minimized with lesser deviations and good
response of the system. Also it adds the stability to the system. So this type of control is used
for sluggish multi capacity processes like to control temperature and composition. In short
best controller is selected on following basis;
1. Severity of process
2. Accuracy required
3. Cost
6.7 Control Loops
For instrumentation and control of different sections and equipment’s of plants, following
control loops are most often used.
1. Feed backward control loop
2. Feed forward control loop
3. Ratio control loop
4. Auctioneering control loop
5. Split range control loop
6. Cascade control loop
6.7.i. Feed Back Control Loop
Feedback is a mechanism, process or signal that is looped back to control a system within
itself. Such a loop is called a feedback loop. Intuitively many systems have an obvious input
and output; feeding back part of the output so as to increase the input is positive feedback;
feeding back part of the output in such a way as to partially oppose the input is negative
feedback.
6.7.ii. Feed Forward Control Loop
“A method of control in which the value of a disturbance is measured, and action is taken to
prevent the disturbance by changing the value of a process variable”. This is a control method
designed to prevent errors from occurring in a process variable. This control system is better
than feedback control because it anticipates the change in the process variable before it enters
the process takes the preventive action. While in feedback enter system action is taken after
the change has occurred.
In more general terms, a control system has input from an external signal source and output
to an external load; this defines a natural sense (or direction) or path of propagation of signal;
the feed forward sense or path describes the signal propagation from input to output;
feedback describes the signal propagation in the reverse sense. When the sample of the output
of the system is fed back, in the reverse sense, by a distinct feedback path into the interior of
the system, to contribute to the input of one of its internal feed forward
components,especially an active device or substance that is consumed in an irreversible
reaction; it is called “feedback”.
The propagation of the signal around the feedback loop takes a finite time because it is
casual. Its disadvantage lies in the operational procedure. For example if a certain quantity is
entering in the process, then a monitor will be there at the process to note its value. Any
changes from the set point will be sent to the final control element through the controller so
that to adjust the incoming quantity according to desired value (set point). But in fact changes
have already occurred and only corrective action can be taken while using feedback-control
system.
6.7.iii. Ratio Control
A control loop in which, the controlling element maintains a predetermined ratio of one
variable to another. Usually this control loop is attached to such a system where two different
streams enter a vessel for reaction that may be of any kind. To maintain the stoichiometric
quantities of different streams this loop is used so that to ensure proper process going on in
the process vessel.
6.7.iv. Auctioneering Control Loop
This type of control loop is normally used for a huge vessel where, readings of a single
variable may be different at different locations. This type of control loop ensures safe
operation because it employs all the readings of different locations simultaneously, and
compares them with the set point, if any of those readings is deviating from the set point then
the controller sends appropriate signal to final control element.
6.7.v. Split Range Loop
In this loop controller is per set with different values corresponding to different actions to be
taken at different conditions. The advantage of this loop is to maintain the proper conditions
and avoid abnormalities at very differential levels.
6.7.vi. Cascade Control Loop
This is a control in which two or more control loops are arranged so that the output of one
controlling element adjusts the set point of another controlling element. This control loop is
used where proper and quick control is difficult by simple feed forward or feed backward
control. Normally first loop is feedback control loop. We have selected a cascade control loop
for our heat exchanger in order to get quick on proper control.
6.8. Control loop around gasifier
The chief reactions taking place in the gasifier are exothermic. Therefore a large amount of
heat is liberated. Although the heat evolved catalysis the other reaction but if the temperature
is not controlled, it may lead to ash fusion temperature. So an auctionary control loop is used
to control temperature inside the reactor. Temperature is controlled through flow rate of
cooling water flowing in the cooling tubes and the oxidant. So as the gasifier temperature is
raised above the set point cooling water flow rate is increased and oxidant flow rate is
reduced simultaneously. The pressure inside the gasifier also need to be carefully controlled
therefore a control loop is installed on the syngas outlet. The pressure in the Gasifier is
maintained by controlling the flow rate of exiting syngas. The Flow rate of transport gas is
also controlled to maintain the pneumatic
conveying of feed coal.
6.9. Control loop around Waste Heat Boiler:
Usually, the steam pressure in a boiler is controlled through the use of a pressure control loop
on the discharge line. At the same time the water level in the boiler should not fall below a
lower limit which is necessary to keep the heating coil immersed in water and thus prevent its
burning out. According to this system, whenever the liquid level falls below the allowable
limit, the LSS switches the control action from pressure control to level control and closes the
valve on the discharge line. The syngas outlet temperature is also maintained so we have
installed a cascade control loop which measures the temperature of BFW entering into the
waste heat boiler and the temperature of syngas exiting from the boiler. The manipulated
variable is the flow rate of entering Boiler feed water.
6.10. Control Loop around Compressor
The discharge of a compressor is controlled with a flow control system. To prevent the
discharge pressure from exceeding an upper limit, an override control with a high switch
selector (HSS) is introduced. It transfers control action from the flow control to the Pressure
control loop whenever the discharge pressure exceeds the upper limit. Notice the flow control
or pressure control is actually cascaded to the speed control of the compressor motor. The
scheme is shown in Figure 7-3
7.11. Control Loop around Absorption Column
The two most important variables that need to be controlled for proper operation of
Absorption column is the flow rate of solvent and the column pressure. Column pressure is
controlled by using a simple control loop on the exiting pure syngas which controls the flow
rate of syngas. Now the flow rate of selexol solvent depends on two variables, the flow rate
of entering sour syngas and quantity of H2S in it. So we have installed a cascade control loop
which includes a composition sensor that measures the quantity of H2S and other gases in the
exiting syngas and the flow rate of syngas is also measured. The controller than maintains the
flow rate of solvent required for the removal of sour gases.

