B.

TECH PROJECT REPORT

18,000 MTPA METHANOL PRODUCTION FROM BIOGAS

By

GROUP 03

SHARAT SONI

(15112090)

DEPARTMENT OF CHEMICAL ENGINEERING

INDIAN INSTITUTE OF TECHNOLOGY ROORKEE

ROORKEE - 247667

APRIL - 2019
 Methanol Production From Biogas

CERTIFICATE

This is to certify that the project titled “18,000 MTPA Methanol Production from Biogas”,
which is hereby presented by Mr. Sharat Soni in partial fulfilment of the requirements for the
award of the Degree of Bachelor of Technology in Chemical Engineering at Indian Institute of
Technology Roorkee, is a genuine account of his work carried out during the period from
August 2018 to April 2019 under my supervision and guidance.

Dr. N. Siva Mohan Reddy

Assistant Professor

Department of Chemical Engineering

Indian Institute of Technology Roorkee

Roorkee – 247667, India

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 Methanol Production From Biogas

ACKNOWLEDGEMENTS

We wish to avail the opportunity to express with utmost sincerity, my heartfelt thanks to Dr.
N. Siva Mohan Reddy, Assistant Professor, Department of Chemical Engineering, IIT
Roorkee, for his erudite guidance and suggestions, his timely help and motivation, without
whose patronage it would not have possible for me to carry out my project work and its
culmination into this feasibility report. Sincere thanks are also due to Dr. Shishir Sinha,
Professor and Head, Department of Chemical Engineering, IIT Roorkee for the various
facilities in this department.

Sharat Soni

B.Tech IV Year

Enrollment No. 15112090

Department of Chemical Engineering

Indian Institute of Technology Roorkee

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 Methanol Production From Biogas

1 CONTENTS
1 Contents ............................................................................................................................. 4

2 Executive Summary ........................................................................................................... 6

2.1 Process Summary ........................................................................................................ 6

2.2 Cost Information ......................................................................................................... 6

2.3 Employment Potential ................................................................................................. 7

2.4 Utilities ........................................................................................................................ 7

2.5 Profitability of the Project ........................................................................................... 7

3 Project Details .................................................................................................................... 8

3.1 Introduction ................................................................................................................. 8

3.2 Project Description ...................................................................................................... 8

3.2.1 Uses and Present Status of the Product ................................................................ 8

3.2.2 Available Processes for the Production of Product.............................................. 9

3.2.3 Techno-Economic Appraisal of Alternative Processes/Schemes ...................... 14

3.2.4 Status of Technologies/Schemes Available ....................................................... 17

3.2.5 Selection of Technology/Schemes: .................................................................... 18

3.2.6 Source of Know-How of Selected Process/ Technology ................................... 20

3.2.7 Raw Materials .................................................................................................... 21

3.3 Material and energy flow information ...................................................................... 24

3.4 Detailed design of equipment .................................................................................... 42

3.4.1 Process Design of all major equipment ............................................................. 42

3.4.2 Mechanical Design............................................................................................. 74

3.4.3 Drawings of Two Equipment as per BIS Specification of Equipment ............ 101

3.4.4 Specification of All Process Equipments ......................................................... 102

3.4.5 Major Engineering Problems of the Plant with their remedies ........................ 108

3.5 Materials storage and handling facilities ................................................................. 112

3.5.1 Biogas .............................................................................................................. 112

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3.5.2 Methyl Di-Ethanol Amine (MDEA) ................................................................ 115

3.5.3 Steam................................................................................................................ 118

3.6 Process Instrumentation & Control and Safety Aspects ......................................... 121

4 Environmental Protection & Energy Conservation ....................................................... 131

4.1 Environmental Aspects ........................................................................................... 131

4.2 Energy Conservation ............................................................................................... 135

5 Plant Utilities ................................................................................................................. 137

5.1 Heat Transfer Media................................................................................................ 137

5.1.1 Type and Requirement ..................................................................................... 137

5.1.2 Steam Generation System ................................................................................ 137

5.2 Electricity/ power .................................................................................................... 138

5.3 Water ....................................................................................................................... 139

5.3.1 Process and General Water Requirement and Standard .................................. 139

5.3.2 Water Treatment .............................................................................................. 139

6 Organizational Structure & Manpower Management .................................................... 141

Divisions of Organization .................................................................................................. 144

7 Market Prospects ............................................................................................................ 148

7.1 A brief analysis of demand and supply of the product ............................................ 148

7.2 Present production/licensed capacity of the country ............................................... 150

7.3 Export Potential ....................................................................................................... 150

7.4 Marketing set up and area of consumption ............................................................. 151

8 Site Selection & Project Layout ..................................................................................... 153

8.1 Site Selection ........................................................................................................... 153

8.2 Plant Layout Considerations ................................................................................... 154

9 Economic Evaluation & Profitability of Project ............................................................ 159

10 References ...................................................................................................................... 166

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2 EXECUTIVE SUMMARY

2.1 PROCESS SUMMARY

This process summary is an attempt towards making a techno-economic evaluation of the
production of 18,000 MTPA Methanol production from biogas.

The whole process has been subdivided into three sub-processes:

1. Reforming of Biogas to produce Syngas

2. Conversion of Syngas to Methanol ( Fischer-Tropsch Process)
3. Purification of Crude Methanol

For conversion of biogas to syngas, Bi-reforming method is chosen as it results in favorable

H2/CO (2:1) ratio that can be used for methanol synthesis.

3CH4+ CO2+ 2H2O ↔ 4CO+ 8H2 ΔH298 K= + 220 kJ/mol

The reforming takes place at 950oC and 20 bar. For methanol synthesis the methanol reactor
which is essentially a packed bed reactor operates at 250oC and 71 bar.

The plant location has been chosen as Kudal village in Satara District of Maharashtra
primarily due to ease of availability of raw material, transport facilities and favorable
government policies. Location is close to Green Elephants from which we will be obtaining
Biogas.

2.2 COST INFORMATION

a. Economic Consideration

Purchase Equipment Cost ₹420,000,000

Direct cost ₹ 1,984,234,611
Indirect cost ₹ 361,200,000

Total Project cost ₹ 2,765,434,611

Selling Price at 100% Capacity ₹35/kg of Methanol. The cost price of feed material is ₹ 7
/Kg. The Payback period is 3.23 years and rate of return is 17.29%.

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2.3 EMPLOYMENT POTENTIAL

The plant has a total employment potential of 132 Employees. The top hierarchy of the
organization can be represented by the following chart.

MD/Chairman

CEO CFO COO

(Cheif Executive (Cheif Fianacial (Cheif operation
Officer) Officer) officer)

Personal &
Finance Research and
Administration Operations
Department Development
Department

Product Marketing
and Sales

2.4 UTILITIES
The Summary of utilities used in the plant is given in the table below-

Unit Unit Used Rs/Unit Rs

Power KWH 11773823.04 5.5 64756026.72
HP Steam Tonne 146903.2258 1800 264425806.5
LP Steam Tonne 83032.25806 1500 124548387.1
Fuel Oil Tonne 2636.88 1200 3164256
Cooling Water m^3 1555.2 30 46656
Plant Air m^3 37157201.17 0.7 26010040.82

2.5 PROFITABILITY OF THE PROJECT

The project has a payback period of approx. 3.23 years. This implies that to turn the plant, it
would have to run for at least 3 years to make profit. A positive rate of return 17.29% implies
itself that the plant is profitable.

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3 PROJECT DETAILS

3.1 INTRODUCTION
This project aims at producing 18000 MTPA Methanol from Biogas. Conventionally natural
gas is used as feed to produce methanol, but in near future this source is going to deplete. As
keeping in mind as to how the methanol market is expanding we need to look out for
alternatives of natural gas. One such source is biogas, which can be produced easily from the
everyday waste.

In this report, we’ll first discuss various available processes for the production of Methanol,
followed by the selection of a suitable process. Then the raw material will be discussed in detail
along with the market prospects of the final products followed by the site selection and project
layout is done and the end economic evaluation of the complete project is done.

3.2 PROJECT DESCRIPTION

3.2.1 Uses and Present Status of the Product

Methanol is rated among the most important feedstocks for the chemical, petrochemical and
energy industries, with a worldwide production of 95.38 million metric tons in 2017. The global
production is forecasted to grow annually by an average rate of 7.2% to reach 117 million
metric tons in 2020.1 Some of the important uses of methanol is as follows:

a. Production of heavy chemicals such as formaldehyde: Methanol is primarily converted to

formaldehyde, which is widely used in many areas, especially polymers. The conversion entails
oxidation:
2 CH3OH + O2→ 2 CH2O + 2 H2O

b. Methanol to hydrocarbons, olefins, gasoline: Condensation of methanol to produce

hydrocarbons and even aromatic systems is the basis of several technologies related to gas to
liquids. These include methanol-to-hydrocarbons (MTH), methanol to gasoline (MTG), and
methanol to olefins (MTO), and methanol to propylene (MTP).

c. Gasoline additive: The European Fuel Quality Directive allows up to 3% methanol with an
equal amount of co-solvent to be blended with gasoline sold in Europe. Niti Aayog, the

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planning commission of India on 3rd August 2018 announced that if feasible, passenger
vehicles will run on 15% Methanol mixed fuel.

d. Other Chemicals: Methanol is the precursor to most simple methylamines, methyl halides,
methyl ethers. Methyl esters are produced from methanol, including the transesterification of
fats and production of biodiesel via transesterification.

e. Energy Carriers: Methanol is a promising energy carrier because, as a liquid, it is easier to

store than hydrogen and natural gas. Its energy density is however low reflecting the fact that
it represents partially combusted methane. Its energy density is 15.6 MJ/L, whereas ethanol's
is 24 and gasoline's is 33 MJ/L.

f. Fuel for vehicles: Methanol is occasionally used to fuel internal combustion engines. It burns
forming carbon dioxide and water. It is used in racing cars in many countries.
2CH3OH + 3O2 → 2CO2 + 4H2O
g. Methanol is a traditional denaturant for ethanol, the product being known as "denatured
alcohol" or "methylated spirit".

Importance of the problem

Hence we see that Methanol plays an integral part of our surroundings, from making urethane
foams used in seats to production of Methylamines used in Liquid detergents & shampoos,
methanol is used everywhere in the daily life. All the industrial processes present are based on
natural gas as feedstock but as natural gas resources are getting depleted we’ve to find an
alternative to produce methanol. Bio gas is an important precursor in the need of the hour from
which methane can be produced and ultimately producing Methanol.

3.2.2 Available Processes for the Production of Product

In this section we will discuss several process to produce methanol. Then the most appropriate
process will be selected, but as mentioned earlier in the report there is no mention of any
industrial process using biogas as feedstock to make methanol in the literature. We will analyze
the existing processes using natural gas as feed stock and then accordingly decide the flow
scheme for biogas as feedstock. Direct synthesis processes 2(i.e the direct selective oxidative
transformation of methane)

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CH4(g) + 0.5 O2(g) → CH3OH(l) ΔHo = -30.7 kcal

has the major advantage of avoiding the energy intensive step of syngas production, but are
technically difficult to accomplish. The main disadvantages refer to a low conversion of the
feedstock and the production of undesired byproducts, due to the higher reactivity of the
oxidation products compared to methane.3 Hence, industrial methanol is exclusively produced
by indirect conversion routes via syngas production. The following are the routes used in
industry:

a) Conventional ICI`s 100-atm Methanol Synthesis Process:

 This method was developed by Imperial Chemical Industries. This process reduced the
methanol synthesis pressure by using catalyst but the process was not ideal for large
capacity of production unit due to the necessity of large equipment under low pressure
condition which ultimately caused slower rate of reaction.
 Cu/ZnO/Al2O3 is used as catalyst.
 A process diagram is given below (fig.1). The original flow sheet includes two parts of the
process, namely, reforming and synthesis sections.
 Quench reactor is used in this process at 50-100 bar and 220-280 oC.

Fig. 1- ICI`s 100-atm Methanol Synthesis Process

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b) Haldor Topsoe A/S Low-Pressure Methanol Synthesis Process

 This process is designed to produce methanol from natural or associated gas feed stocks,
utilizing a two-step reforming process to generate feed synthesis gas mixture for the
methanol synthesis. Associated gas is a natural gas produced with crude oil from the same
reservoir.
 The reactor used is vertical tubular reactor at 220oC between 40 - 100 bar. The catalyst is
contained inside the tubes (typically 2000 to 4000 tubes, 7 m long) and on the outside of
the tubes; boiling water is used to remove the heat from the exothermic reaction-taking
place inside the tubes.
 It is claimed that the total investment for this process is lower than the conventional flow
scheme which based on straight steam reforming of natural gas approximately 10%, even
after considering an oxygen plant.
 The two-stage reforming usually conducted by primary reforming, in where, a preheated
mixture of natural gas and steam are reacted and in the secondary reforming stage, the exit
gas further converted with the aid of oxygen.
 The process technology is suitable for smaller to larger methanol plants up to 10,000 TPD.

Fig 2- Haldor Topsoe Low-Pressure Methanol Synthesis Process

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c) Krupp Uhde’s methanol synthesis process

 The process is based on the low-pressure synthesis chemistry of methanol as well as steam
reforming for synthesis gas generation.
 Uhde offers isothermal and adiabatic reactors. The isothermal reactor is the most efficient
system, as the heat of reaction is directly utilized at reaction temperature level to generate
medium-pressure steam. Uhde's isothermal reactor is a tubular reactor with a copper
catalyst contained in vertical tubes and boiling water on the shell side.
 The steam reformer is uniquely designed by Krupp Uhde and is a top-fired box-type
furnace with a cold outlet header system.
 The steam reforming reaction takes place heterogeneously over a nickel catalyst system.
The reformer effluent gas containing H2,CO, CO2, and CH4 is cooled from 880°C to
ambient temperature eventually, and most of the heat content is recovered by steam
generation, BFW preheating, preheating of demineralized water, and heating of crude
methanol for three-column distillation. Eleven plants have been built until 2005, using this
technology.

Fig 3- A schematic of Krupp Uhde’s methanol synthesis process.

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d) Lurgi Ol-Gas-Chemie GmbH methanol synthesis process

 This process is meant to produce methanol in a single-train plant starting from natural gas
or oil-associated gas with capacities up to 10,000 mtpd.
 Steam reforming of natural gas is accomplished in two stages, i.e., prereforming and ATR.
 In the prereformer, the mixture gas of desulfurized natural gas and steam is converted to
H2, CO2, and CH4, whereas in the auto-thermal reformer the gas is reformed with oxygen
and steam, producing product gas containing H2, CO, CO2, and a small amount of
unconverted CH4 in addition to low-pressure steam.
 The reformed gas, i.e., syngas, is mixed with hydrogen from the pressure swing adsorption
(PSA) to increase the H2-to-CO ratio. The produced synthesis gas is pressurized and mixed
with recycled gas from the synthesis loop.
 The reaction takes place under near-isothermal conditions in the Lurgi water-cooled
methanol reactor, which houses a fixed bed of catalyst in vertical tubes surrounded by
boiling water. The reactor effluent gas is cooled to 40°C to separate methanol and water
from the unreacted syngas.
 Methanol and water are separated in distillation units, whereas the major portion of the gas
is recycled back to the methanol synthesis reactor for higher overall conversion. As
mentioned in the earlier subsection, the once-through conversion is typically low;
therefore, recycling of the gas is imperative.
 Enhancements have been made, especially in the efficiency of the Lurgi combined
converter (LCC), to reduce the recycle ratio down to about 2. The process water is
preheated in a fired heater and used as a makeup water for the saturator, thus minimizing
unnecessary water usage and treatment. The reformed gas from the second-stage reformer
contains a considerable amount of thermal energy that is recovered as high-pressure steam
for energy required for preheater and reboiler.

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3.2.3 Techno-Economic Appraisal of Alternative Processes/Schemes

As seen from the above processes, methanol process is composed of three subsystems:

a) Production of synthesis gas - Reforming of Natural gas/Biogas to make syngas (CO + H2)

b) Production of crude methanol- Conversion of Syngas to methanol in methanol synthesis

reactor

c) Purification of methanol- Refining the crude product to get pure methanol

In this section we will see the various alternative for the syngas production and methanol of
methanol production.

Alternative processes for Reforming -

As the feed stock used, biogas, in the current project contains primarily CH4 (50-75%) & CO2
(25-50%) needs to be converted to syngas for methanol production. There are three processes
to reform CO2 and CH4 into syngas, all of which require temperatures above ~800 oC to reach
thermodynamically complete conversions.

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a) CH4 dry reforming - Dry reforming of methane is one of the simplest reactions and can
be performed at temperatures around 800– 1000 oC over a variety of catalysts, for
instance Ni/ MgO or Rh-substituted pyrochlores.
CH4 + CO2 → 2CO + 2H2 ΔH298 K= + 247 kJ/mol, ΔG298 K= + 170 kJ/mol
However, the low H2/CO ratio (1/1) from dry reforming requires the addition of H2 for
reactions of Fischer– Tropsch or methanol synthesis. The most widely used catalysts
for dry reforming are Ni-based catalysts, but they are often plagued with severe
deactivation due to carbon deposition. Noble metal catalysts have been found to be
more carbon deposition resistant, but their high cost limits their industrial use.
b) Oxy-CO2 reforming - The oxy-CO2 reforming of methane has been investigated and
found to have improved energy efficiency of the process as compared to dry reforming:
3CH4 + CO2 + O2 ↔ 4CO + 6H2 ΔH298 K = + 58 kJ/mol, ΔG298 K= -1 kJ/mol
The reaction is auto-thermal but the fact that the presence of oxygen limits carbon
deposition. However, concern of the potent safety of the process, and the less than
optimum H2/CO ratio of oxy-reforming (1.5/ 1) have greatly limited its industrial use
c) Bi-Reforming: The reforming of methane with a combination of CO2 and steam is
known as bi-reforming.
3CH4+ CO2+ 2H2O ↔ 4CO+ 8H2, ΔH298 K= + 220 kJ/mol, ΔG298 K= 151 kJ/mol
Like dry reforming, syngas from bi-reforming can convert CO2 into higher value
products. Also, like dry reforming, bi-reforming can be used to produce syngas from
natural gas containing significant amounts of CO2 and can also be used to react CO2
separated from flue gases from fossil fuel combustion. Unlike dry reforming, bi-
reforming results in a H2/CO ratio of 2/1, which can be directly coupled with the
downstream industrial processes. Several reports also claim that one advantage of bi-
reforming is that the H2/CO ratio can be adjusted by changing the H2O/ (H2O + CO2)
ratio to meet the downstream requirement.4

Reactor alternatives -

The methanol synthesis is exothermic and the maximum conversion is obtained at low
temperature and high pressure. A challenge in the design of a methanol synthesis is to
remove the heat of reaction efficiently and economically - i.e. at high temperature - and at the
same time to equilibrate the synthesis reaction at low temperature, ensuring high conversion
per pass.

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Different designs of methanol synthesis reactors have been used -

a. Quench reactor

A quench reactor consists of a number of adiabatic catalyst beds installed in series in one
pressure shell. In practice, up to five catalyst beds have been used. The reactor feed is split into
several fractions and distributed to the synthesis reactor between the individual catalyst beds.
The quench reactor design is today considered obsolete and not suitable for large capacity
plants.

b. Adiabatic reactors in series

A synthesis loop with adiabatic reactors normally comprises a number (2-4) of fixed bed
reactors placed in series with cooling between the reactors. The cooling may be by preheat of
high pressure boiler feed water, generation of medium pressure steam, and/or by preheat of
feed to the first reactor. The adiabatic reactor system features good economy of scale.
Mechanical simplicity contributes to low investment cost. The design can be scaled up to
single-line capacities of 10,000 MTPD or more.

c. Boiling water reactors (BWR)

The BWR is in principle a shell and tube heat exchanger with catalyst on the tube side. Cooling
of the reactor is provided by circulating boiling water on the shell side. By controlling the
pressure of the circulating boiling water the reaction temperature is controlled and optimized.
The steam produced may be used as process steam.

The isothermal nature of the BWR gives a high conversion compared to the amount of catalyst
installed. However, to ensure a proper reaction rate the reactor will operate at intermediate
temperatures - say between 240ºC and 260ºC - and consequently the recycle ratio may still be
significant.

An adiabatic catalyst bed may be installed before the cooled part of the BWR either in a
separate vessel or preferably on top of the upper tube sheet. One effect of the adiabatic catalyst
bed is to rapidly increase the inlet temperature to the boiling water part. This ensures optimum
use of this relatively expensive unit, as the tubes are now used only for removal of reaction
heat, not for preheat of the feed gas.

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The installation of the adiabatic top layer in the BWR reduces the total catalyst volume and the
cost of the synthesis reactor by about 15-25%. The maximum capacity of one reactor may
increase by about 20%.5

3.2.4 Status of Technologies/Schemes Available

Status of reforming technologies:

Steam reforming is a well-established technology and is used in many processes (Lurgi and
Krupp Uhde’s methanol synthesis) and continuous improvement in materials for reformer
tubes, better control of carbon limits, better catalysts regarding sulfur tolerance and carbon
deposition is still being investigated.

Dry reforming is widely studied & despite significant research, dry reforming is associated
with carbon deposition and, in some cases, thermal deactivation. This process is of particular
interest when H2/CO mixtures with ratios close to unity are preferred. Two commercial
technologies are based on this reaction: the CALCOR process from Caloric (for CO
production) and the SPARG process, from Harold-Topsøe (for syngas production).8

A practical limitation of oxy-CO2 reforming is the danger associated with mixtures of methane
and oxygen, which has greatly limited its widespread use and hence its industrial use is still
under research.

Bi-reforming, the combined steam and dry reforming of methane or natural gas with H2O and
CO2 to syngas for efficient methanol synthesis has been investigated.9 Using a CH4 to steam to

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CO2 ratio of ~3:2:1 in the gas feed, the H2/CO ratio of 2:1 has been achieved, which is desired
for subsequent methanol synthesis.10 This type of reforming is used in Lurgi Ol-Gas-Chemie
GmbH methanol synthesis process.

3.2.5 Selection of Technology/Schemes:

Basis of selection -

a. Selection of Reforming Technology -

The Bi reforming process gives the best result in terms of H2/CO (2:1) that is required for
methanol synthesis. Also it possible to adjust the H2/CO ratio by changing the H2O/(H2O +
CO2) ratio to meet in the reaction. Hence bi reforming is used in the current project and to
carry out this a top-fired reformer (Lurgi Process) is used as it exhibits the following
advantages:

 Multiple-tube rows, resulting in a lower number of burners and lower heat loss

 Almost uniform wall temperature over the entire heated tube length

 Easier burner adjustment and reduced burner maintenance because of the reduced
number of burners Less NOx formation by more accurate fuel and combustion air
equipartition of the burners

 Easier noise abatement

1. Selection of methanol synthesis reactor

Adiabatic-
Reactor Type Quench Tubular Isothermal (BWR)
Radial

Operating Pressure (bar) 50-100 40-100 50-150

Operating Temperature
220-280 220 200-300
(deg C)

Exit MeOH
<7.0 3.0 - 8.0 3.5-5.0
Concentration %

Catalyst Yield low mod.-high high

No. of reactors 1 1 3-4

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Thermal Efficiency low high mod.-low

high thermal efficiency, high production

Major advantages proven reliability
high selectivity rates

low thermal low-medium production reduced

Major disadvantages
efficiency capacity selectivity

Table 1. Comparison of different reactors

As we see in Table 1, the tubular isothermal reactor i.e. Boiling water Reactor gives the highest
thermal efficiency and the maximum exit concentration of methanol, and production capacity
is low- medium which is required for this project as we need to produce 20,000 MTPA of
methanol whereas high capacity plants produce 2500 MTPD.The isothermal reactor is best
suited for the project.

Details of the Selected Process -

The feed biogas at 35oC and 600kPa enters the desulfurizer, where H2S is removed. The
purified biogas (CH4 (65%) + CO2 (35%)) is mixed with steam. Mixture of biogas and steam
is passed through a reformer, where bi-reforming at 950oC and 20 bar occurs to give syngas.
The product of reformer is passed through a liquid/gas separator to remove the liquid droplets
present. Synthesis gas enters the synthesis section of a methanol plant, and is first cooled before
water is removed in a gas/liquid separator. The gas from the separator top outlet is mixed with
the recycle from the reactor and then it is compressed in the syngas compressor. Before it enters
the reactor, the compressed syngas is preheated by hot gas from the reactor outlets. The reactors
are kept at constant temperature of 250oC and 71 bar by pressurized water on the shell side,
which boils from the exothermic reactions happening inside the catalyst-filled tubes. Out of the
reactors the reacted gas runs through the inlet heat exchanger and two coolers (Cooler 1 & 2).
These coolers condense water and methanol in the gas, which is separated from the gas in a
second gas/liquid separator. Gas out of the scrubber is split to purge and recycle. The purge gas
is used elsewhere in the process, and is removed to keep inert gases from building up in the
recycle loop. The recycle compressor, compresses the recycle gas before it is sent back to the
reactors.

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Fig 4. Simplified flow diagram for Methanol Production

3.2.6 Source of Know-How of Selected Process/ Technology

a. Benjamín Cañete, Carlos E. Gigola and Nélida B. Brignole. Synthesis Gas Processes
for Methanol Production via CH4 Reforming with CO2, H2O, and O2.

b. M. Vanden Bussche and . G. F. Froment. A Steady-State Kinetic Model for Methanol

Synthesis and the Water Gas Shift Reaction on a Commercial Cu/ZnO/Al2O3 Catalyst,”
Journal of Catalysis, vol. 161, pp. 1-10, 1996.

c. Lee, Speight, and Loyalka, 2007. Sunggyu Lee, James G. Speight, and Sudarshan K.
Loyalka. Handbook of Alternative Fuel Technologies. CRC Press, 2007. Pg 297 -320

d. George A. Olah, Alain Goeppert, Miklos Czaun, Thomas Mathew, Robert B. May,
and G. K. Surya Prakash. Single Step Bi-reforming and Oxidative Bi-reforming of
Methane (Natural Gas) with Steam and Carbon Dioxide to Metgas (CO-2H2) for
Methanol Synthesis

e. Anita Kovac Kralj Davorin Kralj. Methanol production from biogas 2010.

f. Thomas Helmer Pedersen, René Haller Schultz. Technical and Economic Assessment
of Methanol Production from Biogas,2012

g. Kim Aasberg-Petersen, Charlotte Stub Nielsen, Ib Dybkjær and Jens Perregaard.

Large Scale Methanol Production from Natural Gas.

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3.2.7 Raw Materials

3.2.7.1 Detailed Specifications

The main raw material used in the project is biogas. Table 2 gives composition & properties of
biogas.11

Properties of Biogas Values

Methane (CH4 ) 65 %
Carbon dioxide (CO2) 30 %
Hydrogen Sulfi)de (H2S) 1–2%
Hydrogen (H2) 1–2%
Ammonia (NH3) Traces
Carbon Monoxide (CO) Traces
Nitrogen (N2) Traces
Oxygen (O2) Traces
Appearance Colorless gas
Phase Gas
Flame Speed 25 cm/s
Density (near room Temperature) 1.15 kg/m3
Auto-ignition temperature 540°C
Specific Heat 1.6 kJ/m3 °C
Calorific value 22,000 KJ/Kg
Table 2

Stability and Reactivity

STABILITY: Stable under normal conditions of use.

HAZARDOUS DECOMPOSITION Under normal conditions of storage and use,
PRODUCTS: hazardous decomposition products should not be
produced.
HAZARDOUS POLYMERIZATION: Will not occur.
INCOMPATIBILITIES: Extremely reactive with oxidizing materials.
CONDITIONS TO AVOID: Heat, flames, ignition sources and incompatibilities.

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 Methanol Production From Biogas

Cu/ZnO/Al2O3 catalysts have been applied for nearly 50 years in methanol synthesis, a large-
scale industrial process of still growing importance with a current demand of more than 60
million metric tons per year. Especially in the context of a sustainable future energy system,
methanol produced from CO2 and H2 is believed to play a key role as an energy storage
molecule. Furthermore, Cu/ ZnO – based catalysts are also active in the low-temperature water
gas shift reaction and in the steam reforming of methanol. Because of the multitasking ability
of this class of catalysts, they are used in many applications and different scientific questions
are currently studied based on Cu/ ZnO- based materials. The industrial catalyst is prepared by
co-precipitation. The recipe with constant-pH co-precipitation, ageing, washing, drying and
calcination has been developed and improved by empirical methods over the last decades and
is in itself a subject of on-going research. Based on previous studies, the metal ratio of the best
catalysts prepared was Cu:Zn = 70:30 with additional 3% of Al, resulting in an overall molar
metal composition of 68:29:3 (Cu/ Zn/ Al). This composition aims at a high substitutional level
of Zn in the zincian malachite precursor, (Cu, Zn)2(OH)2 CO3 , to allow for an intimate mixing
of Cu and ZnO particles in the reduced catalyst. Promotion by 3% of Al 3+ was shown to
structurally and electronically promote the catalyst most likely by effective doping of the
ZnO:Al component.

3.2.7.2 Availability: Indigenous/ Imported

India’s production of biogas is quite small as compared to other countries like China. It only
produces about 2.07 billion m3/year of biogas, while it’s estimated that it could produce as
much as 48 billion m3/year. About 47.5 Lakh biogas plants have already been installed in the
country upto 31st March, 2014. The major industries generating biogas are Distillery, Sugar,
and Starch. These three, together, account for 3/4th of the total biogas potential of India. The
other major industries are Pulp and paper, Milk processing, Slaughter house, and Poultry

Biogas in India has been around for a long time. In the 1970’s the country began a program
called the National Biogas and Manure Management Program (NBMMP) to deal with the same
problem — a gas shortage. The country did a great deal of research and implemented a wide
variety of ideas to help their people become more self-sufficient, regardless of the availability
of traditional gasoline and other fossil fuel based products.

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Plant Name Capacity (m3/day) Location

Green Elephant 25000 Satara ( Maharashtra)
Ashoka Biogreen Pvt. Ltd. 500 Talwade Village ( Maharashtra)
Nisargruna 6000 Karnataka
Bharat Biogas Energy Limited 5000 Anand district (Gujrat)
Green Planet Energy Pvt. Ltd. 600 Abohar (Punjab)

Only Hind Agro Industries Ltd, in India imports biogas mainly from Japan. As we see India
itself has abundance of biogas, the raw material for our current project is indigenously
available.

3.2.7.3 Prevailing prices

Cost of Biogas Rs 35/kg

Price of Catalyst - Rs 5980/ 500g of Cu/ZnO/Al2O3

3.2.7.4 Testing procedures for the raw material

There is no standard normative that describes the parameters to be considered and the
respective limits for the determination of biogas quality. The most important organization that
dedicates its attention to biogas, promoting the development of biogas markets, technologies,
and infrastructure, is American Biogas Council (ABC). Because commercial gas specifications
can vary considerably ABC has identified gas purity specifications and the related test methods
for renewable natural gas for vehicle application. Table 3 provides the parameters and limit
values suggested by this organization. It also reports the test methods (American standard test
methods) used to determine these values.

Property Specification Test Methods

Heating value (BTU/ft3) 940–1100 ASTM D1945/ASTM D7164

Carbon dioxide + nitrogen (mol%) max 4 ASTM D1945/ASTM D7164

Oxygen (mol%) max 1 ASTM D1945/ASTM D7164
Hydrogen (ppm) max 300 ASTM D1945/ASTM D7164
ASTM D4084/ASTM D6228/ASTM
Total sulfur (%mass) max 0.001 D4468/ASTM D5504/ASTM D7166
ASTM D4084/ASTM D6228/ASTM
D4468/ASTM
Hydrogen sulfide max 6 D5504/ASTM D7166

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Siloxanes (ppm) max 3 EPA TO-14/EPA TO-15

Liquids Commercial standard -

Dust particulate Commercial standard EPA Method 5
Chlorine additive Commercial standard -
Heavy metals Commercial standard -

Table 3

3.3 MATERIAL AND ENERGY FLOW INFORMATION

Assumption: Plant runs for 330 days a year and 24 hours a day.

As per back calculation, Biogas required is 3365 kg/hr i.e 2926 m3/hr.

Density of biogas: 1.15 kg/m3

Density of methanol: 792 kg/m3

Unit 1: Absorber Column

Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components Biogas Feed MDEA 1 MDEA out
Methane 1313.8351 0 1249.109 64.7261
H2S 4.4299 0 0.0834 4.3464
Nitrogen 18.3542 0 18.1365 0.2177
Hydrogen 2.6206 0 2.6041 0.0165
CO2 2025.3161 0 1228.7309 796.5853
MDEAmine 0 242.58 0 242.58
Total 3607.1359 3607.1359

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Unit 2: Compressor

Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 1 2
Methane 1249.109 1249.109
H2S 0.0834 0.0834
Nitrogen 18.1365 18.1365
Hydrogen 2.6041 2.6041
CO2 1228.7309 1228.7309
Total 2498.6666 2498.6666

Heat Flow (kJ/h) Molar Enthalpy (kJ/kgmol)

Inlet Stream 1 -16790000 -155900
Outlet Stream 2 -16190000 -150300
Q0 Qout-Qin 600000

Unit 3: Mixer

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Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components Steam 2 3
Methane 0 1249.109 1249.109
H2S 0 0.0834 0.0834
Nitrogen 0 18.1365 18.1365
Hydrogen 0 2.6041 2.6041
CO2 0 1228.7309 1228.7309
H2O 2810.3557 0 2810.3557
Total 5309.0196 5309.0196

Heat Flow (kJ/h) Molar Enthalpy (kJ/kgmol)

Inlet Stream Steam -42230000 -270700
2 -16190000 -150300
Outlet Stream 3 -58420000 -221500
Qout-Qin 0

Unit 4: Heater

Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 3 Reformer Feed
Methane 1249.109 1249.109
H2S 0.0834 0.0834
Nitrogen 18.1365 18.1365
Hydrogen 2.6041 2.6041
CO2 1228.7309 1228.7309
H2O 2810.3557 2810.3557
Total 5309.0196 5309.0196

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Heat Flow (kJ/h) Molar Enthalpy (kJ/kgmol)

Inlet Stream 3 -58420000 -221500
Reformer
Outlet Stream Feed -43180000 -163700
Q1 Qout-Qin 15240000

Unit 5: Reformer

Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components Reformer Feed Syngas 4
Methane 1249.109 45.4166 0
H2S 0.0834 0.0834 0
Nitrogen 18.1365 18.1365 0
Hydrogen 2.6041 405.21 0
CO2 1228.7309 1093.9824 0
H2O 2810.3557 1915.9764 0
CO 0 1562.1587 0
C 0 0 268.0556
Total 5309.0196 5309.0196

Reactions occurring in Reformer:

Reaction 1: CH4 + CO2 ↔ 2CO + 2H2

Reaction 2: 2CO ↔ CO2 + C

Reaction 3: CH4 + H2O ↔ CO + 3H2

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Heat Flow (kJ/h) Molar Enthalpy (kJ/kgmol)

Reformer
Inlet Stream Feed -43180000 -163700
Outlet Stream Syngas -29640000 -75710
4 363900 16300
Q2 Qout-Qin 13903900

Unit 6: Cooler

Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components Syngas 5
Methane 45.4166 45.4166
H2S 0.0834 0.0834
Nitrogen 18.1365 18.1365
Hydrogen 405.21 405.21
CO2 1093.9824 1093.9824
H2O 1915.9764 1915.9764
CO 1562.1587 1562.1587
Total 5040.964 5040.964

Heat Flow (kJ/h) Molar Enthalpy (kJ/kgmol)

Inlet Stream Syngas -29640000 -75710
Outlet Stream 5 -36580000 -93450
Q3 Qout-Qin -6940000

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Unit 7: Cooler

Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 5 6
Methane 45.4166 45.4166
H2S 0.0834 0.0834
Nitrogen 18.1365 18.1365
Hydrogen 405.21 405.21
CO2 1093.9824 1093.9824
H2O 1915.9764 1915.9764
CO 1562.1587 1562.1587
Total 5040.964 5040.964

Heat Flow (kJ/h) Molar Enthalpy (kJ/kgmol)

Inlet Stream 5 -36580000 -93450
Outlet Stream 6 -45360000 -115900
Q4 Qout-Qin -8780000

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Unit 8: Separator

Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 6 7 8
Methane 45.4166 45.4166 0
H2S 0.0834 0.0831 0.0003
Nitrogen 18.1365 18.1355 0.0009
Hydrogen 405.21 405.1989 0.0111
CO2 1093.9824 1092.6704 1.312
H2O 1915.9764 146.7835 1769.1929
CO 1562.1587 1562.1167 0.042
Total 5040.964 5040.9639

Unit 9: Compressor

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Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 7 9
Methane 45.4166 45.4166
H2S 0.0831 0.0831
Nitrogen 18.1355 18.1355
Hydrogen 405.1989 405.1989
CO2 1092.6704 1092.6704
H2O 146.7835 146.7835
CO 1562.1167 1562.1167
Total 3270.4047 3270.4047

Heat Flow (kJ/h) Molar Enthalpy (kJ/kgmol)

Inlet Stream 7 -17660000 -60230
Outlet Stream 9 -16680000 -56880
Q5 Qout-Qin 980000

Unit 10: Cooler

Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 9 10
Methane 45.4166 45.4166
H2S 0.0831 0.0831
Nitrogen 18.1355 18.1355
Hydrogen 405.1989 405.1989
CO2 1092.6704 1092.6704
H2O 146.7835 146.7835
CO 1562.1167 1562.1167
Total 3270.4047 3270.4047

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Heat Flow (kJ/h) Molar Enthalpy (kJ/kgmol)

Inlet Stream 9 -16680000 -56880
Outlet Stream 10 -17840000 -60830
Q6 Qout-Qin -1160000

Unit 11: Separator

Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 10 11 12
Methane 45.4166 45.4165 0
H2S 0.0831 0.0831 0
Nitrogen 18.1355 18.1355 0.0001
Hydrogen 405.1989 405.198 0.001
CO2 1092.6704 1092.5619 0.1084
H2O 146.7835 75.4634 71.3201
CO 1562.1167 1562.1131 0.0036
Total 3270.4047 3270.4047

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Unit 12: Mixer

Inlet Stream
Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 11 Recycle 13
Methane 45.4165 672.7885 718.2051
H2S 0.0831 0.3926 0.4756
Nitrogen 18.1355 270.791 288.9256
Hydrogen 405.198 1094.3493 1499.5462
CO2 1092.5619 2661.1263 3753.4229
H2O 75.4634 1.2647 76.7281
CO 1562.1131 591.8659 2153.9771
Methanol 0 54.3258 54.3258
8545.8756 8545.6064

Heat Flow (kJ/h) Molar Enthalpy (kJ/kgmol)

Inlet Stream 11 -16720000 -57800
Recycle -29740000 -43870
Outlet Stream 13 -46460000 -48040
Qout-Qin 0

Unit 13: Heater

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Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 13 14
Methane 718.2051 718.2051
H2S 0.4756 0.4756
Nitrogen 288.9256 288.9256
Hydrogen 1499.5462 1499.5462
CO2 3753.4229 3753.4229
H2O 76.7281 76.7281
CO 2153.9771 2153.9771
Methanol 54.3258 54.3258
Total 8545.6064 8545.6064

Heat Flow (kJ/h) Molar Enthalpy (kJ/kgmol)

Inlet Stream 13 -46460000 -48040
Outlet Stream 14 -45280000 -46820
Q7 Qout-Qin 1180000

Unit 14: Compressor

Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 14 15
Methane 718.2051 718.2051
H2S 0.4756 0.4756
Nitrogen 288.9256 288.9256
Hydrogen 1499.5462 1499.5462
CO2 3753.4229 3753.4229
H2O 76.7281 76.7281
CO 2153.9771 2153.9771
Methanol 54.3258 54.3258
Total 8545.6064 8545.6064

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Heat Flow (kJ/h) Molar Enthalpy (kJ/kgmol)

Inlet Stream 14 -45280000 -46820
Outlet Stream 15 -42670000 -44120
Q8 Qout-Qin 2610000