Figure 6.1 Control loop around Gasifier

Figure 6.2 Control loop on Heat Exchanger

Figure 6.3 Control on Compressor

PnID
Table 6.4 Process & Instrumentation Diagram
 CHAPTER 7

PROCESS EQUIPMENT DESIGN

7.1 Gasifier Design

Particesize=0.002m
Density=800Kg/m3
Density of syn gas =0.95 kg/m3

Density of fluidizing media=1.015 kg/m3

Gravitational accerlation=g=9.8m/s
Mass flowrate of steam= 34855 kg/hr
Mass flowrate of oxygen=6118.82 kg/hr
Viscosity of fluidizing media =0.000028N/m2s

Total flowrate= 40974.829

Flowrate entering in one gasifier= 20486.9
Total density of syngas & fluidizing media= 1.965

Q0 = Total flowrate/Total Density

= 20486.9/1.965*3600
= 2.9 m3/s

Minimum Fluidization velocity:

Archimedes no =ρf(ρp-ρf)gdp3/µ2

Ar=1.015(800-1.015)9.8(0.002)^3/(0.00028)^2

=81096.977

Remf = [C12+C2Ar]0.5 - C1

Where C1=27.2 & C2=0.0408

Remf = [27.2+0.0408(81096.977)]0.5 - 27.2

Remf=36.42
Remf=Umfdpρf/µ

Umf =Remf µ/dpρf

=36.42*0.000028/0.002*1.015

Miinimum fluidization velocity=0.50246m/s

Calculation of transport velocity

Retr=1.41Ar^0.483
Retr=331.335
Retr=Utrdpρf/µ
Utr=4.570149
Minimum bubbling velocity
Umb/Umf=41250 µ0.9 ρf 0.1 (ρp-ρf)gdp Umb/Umf =0.1058m/s
Porosity at minimum fluidization

1-Emf / ɸs2Emf3= 11

Shape factor for coal=ɸs=0.7

Porosity at minimum fluidization=Emf=0.46

Actual flowrate is 3-5 times the minimum flowrate required for fluidization:

We selected 4
Now,
Q0 = 4Qmf
Qmf = Q0 /4 = 2.9/4 =

0.725

D= Qmf * 4 / Umf* 3.14

= 0.725*4/

0.050246*3.14 = 1.36 m

Assume

L=3D = 4.08 m

Area= Qmf / Umf =

0.725/0.50246

=1.4429 m2
 Volume= 3.14/4 * D2 *

= 0.785*1.362 *

4.08

=5.925m3

Height of bed at minimum fluidization

Hm(1

-Em)= Hmf(

Emf)

Emf=

=0.2

Hmf=0.606

593

Height of bed H

(H-Hmf)/

Hmf =

(U-Umf)/

Umb

Assume

U(m/s) =

0.9

H=2.884063

815m

Porosity of bed at fluidization

H/Hmf =(1-Emf)(1-Ef)
Ef =0.88642397

Transport disengagement height (TDH)

TDH/dt=3.8m
Height
of
Zone
HG=H
+TDH
HG=2.
88+4=6
.88m

Pressure drop
Ϫpb=ρp(1-Emf)Hmf*g
Pressure drop due to bed =2568.07 Pa

7.2 Heat Exchanger Design

Q=mCp∆T
Q= 2392KW
Log mean temperature difference:

=193.8 0C
Temperature correction factor:
Ft= 0.75
Tln= 145.35
U= 40 W/m2 0C
Provisional area;

= 41.1m2
Outside diameter=20mm
Inside diameter=16mm
Length of tube=5m
 length of tube allowing tube sheet thickness= 4.95m
Area of tube:

=0.3831m2
Number of Tubes:
Number of tubes can be calculated by using the following formula:

Number of tubes were calculated to be 107.2, hence, 110 was estimated to be the total
number of tubes.
Tubes per pass were calculated as:
110/2=55
Bundle dia and clearance
Bundle diameter was calculated by using the following formula:

Bundle dia was calculated to be 315.13mm

Bundle diameter clearance= 53mm
Shell diameter= 315.13+53
=368.13
Tube Side Coefficient
Mean Temperature = 460°C
Tube Cross-Sectional Area=

=200.96m2
Total Flow Area (At)
 =0.010052m2
Reynold’s number=6838.5
Prandtl number= 9.97
L/di= 309.375
jh= 00.0029
Using the following formula:

hi= 775.5 W/m2 0C

Shell Side Coefficient
Baffle Spacing:
Ib=Ds/4
=92.03mm
Tube Pitch (pt)
=1.25 x o.d
=25mm
Cross Flow Area (As)

=0.0974m2

Shell Side Coefficient

Mass Velocity (Gs) = m/As
=148.32kg/sm2
Equivalent Diameter (de)

=20.17mm
Mean Shell Side Temperature = 240°C
Reynold Number = 77317.68
Prandtl number = 1.6
Baffle spacing = 25%
jh=0.0012
hs=249.08W/m2 0C
Overall Heat Transfer Coefficient
Using the following formula:

Uo was calculated to be = 36.59 W/m2 0 C

Pressure Drop
Pressure Drop – Tube Side

From Fig. 12.24, jf = 0.0029

∆Pt=19209.9N/m2
Pressure Drop- Shell Side

From Fig. 12.30, jf = 0.0012

∆Ps = 867.07 N/m2

7.4 Absorption Column:

Flow Parameters of Absorption Column

Flow Rate of syn gas in the column= 59896.16 kg/hr
Flow Rate of syn gas exit the column = 58597 kg/hr
Flow Rate of selexol solvent in the column = 21969.25 kg/hr
Flow Rate of selexol solvent exit the column= 23268 kg/hr
Temperature of gas in = 368k
Temperature of gas out = 358k
Temperature of selexol in = 368k
Temperature of selexol out = 363k
ρv = PM/ RT
ρv = 0.5393KG/m3
Viscosity of gas =μ = 4.09*10-3 Ns/m2
Heat capacity of gas=cp (gas) =1.942Kj/Kg C
Density of selexol (95 oC) = ρL =1030kg/m3
Viscosity of selexol =μL =0.0058 Ns/m2
Heat capacity of Liquid=cp (liquid) = 2.05Kj/Kg
Molecular weight of selexol = ML =280kg/kmol
Molecular weight of gas = Mv =136kg/kmol

Packing Specification
From table 11.2 Coulson Richard vol #6
Packing type = Intalox Saddle Ceramics
Packing size = dp = 1.5in =38mm
Packing factor = Fp =170
Flv = LW /Vw (ρv / ρl)1/2
Flv = 0.0482
From table 11.44 vol#6
K4 =1.45
Design for pressure drop of 42 mm of water per meter of packing
Percentage flooding =59.45%
Column Diameter
For Vapour density:
μv = (-0.171lt2 + 0.27lt -0.047)[ρl - ρv / ρv]1/2
lt = 0.9m
ρv = 0.5393kg/m3
ρl = 1030kg/m3
μv = 2.51
DC = [ 4*Vw/Л ρv μv ]1/2
Vw= [k4 ρv (ρl - ρv )/13.1(170)(μl / ρl )0.1]1/2
Vw= 16.63
DC = [4* 16.63/ 3.1416* 0.5393* 2.51]1/2
DC = [66.52/4.25]1/2
DC = 3.9m
Column Actual area = (Л/4) d2
= (3.1416/4)(3.9)2
A = 11.945 m2
 y1 = 0.01207
y2 = 0.000607
Y1/y2 = 19.9
Gm = 59896.16/136*3600
= 0.123 kgmol/s
Lm = 78.4/280*3600
=0.021 kgmol/s
Gm = 59896.16/136*3600
= 0.123 kgmol/s
Lm = 78.4/280*3600
=0.021 kgmol/s
Height of Column
m = 0.0123/ 0.0768 => 0.160
mGm/Lm = 0.9371
NoG = 1/1-(mGm/Lm) ln [ 1- (mGm/lm)y1/y2+mGm/Lm
= 1/1-0.9371 ln (1- 0.9371 (19.75 + 0.9371 )
= 15.89 ln ( 0.0629 ( 20.68)
= 4.16 m
Hog = 1.14 (Gm)0.316 /(Lm)0.315
= 1.14 (0.123)0.316 / (0.021)0.315
= 1.985m
Height = Hog * Nog
= 1.985m * 4.16m
= 8.25m

syngas in = 62425.5 kg/hr

Cyclone Separator

syngas out = 59896.16

kg/hr

efficiency = 85.4%

particle size = 18m

 ash out = 1872.285

kg/hr

temp. = 600 C

 = syngas = 0.95 kg/m3

volumetric flowrate of syngas =

62425.4/0.95*3600
= 18.25 m3/s
Optimum velocity range = 10-20 m/sec
Let, velocity = 15 m / s
Area of Inlet duct = 18.25/1
Area of Inlet duct= 1.216m2

Duct area = 0.5 ∗ Dc ∗ 0.2Dc

From figure 10.44(a);

1.216 = 0.1 * Dc2

Dc = 3.487m

This is too large with the standard design diameter of 0.203m

Outlet duct area of gas
D0=0.5*Dc
D0=1.7435m

A0= Pi/4* Do2

A0=2.386m2

Dd = 0.375 ∗ Dc
Diameter of dust collector:

Dd = 1.307625 m

Pressure drop

Ai=Area of inlet duct= 1.216m2

As = cyclone surface area

Fc=friction factor=0.005 for gases

As
 fc =
Ai

rt=radius of circle to which the center line of inlet is tangential

rt= 3.1383m
re=radius of exit pipe
re = D 0 / 2
re = 0.87175m
rt/re= 3.6
By using rt/re and calculate from graph From figure 10.47;
=0.628 &
rt/re=3.6 We have;
= 2
Area of exit pipe;
Ae=*re2
Ae=2.3862 m2
Inlet:
u1= 1082.5/1.2168*3600 = 0.247 m/s
u2= 1082.5/2.3862*3600 = 0.126 m/
Eq 10.9 :
Delta P = pf{u12[1+2Q2(2 rt/re-1])+ 2u22}
= 0.0018392 millibar
 CHAPTER
8

COST ESTIMATION

OVERVIEW

A capital investment is required for any industrial process and determination of

the necessary investment is an important part of a plant design project. Evaluation
of this investment is referred to as cost estimation.

9.1. CAPITAL INVESTMENT

Before industrial plant can put into operation, a large sum of money must be
supplied to purchase and install the necessary machinery and equipment. Land and
service facilities must be obtained and the plant must be erected complete with all
piping, controls and service. In addition, it is necessary to have money available
for the installation and working of a plant is called total capital investment. Total
Capital Investment = Fixed Capital + Working Capital

9.2. FIXED CAPITAL INVESTMENT

The capital needed to supply the necessary manufacturing and plant facilities is
called fixed capital investment. The fixed capital is further subdivided into
followings.
• Manufacturing fixed capital investment
• Non-manufacturing fixed capital investment

The fixed capital investment classified in to two sub divisions:

• Direct Cost
• Indirect Cost

Direct Cost

87
 The direct cost items arc incurred in the construction of the plant in addition to the
cost of equipment.
• Purchased equipment cost
• Purchased equipment installation
• Insulation cost
• Instrumentation and control
• Piping
• Electrical installation
• Building including services
• Yard improvement
• Service facilities
• Land

Indirect Cost
In Direct cost can be estimated by estimating following costs.
• Engineering and supervision
• Construction expenses
• Contractor’s fee
• Contingencies
• Start-up expenses

WORKING CAPITAL

The capital required for the operation of the plant is known as working capital. Working
Capital Includes following things to be considered
• Raw materials and supplies carried in stock

• Finished product in stock and semi-finished products in the process of being

manufactured
• Accounts receivable

88
• Cash kept on hand for monthly payment of operating expenses, such as salaries,
wages and raw material purchases
• Accounts payable
• Taxes payable

CAPITAL COST ESTIMATES

An estimate of the capital investment for a process may vary, pre-design estimated based on
little information except the size of the proposed project to a detailed estimate prepared from
complete drawings and specifications. Between these two extremes of capital investment
estimates there can be numerous other estimates which vary in accuracy depending on the
stage of development of the project. These estimates are called by a variety of names, but the
following five categories represent the accuracy range and designation normally used for the
design purposes.
• Order of magnitude estimates
• Study estimate (factorial estimate)
• Preliminary estimates (Budget authorization estimate
• Definitive estimate (project control estimate)
• Detailed estimate (Contractor’s estimate).