Unit 15: Heat Exchanger

Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 15 17 16 19
Methane 718.2051 718.2051 718.2051 718.2051
H2S 0.4756 0.4756 0.4756 0.4756
Nitrogen 288.9256 288.9265 288.9256 288.9265
Hydrogen 1499.5462 1172.3922 1499.5462 1172.3922
CO2 3753.4229 2969.0799 3753.4229 2969.0799
H2O 76.7281 397.9027 76.7281 397.9027
CO 2153.9771 630.2556 2153.9771 630.2556
Methanol 54.3258 2368.5711 54.3258 2368.5711
Total 8545.6064 8545.6064 8545.6064 8545.6064

Heat Flow (kJ/h) Molar Enthalpy (kJ/kgmol)

Inlet Stream 15 -42670000 -44120
17 -46550000 -56590
Outlet Stream 16 -41690000 -43110
19 -47530000 -57780
Q8 Qout-Qin 0

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Unit 16: Heater

Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 16 Methanol Reactor Feed
Methane 718.2051 718.2051
H2S 0.4756 0.4756
Nitrogen 288.9256 288.9256
Hydrogen 1499.5462 1499.5462
CO2 3753.4229 3753.4229
H2O 76.7281 76.7281
CO 2153.9771 2153.9771
Methanol 54.3258 54.3258
Total 8545.6064 8545.6064

Heat Flow (kJ/h) Molar Enthalpy (kJ/kgmol)

Inlet Stream 16 -41690000 -43110
Methanol
Outlet Stream Reactor Feed -40010000 -41370
Q9 Qout-Qin 1680000

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Unit 17: Methanol Reactor

Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components Methanol Reactor Feed 17 18
Methane 718.2051 718.2051 0
H2S 0.4756 0.4756 0
Nitrogen 288.9256 288.9265 0
Hydrogen 1499.5462 1172.3922 0
CO2 3753.4229 2969.0799 0
H2O 76.7281 397.9027 0
CO 2153.9771 630.2556 0
Methanol 54.3258 2368.5711 0
Total 8545.6064 8545.8087

Heat Flow (kJ/h) Molar Enthalpy (kJ/kgmol)

Methanol
Inlet Stream Reactor Feed -40010000 -41370
Outlet Stream 17 -46550000 -56590
Q10 Qout-Qin -6540000

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Unit 18: Cooler

Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 19 20
Methane 718.2051 718.2051
H2S 0.4756 0.4756
Nitrogen 288.9265 288.9265
Hydrogen 1172.3922 1172.3922
CO2 2969.0799 2969.0799
H2O 397.9027 397.9027
CO 630.2556 630.2556
Methanol 2368.5711 2368.5711
Total 8545.6064 8545.6064

Heat Flow (kJ/h) Molar Enthalpy (kJ/kgmol)

Inlet Stream 19 -47530000 -57780
Outlet Stream 20 -56710000 -68940
Q11 Qout-Qin -9180000

Unit 19: Separator

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Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 20 21 22
Methane 718.2051 716.4771 1.728
H2S 0.4756 0.4232 0.0524
Nitrogen 288.9265 288.2195 0.707
Hydrogen 1172.3922 1171.7355 0.6568
CO2 2969.0799 2846.0217 123.0581
H2O 397.9027 1.3639 396.5388
CO 630.2556 629.7026 0.553
Methanol 2368.5711 57.957 2310.6141
Total 8545.6064 8545.6064

Unit 20: Tee

Inlet Stream
Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 21 Purge 23
Methane 716.4771 45.5348 670.9423
H2S 0.4232 0.0269 0.3963
Nitrogen 288.2195 18.3174 269.902
Hydrogen 1171.7355 74.4682 1097.2672
CO2 2846.0217 180.8755 2665.1463
H2O 1.3639 0.0867 1.2772
CO 629.7026 40.02 589.6826
Methanol 57.957 3.6834 54.2736
Total 5711.9005 5711.9005

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Unit 21: Turbine

Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 22 24
Methane 1.728 1.728
H2S 0.0524 0.0524
Nitrogen 0.707 0.707
Hydrogen 0.6568 0.6568
CO2 123.0581 123.0581
H2O 396.5388 396.5388
CO 0.553 0.553
Methanol 2310.6141 2310.6141
Total 2833.9082 2833.9082

Heat Flow (kJ/h) Molar Enthalpy (kJ/kgmol)

Inlet Stream 22 -24940000 -256000
Outlet Stream 24 -24968766.01 -256353.0066
Q12 Qout-Qin -28766.00576

Unit 23: Separator

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V103 Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 24 25 26
Methane 1.728 1.714 0.0139
H2S 0.0524 0.0362 0.0163
Nitrogen 0.707 0.7013 0.0058
Hydrogen 0.6568 0.6557 0.0011
CO2 123.0581 105.6378 17.4203
H2O 396.5388 0.249 396.2899
CO 0.553 0.5515 0.0016
Methanol 2310.6141 10.3352 2300.2789
Total 2833.9082 2833.9082

Unit 24: Distillation Column

Inlet Stream Mass Flow (kg/h) Outlet Stream Mass Flow (kg/h)
Components 26 Pure Methanol 28
Methane 0.0139 0.0139 0
H2S 0.0163 0.0163 0
Nitrogen 0.0058 0.0058 0
Hydrogen 0.0011 0.0011 0
CO2 17.4203 17.4203 0
H2O 396.2899 5.5435 390.7464
CO 0.0016 0.0016 0
Methanol 2300.2789 2277.265 23.0139
Total 2714.0278 2714.0278

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dc Heat Flow (kJ/h) Molar Enthalpy (kJ/kgmol)

Inlet Stream 26 -23910000 -253900
Pure
Outlet Stream Methanol -17380000 -242100
28 -6255000 -279100
Qout-Qin 280000
Qr 5991000
Qc 5711000
-280000

3.4 DETAILED DESIGN OF EQUIPMENT

3.4.1 Process Design of all major equipment

1. Absorber Column

Step 1: Absorption Column Diameter

𝑘𝑚𝑜𝑙
Feed gas rate, G1 = 130 ℎ

Feed concentration, y1 = 0.001

𝑦
Solute free mole fraction ratio for feed, 𝑌1 = (1−𝑦1 ) = 0.001
1

𝑘𝑚𝑜𝑙
Feed gas flow rate on solute free basis, Gs = G1 (1-y1) = 129.87 ℎ

𝑘𝑚𝑜𝑙
Molar flow of H2S gas entering = G1y1 = 0.13 ℎ

Assuming 99.99 % of H2S is absorbed,

𝑘𝑚𝑜𝑙
H2S absorbed = 0.9999 x H2S gas entering = 0.13 ℎ

𝑘𝑚𝑜𝑙
Molar flow of H2S leaving = 0.0 ℎ

Y2 = Moles of H2S leaving / Gs = 0.0

𝑌2
𝑦2 = =0
(1 + 𝑌2 )

From reference,

Equilibrium line equation: Y = 0.067 X ---- Eq 1.

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Which implies M = 0.067

X1 = Y1 / M = 0.0149 (Using eq 1)

X2 = 0 (Solvent is pure)

Material Balance for non-solute,

Gs (Y1 - Y2) = Ls (X1 - X2)

Where Ls = solute free liquid flowrate

𝑘𝑚𝑜𝑙
Ls min = 8.7 ℎ

𝑘𝑚𝑜𝑙
Now actual liquid rate = Ls = 1.25 x Ls min = 10.87 ℎ

Liquid flow rate at the bottom of the tower,

𝑘𝑚𝑜𝑙
L1 = Ls + H2S absorbed = 11.005 ℎ

Step 2: Calculation of Column Diameter

𝑘𝑔
Density of gas, ρg = 6.159 𝑚3 (Ref. Aspen Properties)

𝑘𝑔
Density of liquid inlet, ρl = 1074 𝑚3 (Ref. Aspen Properties)

𝐿1 𝜌𝑔
Flow parameter = 𝐹𝐿𝑉 = ∗ √ 𝜌 = 0.0064
𝑉1 𝑙

𝑁
Surface tension of inlet gas, σ = 0.0158 𝑚

Tray Spacing = 0.45 m (Assumption)

From Fig. 11.27 Pg 585 Coulson-Richardson

K1 = 0.08

Modified K1 = K1 (σ/0.02)0.2 = 0.07631

2 𝜌𝑙 −𝜌𝑣 𝑚
Flooding Velocity 𝑢𝑓 = 𝑘1 ∗ √ = 1.004
𝜌𝑣 𝑠

Design for 80% flooding

𝑚
Uf = 0.8 * uf = 0.803 𝑠

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𝑚3
Volumetric flow rate of gas = 0.1517 (From Aspen Properties)
𝑠

Volumetric flow rate

Active tray area, Aa = Operating velocity (uf) = 0.188 m2

Fraction downcomer = Fd = 0.2

Tower Cross-section Area, At = Aa/ (1 - Fd) = 0.2359 m2

Tower Diameter, Dc = 0.548 m

Step 3: Calculation of Column Height

Kxa = 1.25 (kmol/m3.s).Δx

Kya = 0.075(kmol/m3.s).Δx

Number of trays, using Kremser equation

𝐿
Where, A = 𝑚𝐺𝑠 = 1.249 (m = slope of operating line)
𝑠

N = 34

Taking, Plate efficiency = 80%

Actual number of plates, Np = N/0.8 = 42

Slope of tie line = -Kxa/Kya = -16.66

Tie line drawn between a point on operating line to equilibrium line of above slope to get
corresponding (xi , yi) values

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y area term
0 1.00033

0.00134 1.00162

0.00267 1.00291

0.00399 1.00419

0.00530 1.00547

0.00661 1.00675

0.00791 1.00803

0.00921 1.00931

0.01049 1.01058

0.01178 1.01186

0.01305 1.01313

0.01432 1.01440

0.01558 1.01567

0.01683 1.01694

0.01808 1.01820

0.01932 1.01946

Now graph between F(y) vs y is plotted and area under the curve is calculated using trapezoidal
rule.

Ntg = Area under curve = 15

𝑘𝑚𝑜𝑙
Average molar flow rate of gas stream = (G1 + G2 )/2 = 550.614 ℎ

⸫Height of gas phase transfer unit = Htg = G/Kya = 0.615

Height of tower, h = Htg * Ntg = 9.316 m

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 Methanol Production From Biogas

2. Heat Exchanger: E-106

Properties of Hot and Cold Fluid

Hot Fluid

Properties Unit Values

Inlet Temperature K 540
Outlet Temperature K 530
Mass flow rate Kg/hr To be calculated
Viscosity Pa.s 1.8x10-4
Specific Heat Capacity (Cp) kJ/kg.K 4.539
Density (ρ) kg/m3 26.62
Thermal Conductivity (k) W/m.K 0.05664

Cold Fluid

Properties Unit Values

Inlet Temperature K 473
Outlet Temperature K 523
Mass flow rate Kg/hr 8546
Viscosity Pa.s 1.56x10-5
Specific Heat Capacity (Cp) kJ/kg.K 3.584
Density (ρ) kg/m3 14.88
Thermal Conductivity (k) W/m.K 0.16775

Step 1. Fluid Allocation

Shell Side: Process gas

Tube Side: High Pressure Steam

From energy balance,

𝑘𝑔
Shell side mass flow rate = 8546 ℎ

𝑚𝑐𝑜𝑙𝑑 ×𝐶𝑝𝑐𝑜𝑙𝑑 ×𝛥𝑇𝑐𝑜𝑙𝑑 𝑘𝑔

Tube side mass flow rate = = 33738.918
𝐶𝑝ℎ𝑜𝑡 ×∆𝑇ℎ𝑜𝑡 ℎ

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 Methanol Production From Biogas

Step 2. Log mean temperature difference

Assuming counter current flow,

LMTD =

= 33.06 oC

R= = 0.2

S = = 0.74

Ft = 0.95 (Ref. Fig 12.20, Coulson & Richardson, Pg – 658)

Corrected LMTD = Ft * LMTD = 31.409

Step 3. Tubes Specification

Choose tubes of following dimensions

Outer diameter = 16 mm

Inner diameter = 12.8 mm

Length = 6.096 m

Effective length = 6.096 – 2 * 0.025 = 6.08 m

𝑊
Assume overall heat transfer coefficient = U = 65 𝑚2 𝐾

Area required = Heat duty / (U*Corrected LMTD) = 750.12 m2

Surface Area of one tube = π..do.Leff = 0.3054 m2

Number of tubes = Area required / Area of one tube = 2455

Number of passes = 8

Pitch = Triangular

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Step 4. Tube Side Velocity

k1 = 0.365 (Ref. Fig 12.4, Coulson & Richardson, Pg-649)

n1 = 2.675 (Ref. Fig 12.4, Coulson & Richardson, Pg-649)

Bundle diameter (Db) = = 1.02 m

Bundle clearance = 0.06 m (Ref. Fig 12.10, Coulson & Richardson, pg-646)

Shell Diameter (Ds) = Db + Clearance = 1.08 m

Tube per pass = Nt / 4 = 306.96

Tube flow area = = 0.04072 m2

𝑚
Tube velocity = Mass flow rate / (Tube flow area * ρ * 3600) = 8.64 𝑠

(Tube velocity acceptable between 5 – 10 m/s)

L/D = 5.625 (Acceptable between 5-10)

Step 5. Tube Side Heat Transfer Coefficients

Re = ρvd/μ = 16620.92

Pr = μCp/k = 14.425

jH = 0.004 (Ref. Fig 12.24, Coulson & Richardson, pg-668)

𝑘𝑗𝐻𝑅𝑒𝑃𝑟 0.33 𝑊
h = = 698.88 𝑚2 𝐾
𝑑𝑖

Step 6. Shell Side Heat Transfer Coefficient

Lb (baffle spacing) = Ds*Bc = 0.216 m

Assume, Baffle cut ,Bc = 0.2

Tube pitch (Pt) = 1.25*do = 0.02 m

Cross-flow Area, As = = 0.0467 m2

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 Methanol Production From Biogas

Re =

𝑚
𝑠ℎ𝑒𝑙𝑙 .𝑑𝑒
= 3600×𝐴 = 3.74 x 104
𝑠𝜇

de =

= 0.01136 m

𝜇𝐶𝑝
Pr = = 0.32
𝑘

jH = 0.0045 (Ref. Fig 12.31, Coulson & Richardson, pg-711)

𝑗𝐻𝑅𝑒𝑃𝑟 𝑜.33 𝑘
hoc = 𝑑𝑜

= 1.71 x 103 W/m2

Fn (Tube row correction factor)

Pt` = 0.87Pt

Baffle cut ht. (Hc) = Baffle cut * Ds

= 0.215 m

Height between tips = Ds- 2*Hc

= 0.64 m

Ncr = Height b/w tips /Pt` = 37.26

Fn = 1.05 (Ref. Fig 12.32, Coulson & Richardson, pg-712)

Fw (Window correction factor)

𝐷𝑏
Hb = − 𝐷𝑠 × (0.5 − 𝐵𝑎𝑓𝑓𝑙𝑒 𝐶𝑢𝑡)
2

= 0.186 m

𝐻
Bundle cut = 𝐷𝑏 = 0.1823
𝑏

Ra’ = 0.13 (Ref. Fig 12.41, Coulson & Richardson, pg-721)

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θb = 1.84 (Ref. Fig 12.41, Coulson & Richardson, pg-721)

Nw (Tubes in one window area)

= θb*Ra`= 319

Nc (Tubes in cross flow) = Nt – 2*Nw = 1817

2∗𝑁𝑤
Rw = = 0.26
𝑁𝑡

Fw = 1.1 (Ref. Fig 12.33, Coulson & Richardson, pg-713)

Fb (By pass correction factor)

Ab= (Ds-DB)*LB

= 0.01296 m2

𝐴𝑏
= 0.277
𝐴𝑠

𝐴 2𝑁 1
Fb = exp[−𝛼. 𝐴𝑏 . (1 − 2 × (𝑁 𝑠 )3 ]
𝑠 𝑐𝑣

Without sealing strips , Ns = 0

Fb = 0.68 > 0.6 (Acceptable)

α = 1.35 for turbulent flow

Fb = 0.8631 (should be >0.85)

⇒FL (Leakage correction factor)

Ct = 0.0008 m (Table 12.5, Coulson & Richardson)

Cs = 0.0016 m (Table 12.5, Coulson & Richardson)

(𝑁𝑡 −𝑁𝑤 )
Atb = 3.14. 𝐶𝑡 . 𝐷𝑜 . 2

= 0.0429 m2

θb = 1.84 (Ref From Fig 12.41, Coulson & Richardson)

6.28−𝜃𝑏 )
Asb = 𝐶𝑠 . 𝐷𝑠 . ( 2

= 0.00383 m2

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Al = Atb + Asb

= 0.04677 m2

𝐴𝑙
= 1.001
𝐴𝑠

βL = 0.52 (Ref From Fig 12.35, Coulson & Richardson)

𝐴𝑡𝑏 +2𝐴𝑠𝑏
FL = 1 − 𝛽𝐿 [ ] = 0.4373
𝐴𝐿

Shell side HTC

hs = hoc*FL*FB*Fw*Fb

𝑊
= 593 𝑚2 𝐾

Step 7. Overall HTC

1 1 𝑑 𝑑 𝑑 𝑙
= ℎ + 2𝐾𝑜 ln ( 𝑑𝑜 ) + 𝑑 𝑜ℎ
𝑈 𝑖 𝑤 𝑖 𝑖 𝑖

𝑊
U = 74.90 𝑚2 𝐾

74.90−60
Error % = × 100
60

= 15.24% (less than 30% acceptable)

Step 8. Tube Side Pressure drop

𝐿 𝜌𝑢𝑡2
∆𝑃𝑡 = [𝑁𝑝 [8. 𝑗𝐹 ( ) + 2.5]
𝑑𝑖 2

= 34750.24 Pa = 5.04 psi < 10 psi (Acceptable)

Step 9. Shell Side Pressure Drop

𝑢𝑠2
Ideal tube bank pressure drop, ΔPi = 8𝑗𝐹 𝑁𝑐𝑣 𝜌 2

𝐺𝑠 𝑚
us = 𝐴 = 3.414
𝑠 𝜌×3600 𝑠

ΔPi = 116.371 Pa

Bypasss Correction factor for pressure drop

α = 4.0 for turbulent flow

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 Methanol Production From Biogas

𝐴𝑏 2𝑁𝑠 1
Fb` = exp[−𝛼. . (1 − 2 × ( )3 ] = 0.329
𝐴𝑠 𝑁𝑐𝑣

βL` = 0.7 (Ref pg 718, Coulson & Richardson)

𝐴𝑡𝑏 +2𝐴𝑠𝑏
FL` = 1 − 𝛽𝐿 ` [ ] = 0.242
𝐴𝐿

Pressure drop for cross flow zone = ΔPc = ΔPi. Fb`. FL`

Window-Zone pressure drop

𝐻𝑏
Nwv = No. of tube rows = = 10.69 ~ 11
𝑃𝑡`

𝜋 𝜋𝑑𝑜2
Aw = 4 𝐷𝑠2 × 𝑅𝑎 − 𝑁𝑤 × = 0.05505
4

𝐺𝑠 𝑚
uw = 𝐴 = 2.89 414
𝑤 𝜌×3600 𝑠

𝑚
uz = √𝑢𝑤 𝑢𝑠 =3.145 414 𝑠

𝜌𝑢𝑧2
ΔPw = [𝐹𝐿` [2 + 0.6. 𝑁𝑤𝑣 ] =150.332 Pa
2

End Zone Pressure drop

𝑁𝑤𝑣 +𝑁𝑐𝑣
ΔPc = ∆𝑃𝑖 × [ ] × 𝐹𝑏` = 14735.47 Pa
𝑁𝑐𝑣

Total shell-side pressure drop

𝐿
Nb = no. of baffles = 𝑙 − 1 = 27.12
𝐵

ΔPs = 2ΔPe + ΔPc(Nb – 1) + NbΔPw = 33792.06 Pa = 4.901 (<7 psi Acceptable)

3. Distillation Column
Step 1: Calculation of no. of stages
𝑘𝑚𝑜𝑙𝑒
Feed rate = 94.19 ℎ𝑟
𝑘𝑚𝑜𝑙𝑒
Distillate rate = 71.78 ℎ𝑟

Feed composition xf = 0.7622

Distillate composition xd = 0.9902
Bottoms composition xw = 0.032
By component balance : Fxf = Dxd + Wxw

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𝑘𝑚𝑜𝑙𝑒
W = 22.41
ℎ𝑟

Column Top pressure = 101.3 kPa

Feed temp =100oC
Feed Pressure = 101.3 kPa
The following is the bubble Pt. X-Y data for water-methanol system from the book ‘Separation
Techniques For Chemical Engineers’.
Bubble Pt. (oC) X1 Y1
100 0
0
99.42 0.0028 0.0153
93.76 0.0356 0.2181
90.36 0.0616 0.3068
87.08 0.095 0.4095
83.82 0.1286 0.4924
79.45 0.1986 0.5805
76.24 0.2841 0.653
73.05 0.4164 0.741
72.46 0.4814 0.7726
71.41 0.5235 0.785
69.35 0.6735 0.8572
67.10 0.8172 0.92
66.33 0.8594 0.9418
65.38 0.9341 0.9735
64.73 0.9869 0.9956

From Mc Cabe thiele Diagram

𝑥 𝑑
yintercept = 𝑅𝑚𝑖𝑛+1 =0.59

Rmin = 0.664
Ractual = 1.39* Rmin = 0.9229

Slope of top operating line = 0.6377

Slope of the bottom operating line = 1.140

q for feed = 1.005

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Slope of Feed line = q/(q-1) = 184.179

From graph, Number of stages= 12

𝑘𝑚𝑜𝑙𝑒
Vapour rate, 𝑉 = 𝐷(1 + 𝑅) = 130.03 ℎ

𝐿′
Slope of the bottom operating line 𝑉𝑚′ = 1.140
𝑚

𝑉𝑚 ʹ = 𝐿𝑚 ʹ − 𝐵, from which:

𝑘𝑚𝑜𝑙𝑒
Vapour flow below feed, Vmʹ = 134.191 ℎ

𝑘𝑚𝑜𝑙𝑒
Liquid flow below feed, Lmʹ = 152.60 ℎ

Step 2: Physical properties

Estimate base pressure, assume column efficiency of 60 per cent, and take reboiler as
equivalent to one stage.