INSTALLED EQUIPMENT COST

COST OF GASIFIER

Type of gasifier = fluidized bubbling bed

Gasifier material of construction =Carbon steel
Pressure factor = 1
Pressure = 1bar
Diameter = 1.36m
Height = 6.88m

89
Bare cost mid 2007 = 19500$

The purchased cost can be calculated using Purchased

cost
= bare cost pressure factor Purchased cost
=19500*1=19500$ in mid of 2007
Cost in 2023/cost in 2007= cost index in 2023/cost index in 2007
Cost index in 2007 = 509.7
Cost index in 2023 = 655.9

Cost in 2023 = 24960 $

COST OF HEAT EXCHANGER (SHELL AND TUBE)

Type = shell and tube heat exchanger

Material of construction = carbon steel
Pressure factor = 1
Type Factor = Floating Head * 1
Heat transfer area=743m2
Pressure = 1 bar
Bare cost mid 2007 = 125500$
The purchased cost can be calculated using
Purchased cost =bare cost*pressure factor*type factor
Purchased cost = 125500*1*1
=125500$ in mid of 2007
Cost index in 2007 = 509.7
Cost index in 2023 = 655.9
Cost in 2023/cost in 2007=Cost index in 2023/cost index in 2007
Cost in 2023 = 161497 $

COST OF ABSORBER

90
Diameter= 3.9m
Height = 8.25m
Cost index in 2007=509.7
Cost index in 2023 = 655.9
Material of construction = carbon steel
Pressure = 1 bar
Bare cost mid 2007 = 11000$
The purchased cost can be calculated using
Purchased cost = bare cost*pressure factor*type factor
Purchased cost = 11000*1*1=11000$ in mid of 2007
Cost in 2023/cost in 2007=cost index in 2023/cost index in 2007

Cost in 2023 =14155.18 $

PACKING COST
Packing type = Intalox saddle of 38mm of size
Cost = 1120$/m
Volume of Packing = 36.17m3
Cost of Packing = 36.17*1120
=40510.4$
Total cost of absorber= 14155.18+40510 = 54665.58$

9) COST OF RECIPROCATING COMPRESSOR

Size of the compressor = 15kw
Ce=a+b*S^n

a = 490000

b = 16800

n = 0.6

C = 511374

91
 e

CI-2007 = 510
CI-2023 = 656

Purchase equipment cost in 2023: 654558.72 $

TOTAL PURCHASED COST OF ALL EQUIPMENT (PCE)
PCE = cost of gasifier + cost of heat exchanger + cost of H2S absorber column + cost of the
compressor
PCE = 24960 $+161497 $ + 54665.58$ + 654558.72$
PCE = 895681.3$

Estimation of capital investment cost (showing individual components)

The percentages indicated in the following summary of the various costs constituting the
capital investment are approximations applicable to ordinary chemical processing plants. It
should be realized that the values given vary depending on many factors, such as plant
location, type of process, and complexity of instrumentation.
• Direct costs = material and labor involved in actual installation of complete facility (65-
85% of fixed-capital investment)
• Equipment + installation + instrumentation + piping + electrical + insulation + painting
(50-60% of fixed- capital investment)

• Purchased equipment (15-40% of fixed-capital investment)

• Installation, including insulation and painting (25-55% of purchased-equipment cost)
• Instrumentation and controls, installed (8-50% of purchased-equipment cost)
• Piping installed (10-80% of purchased-equipment cost)
• Electrical, installed (10-40% of purchased-equipment cost)
• Buildings, process, and auxiliary (10-70% of purchased-equipment cost)
• Service facilities and yard improvements (40-100% of purchased-equipment cost
• Land (1-2% of fixed-capital investment or 4-8% of purchased-equipment cost)

92
 • Indirect costs = expenses which are not directly involved with material and labor of actual
installation of complete facility (15-35% of fixed-capital investment)
• Engineering and supervision (5-30% of direct costs)
• Legal expenses (1-3% of fixed-capital investment)
• Construction expense and contractor's fee (10-20% of fixed-capital investment)
• Contingency (5-15% of fixed-capital investment)

• Fixed-capital investment = direct costs + indirect costs

• Working capital (10-20% of total capital investment)
14. Total capital investment = fixed-capital investment + working capital

• Calculation of cost estimate

Total installation cost = 385142.959$
Total instrumentation and control =
107481.756$
Total piping cost = 591149.658$
Total electrical cost = 134352.195$

Total Building Cost= 403056.585$

Total Service Cost= 179136.26$

Total direct cost = 1800319.41$

Total indirect cost = 450079.853$

Fixed capital investment = 2250399.2$

Working capital = 337559.89$
Total capital investment = 2587959.16$

• Estimation of total product cost (showing individual components)

93
The percentages indicated in the following summary of the various costs involved in the
complete operation of manufacturing plants are approximations applicable to ordinary
chemical processing plants. It should he realized that the values given vary depending on
many factors, such as plant location, type of process, and company policies.

• Manufacturing cost = direct production costs + fixed charges + plant overhead costs

• Direct production costs (about 66% of total product cost)

• Raw materials (10-80% of total product cost)

• Operating labor (10-20% of total product cost)

• Direct supervisory and clerical labor (10-20% of operating labor)

• Utilities (10-20% of total product cost)

● Maintenance and repairs (2-10% of fixed-capital investment)

● Operating supplies (10-20% of maintenance and repair costs, or 0.5-1% of fixed-

capital investment)

4. Laboratory charges (10-20% of operating labor)

● Patents and royalties (0-6% of total product cost)

· Fixed charges (10-20% of total product cost)

● Depreciation

● Local taxes (1-4% of fixed-capital investment)

94
● Insurance (0.4-1% of fixed-capital investment)

5. Rent (8-12% of value of rented land and buildings)

● Financing (interest) (0-10% of total capital investment)

● Plant overhead costs (50-70% of cost for operating labor, supervision, and maintenance;
or 5-15% of total product cost) include costs for the following: general plant upkeep and
overhead, payroll overhead, packaging, medical services, safety and protection, restaurants,
recreation, salvage, laboratories, and storage facilities

• General expenses = administrative costs + distribution and selling costs + research and
development costs (15-25% of the total product cost)

• Administrative costs (about 20% of costs of operating labor, supervision, and maintenance;
or 2-5% of total product cost) include costs for executive salaries, clerical wages, computer
support, legal fees, office sup- plies, and communications

• Distribution and marketing costs (2-20% of total product cost) include costs for sales
offices, salespeople, shipping, and advertising

• Research and development costs (2-5% of every sales dollar, or about 5% of total product
cost)

• Total product cost = manufacturing cost + general expenses

• Gross earnings cost (gross earnings = total income — total product cost; amount of gross
earnings cost depends on amount of gross earnings for entire company and income tax
regulations; a general range for gross earnings cost is 15-40% of gross earnings).

95
Calculation of total product cost

Price of 1kg of syngas = 0.9$

Price of 1000 tons/day = 774$
Price of 313900tons/year =282510$(market price)

• Manufacturing cost = direct production costs + fixed charges + plant overhead costs

• Direct production costs (about 66% of total product cost) = 0.65*251120 =163228$

• Fixed charges (10-20% of total product cost) = 0.11*251120 = 27623.2$

• Plant overhead costs (50-70% of cost for operating labor, supervision, and maintenance;
or 5-15% of total product cost) = 0.07*251120 = 17578.4$

Manufacturing cost = 208429.6$

General expenses = administrative costs + distribution and selling costs + research and
development costs (15-25% of the total product cost)
= 0.17*251120 = 42690.4$

Total product cost = manufacturing cost + general expenses

Total product cost = 208429.6$ + 42690.4$ = 201120
• ANNUAL PROFIT

Total income = 282510$

Total production cost = 201120$

Gross profit = 282510-201120 = 81390$

96
 Net profit (annual profit after tax) = 61042.5$
CHAPTER 9
HAZOP STUDY AND ENVIRONMENTAL EFFECTS
The technique of hazard operability studies or in more common terms HAZOP, has been used
and develop approximately decades for identifying potential hazard and operability problems
caused by deviation from the design intent of both and new and existing process plants. Before
processing further, it might be as well to clarify some aspects of these statements.
Potential Hazards and Operability Problems:
You will note the bold AND in the above handing, it’s because high profile of production
plant accident, emphasis is too often placed upon the identification of hazards to the neglect of
potential problems. Yet it is the latter area that benefits of HAZOP study are usually the greatest.
Industries in Which the Technique is Applied:
HAZOP were initially invented by ICI in the United Kingdom but the technique only
started to be more widely used with in the chemical industries after the Fix borough disaster in
which a chemical plant explosion kills 28 people, many if were ordinary house holders living
nearby. Through the general exchange of ideas and personnel, the system was adopted by the
petroleum industries, which has a similar potential of major disasters. This was then followed by
the food and water industry, where the hazard potential is as great, but of a different nature, the
concern being more to do with contamination rather than explosions or chemical release. Basic
Concept:
Essentially the HAZOP procedure involves taking a full description of process and
systematically questioning every part of it establishes how deviation from the design intent and
their consequences can have a negative effect upon the safe end and efficient operation of plant.
If consider necessary action is then taken to remedy the situation. The critical analysis is applied
in a structured way by a HAZOP team and it relies upon them releasing their imagination in an
effort to discover credible causes of deviations. In practice, many causes will be fairly, obvious
such as pump failure causing of circulation loss in a cooling water facility mentioned above.
However, than a mechanistic checklist type of review. The result is that there good chance that
potential failures and problems will be identified, which had not previously been experienced in
the type of plant being studied.