12−1
Number of real stages = = 19
0.6

Assume 100 mm water, pressure drop per plate.

Column pressure drop = 100 x 0.001 x 1000 x 9.81 x 19 = 18639 Pa

Top pressure, 1 atm = 101.3 kPa

Estimated bottom pressure = Top pressure + Column Pressure drop= 119.939 kPa

From steam tables, base temperature 1000C

𝑘𝑔
ρv = 0.6817 𝑚3

𝑘𝑔
ρL = 958.36 𝑚3

Surface tension = 0.057 N/m

For Top Stream, 99% w/w methanol

𝑘𝑔
ρv = 0.31 𝑚3

ρL = 782 kg/m3

Surface tension 0.0218 N/m

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 Methanol Production From Biogas

Step 3: Column diameter:

0.6817
FLV bottom = 1.167 √958.36 = 0.0311

0.31
FLV top = 0.481 √ 782 = 0.0095

Take plate spacing as 0.5 m

From Figure 11.27 of Coulson & Richardson, base𝐾1 = 0.095 ; top 𝐾1 = 0.087

Applying correction for surface tensions

0.0218 0.2
Base 𝐾1 = 0.095 ∗ ( ) = 0.0966
0.02

0.0218 0.2
Top 𝐾1 = 0.087 ∗ ( ) = 0.0885
0.02

958.36−0.6817
Base 𝑈𝑓 = 0.0966√ = 3.622 𝑚/𝑠𝑒𝑐
0.6817

782−0.31
Top 𝑈𝑓 = 0.0885 √ = 4.44 𝑚/𝑠𝑒𝑐
0.31

Design for 85 per cent flooding at maximum flow rate

Base 𝑈𝑣′ = 0.85𝑈𝑓 = 3.079 𝑚/𝑠𝑒𝑐
Top 𝑈𝑣′ = 0.85𝑈𝑓 = 3.777 𝑚/𝑠𝑒𝑐
Maximum volumetric flow-rate
18.46∗134.191 𝑚3
Base = = 1.009
0.6817∗3600 s
32.05∗138.03 𝑚3
Top = = =3.964
0.31 𝑋 3600 s

Net area required

1.009
Bottom = 3.079 = 0.3278 m2
3.964
Top = = 1.049 m2
3.777

As first trial take down comer area as 12 per cent of total.

Column cross-sectioned area
0.3278
Base = = 0.3725 m2
0.88
1.049
Top = = 1.19 m2
0.88

Column diameter

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0.3725∗4
Base = √ = 0.688 m
𝜋

1.19∗4
Top = √ = 1.232 m
𝜋

Use same diameter above and below feed, reducing the perforated area for plates above the
feed.
Hence Column Diameter = 1.232 m

Step 4:Liquid flow pattern

156.601∗18.46
Maximum volumetric liquid rate = = 8.37 ∗ 10−4 𝑚3
3600∗958.36

From Figure 11.28 Coulson & Richardson, liquid flow patter = Reverse Flow
Provisional plate design
Column diameter Dc = 1.232 m
1.2322
Column area Ac = 𝜋 ∗ = 1.192 m2
4

Down comer area 𝐴𝑑 = 0.12 ∗ 1.192 = 0.1430 𝑚2 , at 12 per cent

Net area 𝐴𝑁 = 𝐴𝑐 − 𝐴𝑑 = 1.049 𝑚2
Active area 𝐴𝑎 = 𝐴𝑐 − 2𝐴𝑑 = 0.9061 𝑚2
Hole area, 𝐴𝐻 taken as 10 per cent of 𝐴𝑎 as first trial = 0.09061 m2
Weir length, Lw (from Figure 11.31 28 Coulson & Richardson) = 0.77 ∗ 1.232 = 0.9489 𝑚
Take weir height 50 mm
Hole diameter 5 mm
Plate thickness 5 mm

Check weeping
18.46∗156.601
Maximum liquid rate = 3600
= 0.803 𝑘𝑔/𝑠𝑒𝑐

Minimum liquid rate, at 70 per cent turn-down 0.7 ∗ 0.803 = 0.5621 𝑘𝑔/𝑠𝑒𝑐
2
0.803 3
Maximum ℎ𝑜𝑤 = 750 ( 0.9489∗958.36) = 6.902 𝑚𝑚 𝑙𝑖𝑞𝑢𝑖𝑑
2
0.5621 3
Minimum ℎ𝑜𝑤 = 750 (0.9489∗958.36 ) = 5.44 𝑚𝑚 𝑙𝑖𝑞𝑢𝑖𝑑

At minimum rate ℎ𝑤 + ℎ𝑜𝑤 = 50 + 5.44 = 55.44 𝑚𝑚 𝑙𝑖𝑞𝑢𝑖𝑑

From figure 11.30 Coulson & Richardson, k2 = 30.3

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𝑘2 − 0.9(25.4 − 𝑑ℎ )
𝑢ℎ (𝑚𝑖𝑛) = [ 1 ] = 14.461 𝑚/𝑠𝑒𝑐
2
𝜌𝑣
𝑚𝑖𝑛𝑖𝑚𝑢𝑚 𝑣𝑎𝑝𝑜𝑟 𝑟𝑎𝑡𝑒
Actual minimum vapor velocity = 𝐴ℎ
0.7∗3.964
= = 30.62 𝑚/𝑠𝑒𝑐 (> 𝑢ℎ 𝑚𝑖𝑛, no weeping)
0.09061

So minimum operating rate will be well above weep point.

Step 5: Plate pressure drop
Dry plate drop
Maximum vapour velocity through holes
3.964
𝑢ℎ′ = = 43.74 𝑚/𝑠𝑒𝑐
0.0906
From Figure 11.34 Coulson & Richardson, for plate thickness/hole dia. = 1,
𝐴 𝐴
and, 𝐴ℎ ≈ 𝐴ℎ = 0.1
𝑝 𝑎

𝐶𝑜 = 0.84
43.74 2 0.6817
ℎ𝑑 = 51 ( ) = 98.38 𝑚𝑚 𝑙𝑖𝑞
0.84 958.36
Residual head
103
ℎ𝑟 = 12.5 ∗ = 13.04 𝑚𝑚 𝑙𝑖𝑞
958.36
Total plate pressure drop
ℎ𝑟 = 13.04 + 98.38 + 55.44 + 6.90 = 173 𝑚𝑚 𝑙𝑖𝑞

Note: 100 mm was assumed to calculate the base pressure. The calculation could be repeated
with a revised estimate but the small change in physical properties will have little effect on the
plate design. 173 mm per plate is considered acceptable.

Step 6:Down comer liquid back-up

Down comer pressure loss
Take ℎ𝑎𝑝 = ℎ𝑤 − 10 = 40 𝑚𝑚
Area under apron, 𝐴𝑎𝑝 = 0.6 ∗ 40 ∗ 0.001 = 0.024 𝑚2
As this is less than 𝐴𝑑 = 0.143 𝑚2 use 𝐴𝑎𝑝 in equation 11.92
0.803 2
ℎ𝑑𝑐 = 166 (958.36 𝑋 0.024) = 0.202 𝑚𝑚

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 Methanol Production From Biogas

Back-up in down comer

ℎ𝑏 = 174 + 13.04 + 6.90 + 50 ≈ 244 𝑚𝑚
1
∵ 0.244 < (𝑝𝑙𝑎𝑡𝑒 𝑠𝑝𝑎𝑐𝑖𝑛𝑔 + 𝑤𝑒𝑖𝑟 ℎ𝑒𝑖𝑔ℎ𝑡) = 0.275
2
Hence, plate spacing is acceptable
Step 7: Check residence time
0.143 ∗ 958.36 ∗ 244 ∗ 0.001
𝑇𝑟 = = 41.55 sec > 3𝑠 , 𝐴𝑐𝑐𝑒𝑝𝑡𝑎𝑏𝑙𝑒
0.803
Step 8: Check entrainment

3.964
𝑢𝑣 = = 3.77 𝑚/𝑠𝑒𝑐
1.04
3.77
% 𝑓𝑙𝑜𝑜𝑑𝑖𝑛𝑔 = 4.44 = 0.848 < 0.85 Assumed flooding ,

𝐹𝐿𝑉 = 0.0311, from figure 11.29,𝜙 = 0.07 well below 0.1

As the per cent flooding is well below the design figure of 85, the column diameter could be
reduced, but this would increase the pressure drop.

Step 9: Trial layout

Use cartridge-type construction. Allow 50 mm unperforated strip round plate edge; 50 mm

wide calming zones.

Perforated area

𝑙 1.169
From Figure 11.32, at 𝐷𝑤 = 1.518 = 0.77 𝛩𝑐 = 100𝑜
𝑐

Angle subtended by the edge of the plate = 180 − 100 = 800

(1.232−50∗0.001)𝜋 ∗ 80
Mean length, unperforated edge strips =
180

=1.650 𝑚

Area of unperforated edge strips = 50 ∗ 0.001 ∗ 1.650 = 0.0825 𝑚2

Mean length of calming zone, approx. = weir length + width of

unperforated strip

= 0.9489 + 50 ∗ 0.001 = 0.998 𝑚

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Area of calming zones = 2(0.998 ∗ 50 ∗ 0.001) = 0.0998 𝑚2

Total area for perforations,

𝐴𝑝 = 0.9061 − 0.0825 − 0.0998 = 0.7237 𝑚2

𝐴ℎ 0.0906
= = 0.125 𝑚2
𝐴𝑝 0.723

𝑙𝑝
From Figure 11.33 Coulson & Richardson , 𝑑 = 2.6 ; satisfactory,
ℎ

within 2.5 to 4.0.

Step 10:Number of holes

4 ∗ 0.090
𝑁ℎ = = 4616 ℎ𝑜𝑙𝑒𝑠
𝜋 ∗ 0.0052

4. Kettle Reboiler Design for Distillation Column

Step 1: Heat duty & Area required calculation

Process fluid will flow through shell side with flow rate = 413.8 kg/h

Reboiler Temperature = 92.240 𝐶

Operating Pressure = 1 bar
Latent Heat of Process Stream, 𝜆 = 2258 kJ/kg (Ref: Aspen Propeerties)
critical pressure, 𝑃𝑐 = 216.64 𝑏𝑎𝑟

𝑊
Assumed overall heat transfer coefficient, 𝑈 = 1200 𝑚2 .0 𝐶 (Ref: Table 12.1, Page 639, BCB)

Reboiler Duty, 𝑄𝑅 = 𝑀𝜆 = 259.60 𝐾𝑊

Adding 5% compensation for losses

𝑄𝑅′ = 1.05 ∗ 259.60 = 272.58 𝑘𝑊

(174.7 − 75) − (174.7 − 35)

Δ𝑇𝐿𝑛 = = 41.040 𝐶
174.7 − 75
𝐿𝑁 ( )
174.7 − 35

FT not used as only 1 side is non isothermal

𝑄
𝑟
Required heat transfer area, 𝐴 = 𝑈𝐴Δ𝑇 = 5.516 𝑚2

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Step 2:Tube Specification:

Internal Diameter of tube, 𝑑𝑖 = 21 𝑚𝑚

Outer Diameter of tube, 𝑑𝑖 = 25.4 𝑚𝑚

Length of Tube, 𝐿 = 6 𝑚

Assuming square pitch, 𝑃𝑡 = 31.75 𝑚𝑚

as OD>25 mm, Tube Sheet thickness= OD = 25.4 mm

Effective length of tube , 𝐿𝑒 = 𝐿 − 2 ∗ 0.0254 = 5.9746 𝑚

Area of one tube = 𝜋 ∗ 0.0254 ∗ 5.9746 = 0.4765 𝑚2

𝐴
Number of Tube, 𝑁𝑡 = 0.5 ∗ 𝑎𝑟𝑒𝑎 𝑜𝑓 𝑜𝑛𝑒 𝑡𝑢𝑏𝑒 ≈ 6

Number of Passes = 6

From appendix Table C.5, 𝑁𝑡 = 6 corresponding shell ID, is = 8 𝑖𝑛𝑐ℎ = 203.2 𝑚𝑚

Bundle diameter = 8 − 0.25 = 7.75 𝑖𝑛𝑐ℎ = 196.85 𝑚𝑚

Actual Heat Trasfer area, 2𝑁𝑡 𝜋 ∗ 𝑂𝐷 ∗ 𝐿𝑒 = 5.718 𝑚2

Step 3: Shell Side Heat Transfer Coefficient:

𝑃 0.17 𝑃 1.2 𝑃 10
ℎ𝑛𝑏 = 0.104𝑃𝑐0.69 𝑞 0.7 [1.8 ( ) + 4 ( ) + 10 ( ) ]
𝑃𝑐 𝑃𝑐 𝑃𝑐

1000 𝑊
Where 𝑞 = 𝑄𝑅 ∗ = 4766.98 𝑚2
𝐴

𝑊
Therefore , ℎ𝑛𝑏 = 1165.30 𝑚2 .0 𝐶

Step 4: Tube Side Heat Transfer Coefficient:

𝑅𝑄 𝑘𝑔
Mass flow rate = 4.187Δ𝑇 = 1.627 sec

𝜋 8
Tube cross-sectional area = 4 ∗ (0.021)2 ∗ 6 = 0.00069 𝑚2

1.178 𝑚
Tube side velocity, 𝑢𝑡 = 993∗0.00858 = 2.36 𝑠𝑒𝑐 (Should be between 1.5-2.5 m/sec)

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Step 5:Overall Coefficient:

25.4
1 1 1 0.025 ln ( 21 ) 25.4 1 25.4 1
= + + + ∗ + ∗
𝑈 1205.9 6000 2 ∗ 50 21 6000 21 8356.55

𝑾
𝑼 = 𝟏𝟐𝟎𝟐. 𝟐𝟒
𝒎𝟐 . 𝟎 𝑪
𝑈𝑐𝑎𝑙𝑐𝑢𝑙𝑎𝑡𝑒𝑑 −𝑈𝐴𝑠𝑠𝑢𝑚𝑒𝑑
Error = × 100 = 0.13% , which is < 30%
𝑈𝐴𝑠𝑠𝑢𝑚𝑒𝑑

Hence, assumed value is acceptable

Step 6: Critical Heat Flux Calculation, qcb

𝑃𝑡 𝜆
𝑞𝑐𝑏 = 𝐾𝑏 × × [𝜎𝑔(𝜌𝐿 − 𝜌𝑣 )𝜌𝑣2 ]0.25
𝑑𝑜 √𝑁𝑡

𝑊
𝑞𝑐𝑏 = 14267.20
𝑚2

Using safety factor = 0.7

q = 0.7 x qcb = 9987

𝑊 𝑊
Flux calculated = 4766 𝑚2 < 9987 𝑚2 , Acceptable

Step 7: Kettle ID Calculation

𝐷𝑏′ = 𝐷𝑏 + 4"

𝜎 0.5 𝑘𝑔
𝑉𝐿 = 2290 × 𝜌𝑉 ( ) = 12.085 3
𝜌𝐿 − 𝜌𝑉 𝑚 .𝑠

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ℎ
= 0.05
𝐷𝑠

𝐷𝑏′ ℎ
=1− = 0.95
𝐷𝑠 𝐷𝑠

𝑚𝑣
𝑆𝐴 = = 1.59 × 10−3 𝑚3
𝐿 × 𝑉𝐿

𝐷𝑏′ = 7.75 + 4 = 11.75 𝑖𝑛𝑐ℎ = 298.45 𝑚𝑚

𝐷𝑏′
𝐷𝑠 = = 314.15 𝑚𝑚
0.6

𝑆𝐴′ = 𝐴 × 𝐷𝑠2 = 0.00144 𝑚2 (A from Appendix 10 A.h/D = 0.05)

`
𝑆𝐴 −𝑆𝐴
Error = × 100 = -8.98 % (<10% acceptable)
𝑆𝐴

Hence Kettle ID = 314.15 mm

5. Condenser for Distillation Column

Step 1: Calculation of Area Required

Mass flow rate of process stream = 2300 kg/h

Operating Pressure of Condenser = 1 bar

Saturation temp of the vapour entering the condenser = 32.810 𝐶

Condensation will be complete at, T = 32.810 𝐶

The average molecular weight of the vapours is = 32.05gm/mol

Latent heat of process stream, 𝜆 = ℎ𝑉 − ℎ𝐿

= 1155 kJ/kg

The temperature rise is to be limited to 100 𝐶

Tube Specification:

OD = 25 mm

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ID = 21.8 mm

L= 4.88 m (16 ft), of admiralty brass.