97
HAZOP study methodology:
In simple terms the HAZOP study process involves applying in a systematic way all
relevant keywords combining to the plant in question in an effort to uncover potential problems.
The results are recorded in a columnar format under the headings,
Deviation Cause Consequences Action
In considering the information to be recorded in each of these columns is given below.
i. Deviation
The key words combination being applied (e.g., Flow/No)
ii. Cause
Potential cause which would result in the deviation occurring (e.g., “strainer blockage due to
impurities in Dosing tank” might be a cause of Flow/No).
iii. Consequences
The consequences which would arise, both from the effect of the deviation (e.g., “Loss of
dosing results in complete separation”) and, if appropriate from the cause itself (e.g. “cavitations
in pumps, with possible damage if prolonged”).
iv. Safeguards
Any existing protective devices, which either prevent the cause or safeguards against the
adverse consequences, would be recorded in this column. For example, you may consider
recording “Local pressure gauge in discharge from pump might indicate problem was arising”.
Note that safeguard need not to be restricted hardware where appropriate credit can be taken for
procedural aspects such as regular plants inspections (if you sure that they will actually be
carried out).
iv. Action
Where a credible cause results in a negative consequence, it must be decided whether some
action should be taken. It is at this stage that consequences and associated safeguards are
considered. If it is deemed that the protective measures are adequate, then no action need to take,
and words to that effects are recorded in the action column. Action falls in two groups:
1. Action that removes the cause

2. Action that mitigates or eliminate the consequences

98
 Whereas former is to be preferred, it is not always possible especially when dealing with
equipment’s malfunction. However, always investigate removing the cause first and only where
necessary mitigate the consequences. Finally, always take into account the label of training
experience especially of personnel who will operate the plant. Actions, which call for elaborate
and sophisticated protective systems, are wasted, as well as being inherently dangerous, if
operators do not and never will, understand how they function. It is not unknown for devices to
be disabled, either deliberately or in error, because no one knows how to maintain and calibrate
them. Having gone through the operations involve in recording a single deviation, these can now
be put into the context of the actual study meeting procedure. From the flow diagram below, it
can be seen that it is very much an iterative process, applying in a structured and systematic way
the relevant keyword combinations in order to identify potential problems.

9.1. HAZOP Technique:

The procedure for performing a HAZOP analysis consists of the following five steps:
1. Define the system or activity. Specify and clearly define the boundaries of the system or
activity for which hazard and operability information is needed.
2. Define the problems of interest for the analysis. Specify the problems of interest that the
analysis will address. These may include health and safety issues, environmental
concerns, etc.
3. Subdivide the system or activity and develop deviations. Subdivide the system or activity
into sections that will be individually analyzed. Then apply the HAZOP guide words that
are appropriate for the specific type of equipment in each section.
4. Conduct HAZOP reviews. Systematically evaluate each deviation for each section of the
system or activity. Document recommendations and other information collected during
the team meetings, and assign responsibility for resolving team recommendations.
5. Use the results in decision making. Evaluate the recommendations from the analysis and
the benefits they are intended to achieve.
6. The benefits may include improved safety and environmental performance or cost
savings. Determine implementation criteria and plans.

9.2. Process of HAZOP Analysis:

 Isolate the framework into segments and create valid deviations.

99
  Focus the reason for the deviation and assess the result/issues.
 Discover the shields which help to diminish the event recurrence of the deviation
or to relieve its outcomes.
 Prescribe a few activities to against the deviation more adequately.
 Record the data.
 Repeat methodology.
Guide words and parameters:
The key feature is to select appropriate parameters which apply to the design intention.
These are general words such as flow, temperature, pressure, level, time, concentration,
and reaction.
Variations in these parameters could constitute deviations from the design Intention. A
set of guide words to each parameter for each section of the process was applied to
identify deviations. Standard guide words are as follows in Table.