𝑀𝑎𝑠𝑠 𝐹𝑙𝑜𝑤 𝑟𝑎𝑡𝑒

Heat transferred from vapour = 3600×𝑙𝑎𝑡𝑒𝑛𝑡 ℎ𝑒𝑎𝑡 = 737.91 𝐾𝑊

𝐻𝑒𝑎𝑡 𝑡𝑟𝑎𝑛𝑠𝑓𝑒𝑟𝑟𝑒𝑑 𝑓𝑟𝑜𝑚 𝑣𝑎𝑝𝑜𝑢𝑟

Cooling water flow = = 17.65 kg/s
𝐶𝑝.𝛥𝑇

𝑊
Assumed overall coefficient, U = 1500 𝑚2 𝐾

(Ref: Table 12.1, Page 639, Coulson & Richardson)

𝑇1 − 𝑇2
𝑅= = 0.1
𝑡2 − 𝑡1

𝑡2 − 𝑡1
𝑆= = 0.724
𝑇1 − 𝑡1

𝐹𝑇 = 0.98

(Ref: Fig 12.19, page 657, Coulson & Richardson)

(33.81 − 30) − (32.81 − 20)

Δ𝑇𝐿𝑛 = = 7.4220 𝐶
(33.81 − 30)
𝐿𝑁 ( )
(32.81 − 20)

Δ𝑇𝐿𝑁 𝑡𝑟𝑢𝑒 = 𝐹𝑇 ∗ Δ𝑇𝐿𝑛 = 7.2730 𝐶

𝑇𝑟𝑖𝑎𝑙 𝑎𝑟𝑒𝑎 = 67.638 𝑚2

Surface area of one tube = 𝜋 ∗ 0.025 ∗ 4.88 = 0.2415 𝑚2 (ignore tube sheet thickness)

𝑇𝑟𝑖𝑎𝑙 𝑎𝑟𝑒𝑎
Number of tubes, 𝑁𝑡 = 𝑆𝑦𝑟𝑓𝑎𝑐𝑒 𝑎𝑟𝑒𝑎 𝑜𝑓 𝑜𝑛𝑒 𝑡𝑢𝑏𝑒 = 275.86

Assuming square pitch, 𝑝𝑡 = 1.25𝑑0 =0.2 m

Tube bundle diameter (Ref Eq. 12.3b and Table 12.4, Coulson & Richardson)

For 4 passes

1 1
𝑁𝑡 𝑁1 275 2.263
𝐷𝑏 = 𝑑0 ( ) = 0.025 ( ) = 0.433 𝑚
𝐾1 0.158

𝐷𝑏
Number of tubes in center row 𝑁𝑟 = ≈ 22
𝑝𝑡

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Step 2 : Shell-side coefficient:

Physical properties of Condensate:

𝑚𝑁𝑠 𝑘𝑔 𝑊
𝜇𝐿 = 0.486 ; 𝜌𝐿 = 782 𝑚3 ; 𝑘𝐿 = 0.1764 𝑚0 𝐶 (Ref: From Aspen Properties)
𝑚2

𝑘𝑔
Vapor density at mean temperature, 𝜌𝑉 = 0.31 𝑚3

𝑊𝑐 4073 1 𝑘𝑔
ΓH = = ∗ = 0.00047
𝐿𝑁𝑡 3600 4.88 ∗ 46 𝑠𝑒𝑐. 𝑚

2
𝑁𝑟′ = 3 ∗ 𝑁𝑟 =15

1
𝜌𝐿 (𝜌𝐿 − 𝜌𝑉 )𝑔 3 −16 𝑊
ℎ𝑐 = 0.926 ∗ 𝑘𝐿 [ ] 𝑁𝑟 = 3161.42 2 0
𝜇𝐿 Γ𝐻 𝑚 . 𝐶

Step 3: Tube-side coefficient:

𝜋 56
Tube cross-sectional area = 4 ∗ (0.0218)2 ∗ = 0.0088 𝑚2
2

Density of water, 𝜌𝑤 = 996 kg/m3

17.3
Tube side velocity, 𝑢𝑡 = = 1.99 m/s (Should be between 1.5-2.5 m/sec)
993∗0.00858

Tube side heat transfer coefficient

4200 ∗ (1.35 + 0.02 ∗ 82.64) ∗ 2.080.8 𝑊

ℎ𝑖 = = 8993.02
21.80.2 𝑚 2 .0 𝐶

(Ref: Eqn 12.17 Coulson & Richardson)

𝑊
Fouling factors: as neither fluid is heavily fouling, use 6000 𝑚2 .0 𝐶 for each side.

𝑊
Thermal conductivity of tube material, 𝑘𝑤 = 50 𝑚.0 𝐶

Step 4: Overall Coefficients:

25
1 1 1 0.025 ln (21.8) 25 1 25 1
= + + + ∗ + ∗
𝑈 3161 6000 2 ∗ 50 21.8 6000 21.8 8993

𝑾
𝑼 = 𝟏𝟓𝟐𝟎. 𝟒𝟗𝟗
𝒎𝟐 . 𝟎 𝑪

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Error in Overall Coefficient with respect to assumed U:

𝑈𝑜𝑏𝑡 − 𝑈𝑎𝑠𝑠𝑢
𝑒𝑟𝑟𝑜𝑟 = ∗ 100 ≈ 1.36%
𝑈𝑎𝑠𝑠𝑢

Close enough to estimate, firm up design

Step 5: Shell-side pressure drop:

Selected baffle spacing = shell diameter, 45 per cent cut.

From Figure 12.10 Coulson & Richardson, clearance = 88 mm.

Shell i.d., 𝐷𝑖 = 𝐷 + 2𝑥𝑐𝑙𝑒𝑎𝑟𝑎𝑛𝑐𝑒 = 0.52 𝑚

Use Kern’s method to make an approximate estimate

Cross-flow area, As

(𝑝𝑡 − 𝑑0 )𝐷𝑖 𝑙𝐵
𝐴𝑆 = = 0.0547 𝑚2
𝑝𝑡

Mass flow-rate, based on inlet conditions

4073 1 𝑘𝑔
𝐺𝑠 = ∗ = 11.66
3600 0.0296 𝑠. 𝑚2

1.27
Equivalent diameter, 𝑑𝑒 = (𝑝𝑡2 − 0.785𝑑02 ) = 0.0157 𝑚
𝑑0

𝑚𝑁𝑠
Shell side Vapour viscosity, 𝜇𝑣 = 0.008 𝑚2

𝜌𝑣𝑑 𝑑
Renolds Number, 𝑅𝑒 = = 𝐺𝑠 ∗ 𝜇 𝑖 = 0.23 ∗ 105
𝜇 𝐿

From Figure 12.30, 𝑗𝐹 = 0.05 (From fig 12.30 Coulson & Richardson)

𝐺 𝑚
Shell side velocity, 𝑢𝑠 = 𝜌𝑠 = 37.63 𝑠𝑒𝑐
𝑣

Taking pressure drop as 50 per cent of that calculated using the inlet flow; neglecting viscosity
correction.

1 𝐷𝑖 𝐿 𝑢𝑠2
Δ𝑃𝑆 = (8𝑗𝑓 ( ) ( ) 𝜌 ( )) = 13563.01 𝑃𝑎
2 𝑑𝑒 𝑙𝑏 2

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Step 6: Tube-side pressure drop:

Viscosity of water, 𝜇 = 0.6 𝑐𝑃

𝜌𝑣𝑑
Renolds Number, 𝑅𝑒 = = 42437
𝜇

From Figure 12.24 Coulson & Richardson, 𝑗𝐹 = 0.0035

Neglecting viscosity correction,

𝐿 𝜌𝑢𝑡2
Δ𝑃𝑡 = 𝑁𝑝 [ 8𝑗𝑓 ( ) + 2.5] = 104690.18 𝑃𝑎
𝑑𝑖 2

6. Process Design of Compressor K-100

Suction Temperature, Ts = 309.08 K

Suction Pressure, Ps = 485 kPa

Discharge Pressure, Pd = 2000 kPa

Pd
Compression Ratio, R = Ps

R = 4.123 < 5 (Single Stage)

Cp
Γ = Cv = 1.307

Pd (𝑟−1)/𝑟
Discharge Temperature, TD = Ts( Ps ) = 431.11 k

Pd Pd 1/𝑟
Volumetric efficiency (%) = 93− Ps −8× [( Ps ) − 1] =73.22

Molecular Weight of gas = 23.2 g

8.314
Universal gas constant, R= kJ/kg.K
23.2

Mass flow rate of gas, F = 2499 kg/hr

𝑟 Pd (𝑟−1)/𝑟
Work required (w) = R×Ts×𝑟−1 × [( Ps ) − 1] kJ/kg = 186.188 kJ/kg

Total Power required = W×F

= 129.24 kJ

= 173.18 BHP

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7. Process Design of Reformer

Catalyst specifications

Name: NiO/MgO

Particle size (dp) = .005 m

Particle density (𝜌) = 5310 kg/m3

Voidage (𝜀) = 0.42

ReformerTemperature = 950oC

Now, we will calculate minimum fluidization velocity

Density of gas = 3.907 kg/m3

ΔP in reformer = 30000 Pa

Step 1: Calculation of reactor height

Assuming Turbulent flow in reactor.

Using Burke Plummer equation

𝛥𝑝 1.75 𝜌𝑣 2 (1−𝜀)
=
𝐿 𝑑𝑝 𝜀 3

Pressure drop per unit length for a fluidized bed,

𝛥𝑝
= (𝜌𝑝 − 𝜌)𝑔(1 − 𝜀)
𝐿

For minimum fluidization velocity,

1.75 ∗𝜌∗𝑣𝑚𝑖𝑛2 (1−𝜀)

(𝜌𝑝 − 𝜌)𝑔(1 − 𝜀) = 𝑑𝑝 𝜀 3

1.75 ∗ 3.907 ∗ 𝑢𝑚𝑖𝑛2 ∗ (1 − 0.42)

(5310 − 3.907) ∗ 9.81 ∗ (1 − 0.42) =
0.005 ∗ 0.42 ∗ 0.42 ∗ 0.42

U min2 = 2.874 m /s

U min = 1.695 m/s

Assume velocity is less than minimum fluidization velocity to avoid fluidization.

Pressure drop in reformer = 30000 Pa

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𝛥𝑝 1.75 𝜌𝑣 2 (1−𝜀)
=
𝐿 𝑑𝑝 𝜀 3

30000 1.75 ∗ 3.907 ∗ 1.695 ∗ (1 − 0.42)

=
𝐿 0.005 ∗ 0.42 ∗ 0.42 ∗ 0.42

𝐿 = 1.752 m

Step 2: Calculation of Residence Time

Outer diameter (do) = 0.113 m [Ullman’s 2011, pg-175]

Inner diameter (di) = 0.1057 m [Ullman’s 2011, pg-175]

Heat to be transferred = 1.392 * 107 kJ / h

=3.866 * 106 J/s

𝑊
Overall HTC = 350 𝑚2 𝐾

Heat transfer area of 1 tube = 3.14*Do2

Coolant inlet temp =298K

Coolant outlet temp = 473K

Q = N * Heat transfer area of 1 tube * U * LMTD

N = 794.46≈ 796 (Take no. of tube in multiple of 4)

Total volume of tube = N * π/4 * (di) 2 * L

= 12.227 m3

Volumetric flow rate = 1359 m3/hr

= 22.65 m3/min

𝑇𝑜𝑡𝑎𝑙 𝑣𝑜𝑙𝑢𝑚𝑒 𝑜𝑓 𝑡𝑢𝑏𝑒

τ = 𝑉𝑜𝑙𝑢𝑚𝑒𝑡𝑟𝑖𝑐 𝑓𝑙𝑜𝑤 𝑟𝑎𝑡𝑒

12.227
τ= = 0.5398 min
22.65

τ = 32.391 sec

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8. Process Design of Methanol Reactor

Catalyst specifications

Name: Cuo/ZnO/Al2O3

Particle size (dp) = .006

Particle density (𝜌) = 1741 kg/m3

Voidage (𝜀) = 0.387

ReformerTemperature = 250oC

Now, we will calculate minimum fluidization velocity

Density of gas = 14.01 kg/m3

ΔP in reformer = 80000 Pa

Step 1: Calculation of reactor height

Assuming Turbulent flow in reactor.

Using Burke Plummer equation

𝛥𝑝 1.75 𝜌𝑣 2 (1−𝜀)
=
𝐿 𝑑𝑝 𝜀 3

Pressure drop per unit length for a fluidized bed,

𝛥𝑝
= (𝜌𝑝 − 𝜌)𝑔(1 − 𝜀)
𝐿

For minimum fluidization velocity,

1.75 ∗𝜌∗𝑣𝑚𝑖𝑛2 (1−𝜀)

(𝜌𝑝 − 𝜌)𝑔(1 − 𝜀) = 𝑑𝑝 𝜀 3

1.75 ∗ 14.01 ∗ 𝑢𝑚𝑖𝑛2 ∗ (1 − 0.42)

(1741 − 14.01) ∗ 9.81 ∗ (1 − 0.42) =
0.006 ∗ 0.3873

Umin2 = 0.244 m /s

Umin = 0.4949 m/s

Assume velocity is less than minimum fluidization velocity to avoid fluidization.

Pressure drop in reformer = 80000 Pa

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𝛥𝑝 1.75 𝜌𝑣 2 (1−𝜀)
=
𝐿 𝑑𝑝 𝜀 3

30000 1.75 ∗ 14.01 ∗ 0.4949 ∗ (1 − 0.387)

=
𝐿 0.006 ∗ 0.3873

𝐿 = 4.628 m

Step 2: Calculation of Residence Time

Outer diameter (do) = 0.12 m [Ullman’s 2011, pg-175]

Inner diameter (di) = 0.09 m [Ullman’s 2011, pg-175]

Heat to be transferred = 6.545 * 106 kJ / h

=1.8180 * 106 J/s

𝑊
Overall HTC = 350 𝑚2 𝐾

Heat transfer area of 1 tube = 3.14*Do2

Coolant inlet temp =298K

Coolant outlet temp = 473K

Q = N * Heat transfer area of 1 tube * U * LMTD

N = 153.19≈ 156 (Take no. of tube in multiple of 4)

Total volume of tube = N * π/4 * (di) 2 * L

= 4.59 m3

Volumetric flow rate = 609.9 m3/hr

= 10.166 m3/min

𝑇𝑜𝑡𝑎𝑙 𝑣𝑜𝑙𝑢𝑚𝑒 𝑜𝑓 𝑡𝑢𝑏𝑒

τ = 𝑉𝑜𝑙𝑢𝑚𝑒𝑡𝑟𝑖𝑐 𝑓𝑙𝑜𝑤 𝑟𝑎𝑡𝑒

12.227
τ= = 0.4515 min
22.65

τ = 27.09 sec

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9. Turbine Design K-103

Mass flow rate of gas, F = 0.7872 kg /s

Inlet temperature, Ti = 298 K

Inlet pressure, Pi = 6962 kPa

Outlet pressure, Pout = 101.3 kPa

Pout
Turbine pressure ratio = = 0.014
Pi

𝐶𝑝
Specific heat ratio, r = = 1.224
𝐶𝑣

PD (𝑟−1)/𝑟
Discharge Temp. = Ti× ( Ps ) = 294 K

Specific heat, Cp = 3.579 kJ/kg.K

Pout (𝑟−1)/𝑟
Work extracted = Cp×Ti×[1 − ( ) ] kJ/kg
Pi

= 250.71 kJ

Power = WxF = 197.366

Power= 264.47 BHP

Actual work extracted = ntW =0.8*264.47 = 211.57 BHP

10. Flash Separator V-100

F=L+V

𝐹𝑧𝑖 = 𝐿𝑥𝑖 + 𝑉𝑦𝑖

Feed, F = 5041 kg/hr

Top outlet (vapor), V = 3270 kg/hr

Density of v, ρV = 7.061 kg/m3

Bottom outlet (liquid), L = 1771 kg/m3

Density of L, ρL = 965.1 kg/m3

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𝑊𝐿 𝜌𝐿 1771 965.1
𝐹𝐿𝑉 = √ = √ = 6.33
𝑊𝑉 𝜌𝑉 3270 07.061

𝜌𝐿 − 𝜌𝑉
𝑉𝑝𝑒𝑟𝑚 = 𝑘 √
𝜌𝑉

2 +𝐷(𝑙𝑛𝐹 )3 +𝐸(𝑙𝑛𝐹 )4
𝑤ℎ𝑒𝑟𝑒, 𝑘 = 𝜃 𝐴+𝐵𝑙𝑛𝐹𝑙𝑣 +𝐶(𝑙𝑛𝐹𝑙𝑣 ) 𝑙𝑣 𝑙𝑣

A = -1.877478

B = -0.814580

C = -0.187074

D = -0.014523

E = -0.001015

k = 0.0162

𝜌𝐿 − 𝜌𝑣 𝑚
𝑉𝑝𝑒𝑟𝑚 = 𝑘 √ = 0.189
𝜌𝑣 𝑠

4𝑉
𝐷𝑖𝑎𝑚𝑒𝑡𝑒𝑟, 𝐷 = √ = 0.9311 𝑚
𝜋𝑉𝑝𝑒𝑟𝑚 𝜌𝑣

Now, hv related to vapor velocity

hv = 36” + 0.5 (diameter of feedline)

hf = 12” + 0.5 (diameter of feedline)

L = h v + hf + h L

Now for nozzle diameter.

𝑘𝑔
𝜌𝑚𝑖𝑛 = 𝜌𝑓𝑒𝑒𝑑 = 10.84
𝑚3

100 𝑓𝑡 𝑚
(𝑈𝑚𝑎𝑥 )𝑛𝑜𝑧𝑧𝑙𝑒 = = 30.37 = 9.25
√𝜌𝑚𝑖𝑛 𝑠 𝑠

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60 𝑓𝑡 𝑚
(𝑈𝑚𝑖𝑛 )𝑛𝑜𝑧𝑧𝑙𝑒 = = 18.22 = 5.55
√𝜌𝑚𝑖𝑛 𝑠 𝑠

𝑉𝑜𝑙𝑢𝑚𝑒𝑡𝑟𝑖𝑐 𝑓𝑙𝑜𝑤 𝑟𝑎𝑡𝑒

𝐴𝑟𝑒𝑎 𝑜𝑓 𝑛𝑜𝑧𝑧𝑙𝑒 = = 0.02325 𝑚2
𝑈𝑚𝑖𝑛

𝜋 2
𝐷 = 0.02325
4 𝑛𝑜𝑧𝑧𝑙𝑒

𝐷𝑛𝑜𝑧𝑧𝑙𝑒 = 0.1721 𝑚 = 6.78 𝑖𝑛𝑐ℎ

Hence

hv = 36 + 0.5 (6.78) = 39.39 inch

hf = 12 + 0.5 (6.78) = 15.39 inch

ℎ𝑓 + ℎ𝑣
ℎ= = 27.39 𝑖𝑛𝑐ℎ
2

𝐿 = ℎ𝑓 + ℎ𝑣 + ℎ = 82.17 𝑖𝑛𝑐ℎ = 2.0871 𝑚

Volume = 1.4205 m3

11. Process Design of Storage Tank

Mass flow rate of Methanol, G = 2300 kg/h

Density, ρ = 780 kg/m3

𝐺
Volumetric flow rate, F = 𝜌

= 2.949 m3/hr

It is assumed that Methanol is stored for 10 days

Therefore, Storage volume, V = F*10*24

= 707.69 m3

As per IS: 803-1976,

Height = 9 m

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Diameter = 12 m

Thickness = 2 mm

Volume = 1017 m3

3.4.2 Mechanical Design of Process Equipments

1. Heat Exchanger

Step 1. Find shell thickness

Operating Pressure = 1951 kPa

Design Pressure = 1951*1.05*0.0101972 = 20.889 kgf/cm2

Shell inside diameter, Di = 0.97 m (From process design)

Design Temperature = 723 K

Allowable stress (f) = 5.9 kgf/mm2 (IS 2002-1962)

Joint efficiency (J) = 0.85 for Class 2 Double welded butt joint with full penetration
(Table 1.1, IS 2002-1962)

𝑃∗𝐷𝑖
Thickness (t) = 200∗𝑓∗𝐽−𝑃 = 0.0206 𝑚

Corrosion Allowance = 0.003 m

So, thickness = 23.6mm

Standard thickness = 25mm (Ref. Table B1 Appendix B.C. Bhattacharya)

Outer diameter, Do = Di + Standard Thickness = 1.02 m

𝑡 0.0236
Check < 0.25 ( = 0.024 < 0.25), Acceptable
𝐷𝑖 0.97

Step 2. Head Design

Since the operating pressure is above 1.5 MN/m2, we use elliptical dished head.
Axis Ratio (Major/Minor) = 2
Taking Ri = Ro = Do and ro = 0.06 Do as initial guess
Ri = Ro = Do = 1.02 m

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𝐷𝑜 𝐷𝑜
ℎ0 = 𝑅0 − √(𝑅0 − ) × (𝑅𝑜 + − 2𝑟0 ) = 0.1727 𝑚
2 2

𝐷02
= 0.255 𝑚
4𝑅𝑜

𝐷𝑜𝑟𝑜
√ = 0.1766 𝑚
2

Out of these 3 quantities calculated above ho is the least, hence hE = ho = 0.1727 m

hE / Do = 0.17
As the diameter of the vessel (1.2 m) is not very large head can be fabricated from a single
plate and therefore, J = 1.
𝑃
= 0.0177
2𝑓𝐽
From Table 13.4, assume t/Do and find corresponding C and the recalculate t/Do

t/Do C t/Do (Calculated) Error (%)

0.002 3.65 0.0646 -3130.79

0.005 2.276 0.0403 -705.84

0.010 1.87 0.0331 -231.05

0.020 1.718 0.0304 -52.07

0.040 1.578 0.0279 30.16

Error is minimum for t/Do = 0.04

So, t = 0.0408 m
Extra 6 % for formed section = 1.06 * t = 0.04324 m
Standard Thickness of the head = 0.045 m
No corrosion allowance is added because t > 30 mm
Compared to 1.02 m, 45 mm is very small. Hence, the first assumption of Ri = Ro does not
introduce any considerable error in the result.
Thickness of Head = 4.5 cm

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Step 3. Nozzle Design

Opening Diameter of Nozzle, Do = 150 mm

𝑃 ∗ 𝐷𝑖 ∗ 0.01
𝐾′ = = 0.902
(1.82 ∗ 𝑓 ∗ (𝑎𝑐𝑡𝑢𝑎𝑙 𝑡ℎ𝑖𝑐𝑘𝑛𝑒𝑠𝑠 − 𝑐𝑜𝑟𝑟𝑜𝑠𝑖𝑜𝑛 𝑎𝑙𝑙𝑜𝑤𝑎𝑛𝑐𝑒)

Maximum Opening uncompensated corresponding to K’ = 115 mm

(According to IS 2825, pg 32)

The opening of nozzle is 150 mm but corresponding to K = 0.902

Nozzle outer diameter = maximum opening = 0.1m

Assume nozzle thickness = 0.01m

Nozzle inside diameter = 0.15-2*0.01 = 0.13m

Additional material in nozzle (An)

𝐻1 = √(𝑑 + 2 ∗ 𝐶. 𝐴) ∗ (𝑡𝑛𝑜𝑧𝑧𝑙𝑒 − 𝐶. 𝐴)

𝐻1 = √(0.18 + 2 ∗ 0.003) ∗ (0.01 − 0.003) = 0.0308𝑚

H1 = min (0.036, 0.05) = 0.036mm

𝑃 ∗ 𝐷𝑜
𝑡𝑟 ′ =
(200 ∗ 𝑓 ∗ 𝐽 + 𝑃)

𝑡𝑟 ′ = 0.0032𝑚

Ao = 2*H1*(tn – tr’ – C.A) = 0.000235 m2

𝐻2 = √(𝑑 + 2 ∗ 𝐶. 𝐴) ∗ (𝑡𝑛 − 2 ∗ 𝐶. 𝐴) = 0.0233 𝑚

H2 = min(0.0233, 0.04) = 0.0233m

Ai = 2*H2*(tn – 2*C.A) = 0.000186 m2

An = Ai + Ao = 0.000421 m2

As = (d + 2*C.A)*(ts – tr – C.A) = 0.000186 m2

A’ = As + An = 0.000607 m2

A = (d + 2* C.A)* tr = 0.002805 m2

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Ar = A – A’ = 0.0022 m2

Since Ar is positive, so external reinforcement is required.

𝐴𝑟 = [2(𝑑 + 2𝑐) − (𝑑 + 2𝑡ℎ )]𝑡𝑝

tp = 0.0224 m

tp (round off), thickness of ring pad = 23 mm

Step 4. Flange Design

Design Pressure = 1.951 MN/m2

Design Temp. = 450oC

Flange material = IS: 2004-1962 Class 2B

Gasket material = Asbestos filled flat metal jacket S.S.

Gasket factor (m) = 3.75 (from Table 7.1, B.C.B)

Minimum Design Seating Stress, y = 62.05 MN/m2 (from Table 7.1, B.C.B)

Bolt material = 5% Cr Mo Steel

Allowable stress of flange material = 118.58 MN/m2

Allowable stress of bolting material, So = 137.78 MN/m2 (from Table 7.1, B.C.B)

Nozzle Opening Diameter, D0 = 0.15 m

Assuming loose type flange,

Therefore, inside diameter of flange, B = Do

= 0.15 m

𝑑𝑖
= 1.01 (where di = internal diameter of Gasket)
𝑑𝑜

di = 0.1515 m

(𝑦−𝑝𝑚)
Gasket outer diameter, do = di*((𝑦−𝑝(𝑚+1)))0.5

= 0.1542 m

(𝑑𝑜−𝑑𝑖)
Minimum Gasket width, N = 2

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= 0.00137 m

N = 0.01 m (from Table 7.1, B.C.B)

Therefore, N taken = 0.01 m

Actual do = di + 2*N

= 0.1715 m

𝑁
Basic Gasket Seating width, bo = 2

= 0.005 m

Effecting Gasket Seating Widt, b = bo bo < 6.3 mm

Diameter at location of Gasket Load Reacton, G = di + N = 0.1615 m bo < 6.3 mm

Estimation of Bolt Loads:

Load due to Design Pressure, H = (π*p*G2)/4

= 0.0399 MN

Load to keep joint tight under operation, Hp = π*G*2*b*m*p

= 0.0371 MN

Total operating load, Wo = H + Hp

= 0.07704 MN

𝑊𝑜
Bolt Area required under operating conditions, Ao = 𝑆𝑜

= 0.000558 m2

Load on Gasket under bolting up condition, Wg = π*G*b*y

= 0.1584 MN

Allowable stress at atmospheric T & P, Sg = 138 MN/m2 (from Table 7.5, B.C.B)

𝑊𝑔
Bolt Area under bolting up condition, ABC = = 0.001148 m2
𝑆𝑔

Therefore Amin = Max (Abc, Ao) = 0.001148 m2

Bolt diameter, db = 0.012 m (from Table 7.4, B.C.B)

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Bolt thickness, tb = 0.0015 m (from Table 7.4, B.C.B)

𝑑𝑏 – 2𝑡𝑏 2
Root Area = 𝜋 ∗ ( )
2

= 0.00006358 m2

𝐴𝑚𝑖𝑛
Minimum No. of bolts = 𝑅𝑜𝑜𝑡 𝑎𝑟𝑒𝑎

= 18.06

Actual No. of bolts, n = 16

Radial clearance, R = 0.02 m (from Table 7.4, B.C.B)

Bolt spacing, Bs = 0.075 m (from Table 7.4, B.C.B)

Bolt Circle Diameter, C1 = Bs*n/π

= 0.3821 m

C2 = Do + 2*(1.415*0.018 + R)

= 0.2409 m

C1 – C2 is least positive for bolt dimension of 12 X 1.5

Flange outside diameter, A = C2 + db + 0.02

= 0.27294 m

Actual bolt area, Ab = n*(Root Area)

= 0.00101 m2

Checking for gasket width condition:

𝑆𝑔∗𝐴𝑏
= 27.685 MN/m2
π∗N∗G

2y = 125 MN/m2

𝑆𝑔∗𝐴𝑏
Thus, π∗N∗G < 2y

Flange Moment Computation:

Operating condition:

Hydrostatic end force on area inside of flange, W1 = π*B2*p/4

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= 0.03446 MN

W2 = H – W1 = 0.00548 MN

W3 = Hp = 0.0371 MN

Wo = W1 + W2 + W3 = 0.077 MN

𝐶2−𝐵
a1 = = 0.04547 m (from Table 7.4, B.C.B)
2
𝐶2−𝐺
a3 = = 0.03972 m (from Table 7.4, B.C.B)
2
𝑎1+𝑎3
a2 = = 0.042595 m (from Table 7.4, B.C.B)
2

Mo = W1*a1 + W2*a2 + W3*a3 = 0.00327 MJ

Bolting up condtion:

W = (Amin + Ab)*0.5*Sg = 0.149 MN

Mg = W*a3 = 0.0059 MJ

Therefore controlling moment, M = max (M0, Mg) = 0.0059 MJ

Step 5. Saddle Support

Shell Diameter, Ds = 1.02 m

Length of Shell, L = 4.854 m
Mass Density, γs = 77000 N/m3
𝜋(𝐷02 −𝐷𝑖2 )(𝐿+2𝐻)γs 𝛾 𝜋𝐷𝑖 (𝐿+3𝐻)𝛾
W0 = + 𝜋(𝑑02 − 𝑑𝑖2 )𝐿𝑛 (4) +
4 4
𝑘𝑁
= 457.745 𝑚2

W1 = W0/2
𝑘𝑁
= 228.872 𝑚2

R = 0.55

A = 0.5

Sf = 0.02

J*f = 1.18e+008*0.85 = 100300000 N/m2

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Longitudinal bending moments in the vessel shell:

There are two maximum bending moments over the supports and at the centre of the span. The
Bending moments are given by:
A) At mid-span
2(𝑅2 −𝐻2 )
𝑊1 𝐿 1+ 𝐿2 4𝐴
M1 = [ 4𝐻 − ]
4 1+ 𝐿
3𝐿

= 167298 N-m

B) At supports
𝐴 𝑅2 −𝐻2
1− +
𝐿 2𝐴𝐿
M2 = −𝑊1 𝐴 [ 1 − 4𝐻 ]
1+
3𝐿

= -5886.603 N-m

Longitudinal bending stresses at the mid span:

The resultant longitudinal stresses at the mid-span due to pressure and bending are given:
A) At the highest point of cross-section,

𝑝𝑅 𝑀 𝑁
𝑓1 = − 𝜋𝑅12 𝑡 = 15250290 𝑚2
2

B) At the lowest point,

𝑝𝑅 𝑀
𝑓1′ = + 𝜋𝑅12 𝑡
2
𝑁
= 30156585 𝑚2

So, f1 < f*J (15250290 < 100300000)

f1’ < f*J (30156585 < 100300000)
Acceptable as it is well below the maximum.

Longitudinal bending stresses at the saddles:

The resultant longitudinal stresses due to pressure and bending are given:

A) At the highest point of cross-section in the shells which remain round in the plane of
the support,

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𝑝𝑅 𝑀2
𝑓2 = −
2 𝐾1 𝜋𝑅 2 𝑡
𝑁
= 25154349 𝑚2 (Ref: Table 10.3, BCB)

B) At the lowest point of cross section,

𝑝𝑅 𝑀2
𝑓2′ = +𝐾 2𝑡
2 2 𝜋𝑅

𝑁
= 21337565 𝑚2 (Ref: Table 10.3, BCB)

So, f2 < f*J (25154349 < 100300000)

f2’ < f*J (21337565 < 100300000)
Acceptable as it is well below the maximum.

Tangential shearing stress:

The load is transferred from the unsupported part of the shell to the part over the supports by
tangential shearing stress which vary with the local stiffness of the shell.

K3 = 1.171 (Ref: Table 10.4, page 180, BCB)

Conditions A>R/2 and A<L/4

Maximum tangential Sheer stress is given by:

𝐾3 𝑊1 𝐿 − 2𝐴 − 𝐻
𝑞= ( )
𝑅𝑡 𝐿+𝐻
𝑁
=1519038 𝑚2

So, q < 0.8f (1519038 < 100300000)

Acceptable as it is well below the maximum.

Circumferential stress:
K5 = 0.76; K6 = 0.047; B = 0.5; (Ref: Table 10.5, page 181, BCB)
A/R = 0.909; L/R = 11.08 (Ref: Table 10.5, page 181, BCB)

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A) At the lowest point of cross section,

𝐾5 𝑊1
𝑓3 =
𝑡(𝐵 + 10𝑡)
𝑁
= 9276966 𝑚2

B) At the horn of the saddle,

𝑊1 3𝐾6 𝑊1
𝑓4 = (− )−( )
4𝑡(𝐵 + 10𝑡) 2𝑡 2
𝑁
= -28868454 𝑚2

So, f2 < f*1.25 (8624381.07 < 147500000)

f2’ < f*1.25 (15590474.83 < 147500000)
Acceptable as it is well below the maximum.

Horizontal component of all radial loads:

K9 = 0.204 for 𝜃= 1200
= 0.260 for 𝜃= 1500

𝐹 = 𝐾9 𝑊1
= 46690 N

2. Mechanical Design of Methanol Reactor

Step 1. Head Design
Number of passes = 1
k1 = 0.319 (Table 12.4, Coulson & Richardson, Page 649)
n1 = 2.142 (Table 12.4, Coulson & Richardson, Page 649)
do = 0.12 m

Db = = 2.161 m
Clearance = 0.018 mm
Shell inside diameter = 2.161 + 0.018 = 2.179 m
P = 1.05 x 71 = 74.55 bar
J = 1, for Class I Double welded butt joint with full penetration
f = 1.25 x 108 MN/m2 (Material – IS: 2041-1962)

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Thickness = P * do/ (2 * f * J - P) = 0.0706 m

Thickness (round off to std.) = 0.071 m (Ref. Table B-1 BCB pg-269)
Outer Diameter = Inside Diameter + 2 * Thickness
= 2.321 m
Standard Outer diameter of shell = 2.4 m (Ref. Table B-4 BCB pg-271)

As the design pressure is above 1.5 MN/m2, we use ellipsoidal dished head
Major axis / Minor axis = 2
As first iteration take
Ri = Do = 2.4 m
Ro = Do = 2.4 m
ro = 0.06 * Do = 0.144 m

𝐷𝑜 𝐷𝑜
ℎ0 = 𝑅0 − √(𝑅0 − ) × (𝑅𝑜 + − 2𝑟0 ) = 0.3831 𝑚
2 2

Now find,
𝐷02
= 0.6 𝑚
4𝑅𝑜

𝐷𝑜𝑟𝑜
√ = 0.4156
2

he = min (ho, Do2/(4 * Ro) , (Do * ro / 2)½ ) = 0.3831 m

he/Do = 0.16
J=1
𝑡 𝐶
= 𝑃 ∗ (2
𝐷𝑜 ∗ 𝑓 ∗ 𝐽)

= 0.02982 C

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From Table 13.4 BCB, assume t/Do and find corresponding C and the recalculate t/Do

t/Do C t/Do (Calculated) Error (%)

0.002 4.1 0.122262 -6013.1

0.005 2.468 0.073595 -1371

0.010 2.01 0.059938 -499.38

0.020 1.834 0.054689 -173

0.040 1.664 0.049620 -24.05

Error is minimum for t/Do = 0.04

So, t = 0.04 * 2.4 = 0.096 m
Adding 6% for formed section = 1.06 * 0.096 = 0.102 m
No corrosion allowance is added because t > 30 mm
Compared to 2.4 m, 0.102 mm is very small. Hence, the first assumption of Ri = Ro does not
introduce any considerable error in the result.
Thickness of the head = 10.2 cm

Step 2. Skirt Support Design

The tensile stress in the skirt will be maximum when the dead weight is minimum, i.e., the
shell of the vessel is just erected and the shell empty without any internal attachments. The
compressive stress, on the other hand, is to be determined when the vessel is filled up with
water for hydraulic test. Maximum wind load may be expected at any time and this factor
always to be considered.

For skirt material, f = 96 MN/m2

E= 2x102 MN/m2
The minimum weight of the vessel with two beads and shell will be:
W min= π (Di + ta) ta (H - 4) ϒs + 2 (Head Weight)
where Di= 2.179 m
ta= 0.071 m

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Height of reactor tangent to tangent = 4.6778 m

Skirt Height, H= 1 m

Insulation material = Asbestos

Thickness of insulation = 0.05 m

ϒs = specific weight (or weight density) of shell material
= 7 850 x 9.81 N/m3
=77 000 N/m3 or 77 kN/m3

𝐷 2
Blank Diameter of head = 𝐷𝑜 + 42𝑜 + 3 ∗ 0.06 ∗ 𝐷𝑜 + 0.04 ∗ 2 + 𝑡𝑠 = 2.729 𝑚

Weight of 1 head = 15.836 kN

Substituting the values and expressing the weight in kN,

W max =Ws + Wi + Wl + Wa
Ws = weight of shell during test

= 3.14*(Shell I.D + 0.05)*0.05*(Heffective – skirt height)* ϒs

= 126.065 kN
Wi = weight of insulation

= 3.14*2450*9.81*0.05*Shell outer diameter*Leffec

= 41.91 kN

Wl = weight of water during test

π 𝐷𝑖 2
= (H-4)(9.81), kN
4

= 171.079 kN
Wa= weight of attachments
= 5.677 kN

Therefore,

Wmax= 693.691 kN

Period of vibration at minimum dead weight i

Tmin= 6.35 X 10-5 (H/D).3/2 (Wmin/ta)1/2

= 0.712 s > 0.5 s (Ref. Pg 151 B.C.B, take t as corroded wall thickness)

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K2 = a coefficient to determine wind load =2

Period of vibration at maximum dead weight is given by,
Tmax= 6.35X 10-5 (H/D)3/2(Wmax/t)1/2
= 0.86 > 0.5
Hence, K2 = 0.7
From Eq. 9.39 the wind load is determined as follows :

Pw = K1 K2 pw H D
For minimum weight condition, Do = 2.279 m
For maximum weight condition, Do = 2.5 m (insulated)
Hence, Pw (min) = 18117 N
and, Pw (max) = 19872 N
Minimum and maximum wind moments are computed by Eq. 9.3.11 BCB.
Mw (min) =Pw (min) x H/2
= 51434 J
Mw (max) = Pw (max) X H/2
= 56416 J
As the thickness of the skirt is expected to be small, assume
Di≈ Do = 2.279 m
By Eq. 9.3.13 BCB
4Mw (min)
σswm (min) = π 𝐷2 t

0.0126
= MN/m2
𝑡

4 𝑀𝑤𝑚𝑎𝑥
σzwm (max) = 𝜋 𝐷2 𝑡

0.01145
= MN/m2
𝑡

Minimum and maximum dead load stresses are calculated as follows:

𝑊𝑚𝑖𝑛
σsw (min) = 𝜋𝑑𝑡

0.0663
= MN/m2
𝑡

𝑊𝑚𝑎𝑥
σsw (max) = 𝜋𝑑𝑡

0.0884
= MN/m2
𝑡

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By Eq. 10.2.1 BCB ,maximum tensile stress without any eccentric load is computed as follows.

σz (tensile) = σzwm (min) –σsw(min)

= 0.05376/t

Substituting, σz (tensile) = f J

= 96 MN/m2

J = 1 for double welded butt joint for class I

Equating,

96 = 0.05376/t

t = 0.56 mm

Maximum compression load is computed as follows:

σz (compression) = σzwm (max) + σsw (max)

= 0.01145/t + 0.08834/t

= 0.0998/t

Substituting, σz (compressive) = 0.125 E (t/Do)

= 0.125 (2 X 105 ) (t/2.5)

= 1.25 X 104 t

Equating,

1.25 X 104 t = 0.0998/t

0.0998
Or, t2 = 1.25 𝑋 104

Or, t = 3.16 X 10-3 m

= 3.16 mm

As per IS : 2825 – 1969 minimum corroded skirt thickness is 7 mm. Providing 1mm corrosion
allowance, a standard 8 mm thick plate can be used for skirt.

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Design of skirt-bearing-plate:

Maximum compressive stress between bearing-plate and foundation is:

𝑊𝑚𝑎𝑥 𝑀𝑤
σc = +
𝐴 𝑍

Where, Wmax = 693.69 kN

A = π (Do –l) l = 0.7536 m2

Do = outer diam. Of skirt = 2.5 m

l = outer radius of bearing plate - outer radius of skirt = 100 mm

Mw = 56.416 kJ

Z = π Rm2 l = 0.4521

σc = 1.04527 MN/m2

Thickness of the bearing plate is calculated as follows:

tbp = l√3 𝜎𝑐 /f

f = allowable stress = 96 MN/m2

Substituting,

1.045
tbp = 100 √( 3 𝑋 )
96

= 18.07 mm

Standard Thickness from Table B-1 BCB

tbp = 20 mm

As the plate thickness required is equal to 20 mm, gussets will not be used to reinforce the
plate. (Gussets required for thickness > 20 mm)

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3. Absorber

Step 1. Head Design

Shell inside diameter = 1.753 m

P = 1.05 * 490 * 0.01019 = 53.5353 kgf/mm2

J = 0.85, for Class II Double welded Butt joint with full penetration

f = 14.3 kgf/cm2 (Material- IS: 2041-1962)

Thickness = P * do/ (200 * f * J - P) = 0.039473 m

Thickness = 39.4 mm

Outer Diameter = Inside Diameter + 2 * Thickness

= 1.753 + 2*0.039473

= 1.831 m

Outer diameter (round off) of shell = 1.84 m

As design pressure is 5000 kPa, so we can use ellipsoidal dished heads.