Meaning
Guide Words
REVERSE Logical opposite of the design intent
PART OF Qualitative decrease
MORE Quantitative increase
LESS Quantitative decrease
NO Complete negation of the design intent

HAZOP on Reactor:

Guide Possible Causes Consequences Action

Deviation
Words required

100
 Required
Install low
Steam valve temperature
No No Steam temperature
malfunctioning does not achieve in
alarms
reactor
Less heating
reactor may not
Failure of steam Install check
Reverse achieve
Reverse source resulting in valve in flow
steam flow required
backward flow line
temperature for
conversion
Install high
More steam Failure of steam Reactor may be
More temperature
flow header over heated
alarms
Required Install low
Less steam
Less Failure in furnace temperature temperature
temperature
doesn’t achieve alarms
in reactor
Table 9.1 Hazop on Reactor

HAZOP on Heat Exchanger:

Guide Deviation Possible Consequences Action required

Words causes

Less Less cooling Pipe leakage Process fluid Installation of flow

water temperature too meter
low

101
 More More Failure of inlet Output of fluid Install temperature
cooling cooling water temperature too indicator before and
water flow valve to close low after process fluid
Reverse Reverse Failure of Product off set Install check valves
process fluid process flow
flow inlet valves
Table 9.2 Hazop on Heat Exchanger

HAZOP on Separator:

Guide Deviation Possible causes Consequences Action required

Words

Less less flow of 1. Pipe leakage 1. Rate of 1. Maintenance

fluid 2. Control production 2. Fit flow level

valves inlet reduces alarm
failure 2. Rate of

3. Blocking in separation

pipe reduce

More High flow 1. Level 1. Turbulence 1. Install automatic

of fluid control fails flow occur plant shut down

2. Partial 2. Rate of 2. Install

separation independent level
failure pump
reduce transmitter

1. No separation 1. Maintenance and

Reverse No flow of 1. Pump failure
fluid 2. Level valves 2. No production checking

fail 2. Install flow

meters

Table 9.3 Hazop on Separator

102
HAZOP study of Absorber:.

Deviation Possible Causes Consequences Action Required

More of Lean solution flow rate Over-absorption of the gas, Reduce lean solution flow
(M) too high leading to a loss of product rate

Less of (L) Lean solution flow rate Under-absorption of the gas, Increase lean solution
too low leading to emissions flow rate

Higher of Gas inlet temperature Increased vapor pressure of the Reduce gas inlet
(H) too high gas, leading to a decrease in temperature
absorption efficiency
Lower of Gas inlet temperature Decreased vapor pressure of the Increase gas inlet
(L) too low gas, leading to an increase in temperature
absorption efficiency
Reverse of Flow of lean solution Inefficient absorption Reverse the flow of lean
(R) and gas in opposite solution and gas
direction
No flow Absorber blocked or No absorption of gas Clear blockage or
(N) obstructed obstruction

Other (O) Any other deviation not Dependent on the specific Dependent on the specific
listed above deviation deviation

Table 9.4 Hazop on Absorber

103
 Chapter 10
Conclusion

Syngas is so called because of its history as an intermediate in the production of synthetic

natural gas.
Composed primarily of the colorless, odorless, highly flammable gases carbon monoxide
(CO) and hydrogen (H2), syngas has a variety of uses. The syngas can be further converted
(or shifted) to nothing but hydrogen and carbon dioxide (CO2) by adding steam and reacting
over a catalyst in a water-gas-shift reactor. When hydrogen is burned, it creates nothing but
heat and water, resulting in the ability to create electricity with no carbon dioxide in the
exhaust gases. Furthermore, hydrogen made from coal or other solid fuels can be used to
refine oil, or to make products such as ammonia and fertilizer. More importantly, hydrogen
enriched syngas can be used to make gasoline and diesel fuel. Polygeneration plants that
produce multiple products are uniquely possible with gasification technologies. Carbon
dioxide can be efficiently captured from syngas, preventing its greenhouse gas emission to
the atmosphere and enabling its utilization (such as for Enhanced Oil Recovery) or safe
storage
Syngas is the new smart energy that can be utilized instead of various fossil fuels including
gasoline and other combustible fuels. Syngas production is the vital need of the modern era.
Its various methods of production have made its extraction from various fossil fuels possible
giving safe and nature friendly products.The extraction of syngas through gasification of one
of the most widely available fossil fuel I.e. coal is one of the most trusted and useful method
giving lesser by products making it feasible and eco-friendly process.

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 Chapter 11
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