Major axis / Minor axis = 2: 1

As first iteration take

Ro = Do = 1.84 m

Ri = Do = 1.84 m

ro = 0.06 * Do = 0.1104 m

𝐷𝑜 𝐷𝑜
ℎ0 = 𝑅0 − √(𝑅0 − ) × (𝑅𝑜 + − 2𝑟0 ) = 0.311 𝑚
2 2

Now find,
𝐷02
= 0.46 𝑚
4𝑅𝑜

𝐷𝑜𝑟𝑜
√ = 0.3186
2

he = min (ho, Do2/(4 * Ro) , (Do * ro / 2)½ ) = 0.311 m

he/Do = 0.169, J = 1

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𝑡 𝐶
= 𝑃 ∗ (200
𝐷𝑜 ∗ 𝑓 ∗ 𝐽)

= 0.02983 C
From Table 13.4 BCB, assume t/Do and find corresponding C and the recalculate t/Do

t/Do C t/Do (Calculated) Error (%)

0.002 3.425 0.6411 -96.88

0.005 2.180 0.0408066 -87.74

0.010 1.800 0.0408066 -75.49

0.020 1.570 0.029388 -31.94

0.040 1.480 0.0277 44.38566

Error is minimum for t/Do = 0.020

So, t = 0.020 *1.84 = 0.0368 m

Adding 6% for formed section = 1.06 * 0.0368= 0.039 m

No corrosion allowance is added because t > 30 mm
Compared to 1.84 m, 0.039 mm is very small. Hence, the first assumption of Ri = Ro does not
introduce any considerable error in the result.
Thickness of the head = 3.9 cm

Step 2. Tall tower Design

Max wind velocity expected (for height up to 20 m). =140 km/h

Shell outside diameter =1.84 m

Shell length tangent to tangent = 9.321m

Skirt height =4.0 m

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Operating pressure =5 MN/m2

Design pressure =5.25 MN/m2

Shell material = IS: 2002-1962 Grade 2 B

Shell double welded butt joints, no stress relieving or radiographing.

Corrosion allowance = 2.4mm

Tray spacing = 0.75m

Top disengaging space = 1.0m

Bottom separator space = 2.75m

Weir height = 75mm all trays

Downcomer clearance = 25 mm all trays

Weight of each head = 7.5 KN

Tray loading excluding liquid (alloy steel trays) = 1.0 kN/m2 of tray

Insultion = 75mm asbestos

Accessories = one caged ladde

Allowable stress of shell material at design temperature 98.1 MN/m2

Weld joint efficiency factor = 0.85, for Class II Double welded Butt joints

Both the values are obtained from IS: 2825 - 1969

Thickness of shell required for internal pressure:

𝑝𝐷𝑜
t = 2𝑓 +c
𝑗 +𝑝

Substituting for

P = 5.25 MN/m2

Do = 1.84 m

f = 98.1 MN/m2

c = 0.003

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t = 0.039473 m

Nearest standard thickness 39.47 mm = 0.039473 m

Corroded shell thickness, t = 0.037 m

As the shell thickness is very small compared to the diameter, for rest of the calculation

Do = Di = Di+ t = 1.84 m will be used.

Calculation of axial stress due to pressure:

pD 0.8 x 2
σz = = = 65.27 MN/m2
4t 4 x 0.011

Calculation of axial stress due to dead loads:

Ws = wt. of shell for λ meters length

= (πDtXγs ), N

𝑊𝑠
σzs =
πtD

= (9.81) (7 850) (X) x 10-6 MN/m2

= 0.077 X MN/m2

(Assuming constant thickness of shell)

Wi= weight of insulation for a length X meters

=(π Dins tins X γins ) X 10-6 MN

Dins = mean diam. of insulation ≈ D

𝑊𝑠 𝑡𝑖𝑛𝑠 γ𝑖𝑛𝑠 𝑋
σzi = =
πtD 𝑡

(0 075) (5 640) (X) x 10−6

= 0.011

= 0.011432 (X) MN/m2

Wl= weight of liquid supported for a distance X meters from top

X−1 4X−1
No of trays, n= ( + 1)=
0.75 3

Liquid weights on trays are calculated on the basis of water and 0.075 m depth. Hence

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π 4𝑋−1
Wt = (D2) (0.075) (9 810) x 10-6 MN
4 3

𝑊𝑡
σzi = πDt

4𝑋−1
(75) (9.81 x 10−6 )
3
= 2(0.011)

4𝑋−1
=0.0114( ) MN/m2
3

Weight of top head =16.65 x 10-3 MN

Weight of ladder = 3.65 x 10-4 (X) MN

𝜋𝐷 2 4𝑋−1
Weight of trays = (l) X10-3 MN
4 3

Wa= weight of attachments

4𝑋−1
= (16.65 x 10-3) + (3.65 x 10-4 X) + (3.14 x10-3) , MN
3

𝑊𝑎
σza =
πtD

4𝑋−1
=0.11+5.3x10-3 (X) + 0.046 , MN/m2
3

= 0.0017(X) – 0.078, MN/m2

σzw = 0.077 X+0.038 5 X+(0.044 8 X-0.011 2)+0056 7X – 0.223

= 0.166X -0.384

Calculation of stress due to wind loads:

Wind pressure pw is calculated

Pw= 0.05 Vw2

=0.05 (140)2

= 980 N/m2

From Table 9.1 BCB, 8 maximum wind pressure upto 20 m height is 1 000 N/m2. For
calculating wind load pw = 1.0kN/m will be used,

Wind load, Pw, is

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Pw=K1K2pwXDo

Where pw = 1000 N/m2

Do= 1.84+ 0.075 x 2

= 1.99 m (here effect of ladder and piping are not considered)

K1= 0.7

To decide for K2, period of variation, T, is to be known.

From Eq. 9.3.23

T=6.35 x 10-5 (H/D)3/2(W/t)1/3, second

Where, H= 20 m

D=1.99m

t= 0.011 m

W = Ws + Wt + Wi + Wa
𝜋 𝜋
= 𝜋Dt(H- 4)γs +πDtins(H-4)γins +4 (D2)(.075) γ1 (16)+ [7.5 x 2 + 0 365 (H-4)+ 4 D2 (1.0) (16)]

= (3.14) (2) (16) (0.011) 77 + (3.14) (2) (0.785)(16)(5.64) +(0.785) (4) (0.075) (9.81) (16)+
(15.0) +5.85+50.15

= 84.00 + 42.00 + 37.00 + 71.00

= 250.034 kN

Therefore,

T = 6.35 x 10-5 (20/2)3/2(234/0.011)1/2 = 0.101s< 0.5s

Hence,

K2 = 1

Substituting,

Pw = (0.7) (1) (1 000) X (1.99), N = 1365.14X, N

Mw = Pw X2 = 682.57 X2,

4𝑀𝑤
σzwm = (10-6), MN/ m2
𝜋𝐷 2 𝑡

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(4)(682.57)𝑋 2 10−6
= , MN/ m2
(3.14)(3.38)(0.037)

=0.006941 X2 MN/m2

Calculation of resultant longitudinal stress

Upwind side:

σz(tensile)= σzp –σzw +σzwm

= 64.88 -0.1668 X + 0.006941 X2

= 0.006941X2 -0.1668 X+64.88

Expecting, circumferential weld-seam may fall at a distance X meters from top or a little earlier

σ z(max)= fJ

= 98.1 x 0.85

=83.385 MN/m2

Substituting σz (max) for σz (tensile)

83 = 0.021 7X2 -0.227 X +36.534 or, 0.021 7 X2-0.227 X-46.47-0

Solving for X ,

0.227±√0.2272 −4(0.0217)(46.47)
X= 2(0.017)

= 65.026 m > >16 m

Downwind side:

σz (compression) = σzwm =σzw +σzp

= 0.021 7X2+0.227 X -0.234 -3.63

= 0.021 7 X2+0.227 X-36.534

𝑡
σz (compressive, maximum) = 0.125 E 𝐷
𝑜

0.011
= 0.125 (2 x 105)( )
2

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= 502.717 MN/m2

Equating the maximum value of σz,(compressive):S

0.021 7 X2 + 0.227 X -174.034 = 0

Or, X= 88.32 meters ≫16 m

If credit for reinforcement of the shell by tray-support n rings are also taken into account X will
be further increased.

Step 3. Skirt Support Design

Tensile stress in the skirt will be maximum when the dead weight is minimum, i.e., the shell
of the vessel is just erected and the shell empty without any internal attachments. The
compressive stress, on the other hand, is to be determined when the vessel is filled up with
water for hydraulic test. Maximum wind load may be expected at any time and this factor
always to be considered.
The minimum weight of the vessel with two beads and shell will be :
W min= π (Di + ta) ta(H - 4) ϒs + 2 (7 500)
where Di= 1.753 m
ta= 0.039 m
H=4m
ϒs = specific weight (or weight density) of shell material
= 7 850 x 9.81 N/m3
=77 000 N/m3 or 77 kN/m3
Substituting the values and expressing the weight in kN,
W min = (3.14) (1.986) (0.014) (16) (77) + 2(7.5)
=108 + 15
= 123 kN

W max =Ws + Wi + Wl + Wa
Ws = weight of shell during test

= 3.14*(Shell I.D + 0.05)*0.05*(Heffective – skirt height)* ϒs

= 246.757 kN
Wi = weight of insulation

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= 3.14*2450*9.81*0.05*Shell outer diameter*Leffec

= 64.369 kN

Wl = weight of water during test

π 𝐷𝑖 2
= (H-4)(9.81), kN
4

=(0.785)(1.972) (16) (9.81)

=267.908 kN
Wa= weight of attachments
= 13.321kN

Therefore,

Wmax= 246.757 + 42 + 267.908 + 71

= 380.908 kN

Period of vibration at minimum dead weight i

Tmin= 6.35 X 10-5 (H/D).3/2 (Wmin/ta)1/2

= 2.92s > 0.5 s

K2 = a coefficient to determine wind load.

=2
Period of vibration at maximum dead weight is given by,
Tmax= 6.35X 10-5 (H/D)3/2(Wmax/t)1/2
= 3.414 > 0.5
Hence, K2 = 2
From Eq. 9.39 the wind load is determined as follows :

Pw = K1 K2 pw H D
For minimum weight condition, Do = 1.753 m
For maximum weight condition, Do = 1.84 m (insulated)
Hence, Pw(min)= (0.7) (2) (1 000) (4) (1.75)
=32692.39 N
and, Pw (max) =(0.7) (2) (1 000) (20) (1.84)
=34314.896 N

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Minimum and maximum wind moments are computed

Mw (min) =Pw (min) x H/2
= 32692 X 2 kJ
= 217.747 kJ
Mw (max) = Pw (max) X H/2
= 34314.896 x 2kJ
= 228.554 kJ
As the thickness of the skirt is expected to be small, assume
Di≈ Do = 1.753m
By Eq. 9.3.13
4Mw (min)
σswm (min) = π 𝐷2 t

= 4 (217.747)/3.14 (3.073) t MN/m2

= 0.0819/t, MN/m2

σzwm (max) = 4 Mw (max)/π D2 t

= 4 (228.554)/3.14 (3.073) t MN/m2

= 0.085/t MN/m2

Minimum and maximum dead load stresses are calculated as follows:

σsw (min) = Wmin/π d t

= 0.123/3.14 (2) t MN/m2

= 0.05/t MN/m2

σsw (max) = Wmax/π d t

= 0.465/3.14 (2) t MN/m2

= 0.065/t MN/m2

Maximum tensile stress without any eccentric load is computed as follows.

σz (tensile) = σzwm (min) –σsw(min)

=0.0819/t – 0.05/t

= 0.031/t

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Substituting, σz (tensile) = f J

= 96 X 0.7

= 67.2 MN/m2

J = 0.7 for double-welded butt-joint for class 3 construction.

Equating,

67.2 = 0.031/t

t = 2.161mm

Maximum compression load is computed as follows:

σz (compression) = σzwm (max) + σsw (max)

= 0.1519/t

Substituting, σz (compressive) = 0.125 E (t/Do)

= 0.125 (2 X 105 ) (t/2)

= 1.25 X 104 t

Equating,

1.25 X 104 t = 0.1519/t

0.1519
Or, t2 = 1.25 𝑋 104

Or, t = 3.34 X 10-3 m

= 3.7 mm

As per IS : 2825 – 1969 minimum corroded skirt thickness is 7 mm. Providing corrosion
allowance, a standard 8 mm thick plate can be used for skirt.

Design of skirt-bearing-plate:

Maximum compressive stress between bearing-plate and foundation is :

𝑊𝑚𝑎𝑥 𝑀𝑤
σc = +
𝐴 𝑍

Where, Wmax = 380.908 kN

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A = π (Do –l) l

Do = outer diam. Of skirt

=2m

l = outer radius of bearing plate minus outer radius of skirt

Mw = 301 kJ

Z = π Rm2 l

Thickness of the bearing plate is calculated as follows:

tbp = l√3 𝜎𝑐 /f

Where, l = 100 mm

σc = maximum compressive load calculated by Eq. 10.2.5 for l=0.1 m

= 1.85 MN/m2

f = allowable stress = 96 MN/m2

Substituting,

1.85
tbp = 100 √( 3 𝑋 )
96

= 18.73 mm

Bearing plate thickness of 25 mm is required. As the plate thickness required is smaller than
20 mm, gussets may not be used to reinforce the plate

3.4.3 Drawings of Two Equipment as per BIS Specification of Equipment

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3.4.4 Specification of All Process Equipments

Heat Exchanger: E-101

Type Shell and Tube

No. of Shell Passes 1
No. of Tube Passes 2
Tube Side Fluid Cooling Water
Shell Side Fluid Syngas
Area (m2) 35.067
No. of Tubes 60
Shell Inside Diameter (m) 0.5479
Tube Side Pressure Drop (psi) 6.594
Shell Side Pressure Drop (psi) 6.376
Uo(W/m2K) 103.1

Heat Exchanger: E-102

Type Shell and Tube

No. of Shell Passes 1
No. of Tube Passes 6
Tube Side Fluid Cooling Water
Shell Side Fluid Syngas
Area (m2) 110.475
No. of Tubes 192
Shell Inside Diameter (m) 0.9692
Tube Side Pressure Drop (psi) 9.139
Shell Side Pressure Drop (psi) 0.335
Uo(W/m2K) 79.5

Heat Exchanger: E-103

Type Shell and Tube

No. of Shell Passes 1
No. of Tube Passes 8

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Tube Side Fluid Cooling water

Shell Side Fluid Syngas
Area (m2) 45.126
No. of Tubes 104
Shell Inside Diameter (m) 0.6665
Tube Side Pressure Drop (psi) 9.433
Shell Side Pressure Drop (psi) 0.422
Uo(W/m2K) 75.63

Heat Exchanger: E-104

Type Shell and Tube

No. of Shell Passes 1
No. of Tube Passes 4
Tube Side Fluid High Pressure Steam
Shell Side Fluid Syngas
Area (m2) 83.386
No. of Tubes 116
Shell Inside Diameter (m) 0.7078
Tube Side Pressure Drop (psi) 1.044
Shell Side Pressure Drop (psi) 4.649
Uo(W/m2K) 82.46

Heat Exchanger: E-105

Type Shell and Tube

No. of Shell Passes 1
No. of Tube Passes 8
Tube Side Fluid Crude Methanol
Shell Side Fluid Syngas
Area (m2) 280.663
No. of Tubes 920
Shell Inside Diameter (m) 0.7708

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Tube Side Pressure Drop (psi) 2.623

Shell Side Pressure Drop (psi) 5.788
Uo(W/m2K) 84.948

Heat Exchanger: E-106

Type Shell and Tube

No. of Shell Passes 1
No. of Tube Passes 8
Tube Side Fluid High Pressure Steam
Shell Side Fluid Syngas
Area (m2) 750.1206
No. of Tubes 2456
Shell Inside Diameter (m) 1.0807
Tube Side Pressure Drop (psi) 5.040
Shell Side Pressure Drop (psi) 4..901
Uo(W/m2K) 74.908

Heat Exchanger: E-107

Type Shell and Tube

No. of Shell Passes 1
No. of Tube Passes 8
Tube Side Fluid Cooling Water
Shell Side Fluid Crude Methanol
Area (m2) 169.7572
No. of Tubes 360
Shell Inside Diameter (m) 0.8645
Tube Side Pressure Drop (psi) 9.850
Shell Side Pressure Drop (psi) 0.975
Uo(W/m2K) 86.412

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Liquid-Gas Separator: V-100

Material of Construction Carbon Steel

Pressure (kPa) 1862
Temperature (oC) 80
Diameter (m) 0.9311
Height (m) 2.0871

Liquid-Gas Separator: V-101

Material of Construction Carbon Steel

Pressure (kPa) 3931
Temperature (oC) 80
Diameter (m) 0.1585
Height (m) 2.020

Liquid-Gas Separator: V-102

Material of Construction Carbon Steel

Pressure (kPa) 6962
Temperature (oC) 25
Diameter (m) 0.5644
Height (m) 2.0848

Distillation Column

Temperature (Top) (oC) 32.73

Temperature (Bottom) (oC) 99.24
Reflux Ratio 0.922
Column Diameter (m) 1.232
Number of stages 12
Weir length (m) 0.948
Weir Height (mm) 50
Hole Diameter (mm) 5

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Plate Thickness (mm) 5

Number of Holes 4618
Liquid Flow Pattern Reverse Flow
MOC Carbon Steel

Reboiler

Type Kettle Reboiler

Shell Fluid Water-Methanol Mixture
Tube Fluid Hot Water
Area (m2) 5.516
No. of Tubes 6
Kettle Inside Diameter (mm) 315
Uo(W/m2K) 658

Condenser

Type Shell and Tube

No. of Shell Passes 1
No. of Tube Passes 4
Hot Fluid Methanol
Cold Fluid Cooling Water
Area (m2) 67.633
No. of Tubes 276
Tube Side Pressure Drop (Pa) 104.69
Shell Side Pressure Drop (Pa) 13.56
Uo(W/m2K) 1520.4

Reformer

Type Packed Bed Reactor

Temperature (oC) 950
Pressure (kPa) 2000

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Shell Diameter (m) 5.1118

Length (m) 1.7514
Number of Tubes 796
Residence Time (s) 32
MOC Carbon Steel

Methanol Reactor

Type Packed Bed Reactor

Temperature (oC) 250
Pressure (kPa) 7100
Shell Diameter (m) 2.4
Length (m) 4.6278
Number of Tubes 156
Residence Time (s) 27
MOC IS:2041-1962

Absorber Column

Temperature (oC) 35
Pressure (kPa) 5000
Mode of Operation Counter Current
Column Diameter (m) 1.753
Column Height (m) 9.316
Number of Trays 43
MOC Carbon Steel
Compressor: K-100

Suction Pressure (kpa) 485

Discharge Pressure (kpa) 2000
Discharge Temperature (oC) 158.11
Power Required (BHP) 173.189
MOC Carbon Steel

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Compressor: K-101

Suction Pressure (kpa) 1862

Discharge Pressure (kpa) 4000
Discharge Temperature (oC) 165.84
Power Required (BHP) 273.682
MOC Carbon Steel

Compressor: K-102

Suction Pressure (kpa) 3862

Discharge Pressure (kpa) 7200
Discharge Temperature (oC) 140.29
Power Required (BHP) 712.77
MOC Carbon Steel

Turbine

Suction Temperature (K) 298

Suction Pressure (kPa) 6962
Discharge Temperature (K) 294
Discharge Pressure (kPa) 101.3
Shaft Work (kJ) 200.56
MOC Carbon Steel

3.4.5 Major Engineering Problems of the Plant with their Remedies

Catalytic Reactor

Problem: Dumped catalyst tubes and downtime to reinstall the catalyst and clean downstream
equipment.

Cause: Inadequate design and careless installation of bed supports, particularly the wire mesh
screen support.

Remedies: Following features should be incorporated into the catalytic reactor design.

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 External insulation for heat conservation and to prevent corrosion of the vessel shell.
 Inlet flow distributors to prevent impingement of process gas directly onto catalyst tubes
which can cause flow channeling and bed movement.

Explosion

Cause:

 Excess Pressure
 Inappropriate material of construction

Remedies:

 Proper pressure controller

 Good quality of material of construction Proper designing

Catalyst Deactivation Causes:

 Sintering or Aging Fouling

Major Problems in Equipmments

1. Air leaks & Compressors

2. Heat exchangers, reboilers & tube bundle
3. Turndown & modulating outlet temperatures
4. Control Scheme
5. Fouling of heat exchanger surfaces
6. Gas leaks, Valve leaks
7. Tracing
8. Circuit troubleshooting, pipe temperature & maintenance
9. Trap Safety
10. Corrosive condensate
11. Excessive back pressure

Problems with pressure vessels and remedies

Pressure vessels are air-tight containers used mostly in process industry, refinery and
petrochemical plant to carry or hold liquid, gases or process fluids. They are typically subjected
to pressure loading and internal or external operating pressure different from ambient pressure.

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Due to differential operating pressure of the pressure vessel, it is potentially dangerous and
hazardous.

The main causes of failure of a pressure vessel are as follows

 Fatigue Stress
 Improper selection of materials or defects Improper repair of leakage
 Improper installation Fabrication error over pressurization
 Failure to inspect frequently enough erosion
 Creep Embrittlement
 Unsafe modifications or alteration Unknown or under investigation.

Remedies:

Designing, fabricating and constructing pressure vessels to comply with applicable codes and
standards, and where no pressure vessel law exists, to internationally recognized pressure
vessel safety codes.

Operating the vessel at pressure below the maximum allowable working pressure with proper
pressure setting of relief devices, to handle design pressures and temperatures.

Periodically testing and inspecting the vessel as well as the relief devices in order to detect
corrosion or erosion of the vessel that can cause holes, leaks, cracks, general thinning of the
vessel walls or any other defects. Safety relief valves must be taken off during safety inspection
to verify whether their settings are correct.

Ensuring that alterations or repairs of vessels are only done by competent and authorised
persons and the repair must meet the accepted industry quality standards for pressure vessel
repair.

Problems in Heat Exchanger

The most common heat exchanger problem for many chemical engineers is fouling which can
occur within the inside of a tube wall and decrease performance and even damage the heat
exchanger in the long run.

Most common causes of fouling are: Settlement of sludge, rust or dust particles Corrosion

Possible Remedies for fouling problem:

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1. Choosing a material of construction which does not easily corrode or produce voluminous
deposits of corrosion products. If chemical removal of fouling is planned, the material
selected must also be resistant to attack by cleaning solutions.
2. If fouling cannot be prevented from forming, it is necessary to make some provisions for
its periodic removal. Some deposits can be removed by purely chemical means.

Problems in Storage Tanks

Leaking storage tanks, whether above or below ground, can pollute the environment, threaten
public health, and lead to billions of dollars in direct and indirect costs. Main reason for storage
tank failure is corrosion.

Possible solutions to control corrosion in storage tanks:

Common strategies include corrosion-resistant materials, application of coatings and/or linings

as a barrier to the environment, various forms of cathodic protection to prevent deterioration
of tank components in contact with the soil, and use of inhibiting chemicals in stored substances
to control corrosion of the tank interior.

Scaling Problem and possible remedies

Scaling problem takes place due to:

 Evaporation and drying of moisture on hot surfaces.

 Nonhomogeneous nucleation of concentrated droplets and crystals on surfaces.

Possible remedies for corrosion and scaling problems:

 Decreasing concentration of corrosive impurities in makeup and feed water, lower air in
leakage and condenser leakage etc.
 Turbine washing after chemical upsets to remove deposited impurities.

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3.5 MATERIALS STORAGE AND HANDLING FACILITIES

3.5.1 Biogas
Physical Data

Boiling Point -162°C

Density 1.15 kg/m3
Solubility in water Very slightly soluble
Evaporation Rate Gas at normal ambient conditions
Appearance Colorless gas at normal temperature
Odor Odorless

If the local utility company has added an odorant, then an unpleasant smell resembling that of
rotten eggs or garlic.

Storage and handling conditions

Store and use cylinders and tanks in well-ventilated areas, away from heat and sources of
ignition. No smoking near storage or use. Follow standard procedures for handling cylinders,
tanks, and loading/unloading. Fixed storage containers must be grounded and bonded during
transfer of product.

Firefighting and explosion data

Flash point: 187.8 0C

Auto ignition: 5400C

Flammable limits in air: 5% (lower), 15 %(upper)

Unusual fire and explosion hazards

This gas is extremely flammable and forms flammable mixture with air. It burns in the open or
be explosive in confined spaces. Its vapors are lighter than air and disperse, a hazard of re
ignition or explosion exists if flame is extinguished without stopping the gas flow.

Extinguishing Media

Stop the flow of gas. Dry chemical CO2 or halogen. Water can be used to cool the fire but may
not extinguish the fire.

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Special firefighting instructions: Evacuate area upwind of source. Stop gas flow and extinguish
fire. If gas source cannot be shut off immediately, equipment and surfaces exposed to the fire
should be cooled with water to prevent overheating and explosions. Control fire until gas
supply can be shut off.

Health Hazard Data

Effects of Single Overexposure:

Swallowing: This product is a gas at normal temperature/pressure, No potential for ingestion

expected Solid and liquefied forms of this material and pressurized gas can cause freeze burns.

Skin Absorption: This material is not expected to be absorbed through the skin. Solid and
liquefied forms of this material and pressurized gas can cause freeze burns.

Inhalation: Exposure may produce rapid breathing, headache, dizziness, visual disturbances,
muscular weakness, tremors, narcosis, unconsciousness, and death, depending on the
concentration and duration of exposure.

Skin Contact: Non-irritating, but solid and liquid forms of this material and pressurized gas can
cause frostbite, blisters and redness.

Eye Contact: This gas is non-irritating; but direct contact with liquefied/pressurized gas or frost
panicles may produce severe and possible permanent eye damage from freeze burns.

Effects of repeated overexposure:

Medical Conditions Aggravated by Overexposure: Personnel with pre-existing chronic

respiratory diseases should avoid exposure to this material.

Emergency and first aid procedure:

Swallowing: this product is a gas at normal temperature / pressure and not to present a
swallowing hazard.

Skin: frozen tissues should be flooded or soaked with warm water. Do not use hot water.
Cryogenic burns that results in blistering or deeper tissues freezing should be promptly seen by
a doctor.

Inhalation: immediate move personnel to area of fresh air. For respiratory distress, give air,
oxygen or administrator CPR (cardiopulmonary resuscitation) if necessary. Obtain medical
attention if breathing difficulties continues.

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Eyes: methane gas is not expected to present an eye irritation hazard. If contacted by liquid
solid, immediately flush the eyes gently with warm water for at least 15 minutes. Seek medical
attention.

Reactivity and polymerization

Stability: stable

Conditions to avoid: High heat, open flames and other sources of ignition. Explosive reactions
can occur between natural gas and oxidizing agents. Spontaneous ignition with chlorine
dioxide. Incompatibility (materials to avoid): barium peroxide, chlorine dioxide and strong
oxidizing agents.

Hazardous combustion or decomposition products: Combustion may produce carbon

monoxide, carbon dioxide and other harmful substances

Hazardous polymerization: none

Spill, Leaks & disposal procedures

Spill, Leaks or Release: Eliminate all potential sources of Ignition. Handling equipment and
tools must be grounded to prevent sparking. Evacuate all nonessential personnel to an area
upwind. Equip responders with proper protection equipment and advice of hazards- Stop Of
release with non-sparking tools before attempting to put out any fire. Ventilate enclosed areas
to prevent formation of flammable or oxygen-deficient atmospheres. Water may be used to
cool equipment or reduce gas accumulation.

Waste Disposal Procedures: Disposal of containerized gas may be disposal of a hazardous

disposal should be made in accordance with all applicable federal, state, and local and
regulations.

Special protection measures

Ventilation: Local exhaust and general room ventilation may both be essential in work areas to
prevent accumulation of explosive mixtures. If mechanical ventilation is used, electrical
equipment must meet National Electric Code requirements.

Eye Protection: Use chemical-type goggles and face shields when handling liquefied gases.
Safety glasses and/or face shields are recommended when handling high-pressure cylinders
and piping systems or whenever gases arc discharged.

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Skin Protection: If there is a potential for contact with high concentrations of Compressed gas,
use insulated, impervious plastic or neoprene coated canvas gloves and protective gear (Apron,
face shield, etc.) to protect hands and other skin areas.

Respiratory Protection: For excessive gas concentrations, use only NIOSHJMSHA approved,
self-contained breathing apparatus.

Work/Hygiene Practices: Emergency eye wash fountains and safety showers for first aid
treatment of potential freeze burns should be available in the vicinity of any significant
exposure from compressed gas release. Personnel should not enter areas where the atmosphere
is below 19.5 vol. % oxygen without special procedures/equipment. Respirator use should
comply with OSHA 29 CFR 1910.134 or equivalent.

3.5.2 Methyl Di-Ethanol Amine (MDEA)

Physical Properties:

Physical State Clear liquid

Color Colorless – light yellow
Odor Amine-like
pH 11.5 (100 g/L aq. Sol)
Vapor Pressure 0.026 mbar @ 40°C
Viscosity 101 mPa.s @ 20°C
Boiling Point 243°C @ 760 mmHg (469.40 °F)
Freezing Point -21°C
Auto Ignition Temperature 265°C
Flash Point 137°C
Explosion Limits Lower: 0.9 Vol%
Explosion Limits Upper: 8.4 Vol%
Solubility in Water Miscible
Specific Gravity/Density 1.038 g/cm3
Molecular Formula C5H13NO2
Molecular Weight 119.16

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Materials of Storage:

The preferred material for storage of MDEA is 304L or 316L stainless steel. Carbon steel tanks
are also satisfactory, although discoloration and iron in the amine may occur . Nitrogen padding
of the tanks is recommended to prevent oxidation and discoloration of the amine can also be
stored in high-density polyethylene (HDPE) or polypropylene (HDPP).

Materials to avoid include:

 Aluminum
 Copper
 Brass
 Copper alloy

Storage Temperature:

 The recommended minimum temperature for storing and pumping 100% MDA is 200F
(-70C).
 Steam tracing and insulation may be required in cold weather.

Handling and Safety:

 MDEA can cause serious injury to the eyes and may result in permanent eye injury. If
accidental contact with the eyes occurs, flush them thoroughly with water and seek
medical attention.
 Single dose oral toxicity of MDEA is low.
 Swallowing a large amount of MDEA may cause severe burns to the mouth, throat and
digestive tract. If accidental ingestion occurs sick medical attention.
 Accidental ingestion of small amount of empty is not expected to cause injury.
 May cause irritation to the skin. Occasional contact with the skin should be washed off
immediately and should have adverse effects.
 If MDEA is heated or mist, produced concentrations may be sufficient to cause
irritation to the upper respiratory tract.

The following precautions should be observed when the possibility of exposure exists:

 A safety shower and I wash facility located nearby.

 Chemical goggles

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 Protective clothing including chemical resistant gloves

 Well ventilated work area

Accidental release

 Clear non-emergency personnel from the area

 Protect the environment: keep out of sewers, storm drains, surface water and soil
 Contain the spill if possible. Clean up non-combustible absorbent. Do not use sawdust.

Potential Health Effects:

Eye: Causes eye irritation.

Skin: may cause skin irritation. May be harmful if absorbed through the skin

Ingestion: may cause irritation of the digestive tract.

Inhalation: may cause respiratory tract irritation. May be harmful if inhaled

First aid measures

Eyes: flush eyes with plenty of water for at least 15 minutes .Occasionally lifting the upper and
lower eyelids. Get medical aid.

Skin: get medical aid. Flush skin with plenty of water for at least 15 minutes while removing
contaminated clothing and shoes.

Ingestion: get medical aid. Wash mouth out with water.

Inhalation: remove from exposure and move to fresh air.

Immediate potential health effects

Skin: may cause skin irritation. Maybe harmful if absorbed through the skin.

Ingestion: may cause respiratory tract irritation. Maybe harmful if inhaled.

Inhalation: may cause respiratory tract irritation. Maybe harmful if inhaled.

Firefighting Measures:

General information: as in any fire, wear a self- contained breathing apparatus in pressure-
demand .MSHA/NIOSH (approved or equivalent), and fully protective gear. Extinguishing
Media: in case of fire, use water, dry chemical, chemical foam, or alcohol-resistant foam.

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3.5.3 Steam
Physical properties

Physical State Gas

Color Colorless
pH 7-9 (slightly alkaline)
Boiling Point 101.07°C @ 760 mmHg
Auto-ignition temperature N/A
Flash Point N/A
Decomposition temperature N/A
Molecular Weight 18.02
Molecular Formula H2O
Density 1.27 g/L @ 273 K

Storage of steam

A steam accumulator is an insulated steel pressure tank containing hot water and steam under
pressure. It is a type of energy storage device. It can be used to smooth out peaks and troughs
in demand for steam. Steam accumulators may take on a significance for energy storage in
solar thermal energy projects. The tank is about half-filled with cold water and steam is blown
in from a boiler via a perforated pipe near the bottom of the drum. Some of the steam condenses
and heats the water. The remainder fills the space above the water level. When the accumulator
is fully charged the condensed steam will have raised the water level in the drum to about three
quarters full and the temperature and pressure will also have risen.

Handling and safety

Sodium-ion monitoring can prevent steam-turbine corrosion Studies have shown that sodium
is one of the most significant contributors to corrosion within turbines, and that such corrosion
leads to cracking, embrittlement and ultimately, turbine failure. The Orion Ion plus 2111LL
low-level sodium monitor is used to track sodium ion concentrations of steam and other pure-
water circuits within the power industry.

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Safety

Steam may seem less harmful than hot water, but this is not the case. Steam can cause serious
injuries, and taking the correct safety precautions when using any equipment that produces
steam is essential.

1. Hazards: The main danger associated with steam is burns or scalding to the skin. Water
will scald at 120 degrees Fahrenheit. Another hazard of steam is poor visibility. Steam will
"cloud" the air, making it difficult to see what you are actually doing, which could lead to
other accidents. Steam is still water and steam getting near electrical appliances or plug
sockets could lead to an electric shock. If you are working with steam on or near a floor,
the risk of slipping or falling also exists.
2. Protective Clothing: To ensure that you do not get burned or scalded, do not use steam
above 120 degrees Fahrenheit for cleaning or other tasks. If you need to use steam at a
higher temperature, wear protective clothing, such as gloves, face shield, eye protection,
long apron and boots.
3. Other Precautions: To ensure that you do not get an electric shock, make sure that you
work away from plugs, sockets and electrical equipment, or cover electrical equipment and
ensure that it is completely dry before using. Place non-slip mats on the floor if there is a
danger of it getting wet. If a steam cloud appears, stop working and wait for the cloud to
dissipate before resuming your task.

There are immediate steps to after a steam burn is sustained to the skin.

Steps to Take After a Steam Burn

1. Remove the threat.

2. Stop the burning process.
3. Cover the burn injuries.
4. Transport the patient to a burn center.

1. Remove the Threat

The most important treatment step for any burn injury is to eliminate cause for any further
injury (whether you are the one who has sustained a steam burn or you are helping someone
who has). The first step is to turn off the source of the heat.

2. Stop the Process

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The second step is to stop the burning process by running cool tap water over burned areas
until the area is cool to the touch (even if the patient feels relief before this). The cool water
reduces the temperature of burn injuries. It might take flushing the area with cool water for up
to twenty minutes to completely stop the burning process and make sure the patient is not going
to get worse.

3. Cover and Transport

Next, cover the burn injuries with a dry, sterile dressing. Finally, in cases where the total burn
injury is larger than 9 percent of the entire body (see the Rule of Nines), the patient needs to
be transported by ambulance to a burn center. Call ambulance if the steam burn or scald
includes the patient's face, entire hand, entire foot, or genitalia.

If the patient does not need an ambulance, take the following short-term treatment steps after
a steam burn is sustained:

1. Keep the injury covered in a dry, sterile dressing. Change these daily and maintain the
dressings for at least 10 days until the injured area appears to be healing and the patient
can tolerate exposure to air.
2. Take over-the-counter (OTC) pain medication for pain control.
3. If the injured area develops signs of infection, contact a physician immediately.
4. In cases where the patient did not seek medical treatment but becomes short of breath
at any time after a steam injury, call 911 immediately. Steam in the throat can lead to
swelling in the airway hours later.

If the patient requires immediate treatment for her injuries, the hospital may send her to a burn
center. Treatment at a burn center could include debridement (scrubbing away dead tissue) to
reduce scarring as well as intravenous pain medication. Patients may be hospitalized for two to
three weeks in a burn center.

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3.6 PROCESS INSTRUMENTATION & CONTROL AND SAFETY ASPECTS

Process instrumentation and control aid the economic function of any operation by maintaining,
improving and controlling the various process parameters like flow rates, temperature,
pressure, level, composition etc. An efficiently controlled process plant system also ensures
greater safety as its operation.

Instrumentation is provided to monitor the key process variables during plant operation. They
may be incorporated in automatic control loops or used the manual monitoring of the process
operation. Instruments monitoring critical process variables will be fitted with automatic
alarms to alert the operators to critical and hazardous situations. For control of the distillation
columns, the continuous, on line analysis of the overhead products desirable but difficult and
expensive to achieve reliably so temperature is often monitor, indicator of composition. The
temperature instrument may form part of a control loop control say reflux flow, with the
composition of the overhead checked frequently by sampling and lab analysis.

Instrumentation claims the following advantages:

Control

It controls all those parameters, which control the process and do not allow them to cross safe
limit thereby enabling smooth and safe operation.

Safety

An efficient controlled plant possesses high safety by carefully monitoring potential hazards.
like fire, explosion, toxicity etc.

Product Quality

By the monitoring of the process parameters like temperature, pressure and composition
streams of reaction vessel, it guarantees the quality of the product.

Motivation behind Process Control

An industrial process consists of a number of unit operations interconnected to produce the

desired results i.e. conversion of feedstock into products. Equipment is chosen to carry out
required operation. During the operation the plant must satisfy the several requirements
imposed by its desi and general technical, economic and social conditions in presence of ever
changing at disturbance’s or influences.

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Following are the reasons behind control and instrumentation in industries-

1. Production specifications & Optimization

A plant should produce desired amount and quality of the final Product. To produce and
maintain the final product composition desired, chemical process control is essential.

2. Process Safety & Human Safety

The safe operation of a chemical process is a primary requirement for the wellbeing of the
people in the Plant and for its continued contribution to the economic development.

3. Environmental Safety & regulations

Various central and state laws may specify the allowable limits of temperature, concenteratin
of flow rates of effluents from the plant. Environmental pollution must be minimized by
pollution control strategies.

4. Operational Limits of Equipment

The various types of equipment used in plants have constraint inherent to their operation. Such
constraint should be satisfied throughout the operation of the plant. For e.g. pumps must
maintain a certain NPSII, tanks should not overflow or go dry, distillation columns should not
be flooded, the temperature in catalytic reactors should not exceed the range of the catalyst.

5. Measurement Aspects

Every type of equipment has its special measurement requirements. The guiding principle is to
determine the actual value that is to be controlled and to install instrumentation that will
measure that precise value.

6. Cost Competitiveness

The operation of a plant must confirm to the market condition, the availability of materials and
demand of the final products. Further it should be as economical as possible in the utilization
of raw materials, energy, capital and labour.

There are three key elements leading to fire and explosions known as fire triangle.

Safety can be achieved by removing at least one of the elements in the environment around
instrumentation.

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1. Fuel: A controlled environment can be purged with air inert to remove fuel.

2. Oxygen: The environment around an Instrument can be immersed in liquid , solid that will
prevent oxygen from being affected by the source of ignition

3. Ignition: The power source can be maintained below the critical value that could initiate fire
or explosion.

Contaminant: An instrument can be surrounded with an enclosure that can contain explosion
within the small region, where it will extinguish quickly because of lack of fuel and oxygen.
This approach is also termed explosion proofing or flame proofing.

Instrumentation and Control in Heat Exchangers

The objective of a heat exchanger control is to maintain a specified product outlet enthalpy. A
computerized control system can be designed to achieve this goal

The heat balance equation of a product to product exchanger is:

Hp = Cp1 (T1-T0) + Cp2 F2/F1 (T3 - T2)

Where, Hp = Heated stream outlet enthalpy

Cp1 = Specific heat of cold stream inlet

T1 = Inlet temperature of cold stream

T0 = Reference temperature

Cp2= Specific heat of hot stream

F2= Flow rate of hot stream

F1 = Flow rate of cold stream,

T2 = Outlet temperature of hot stream,

T3 = Inlet temperature of hot stream

The equation can be mechanized and the calculated enthalpy used as measurement signal to a
standard controller.

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Two types of advanced control strategies can be employed in designing the Control System of
a heat exchanger -

1. Using feed forward controller:

Type of Controller Controlled Variable Manipulated Measurement

Variable
Feed Forward Temperature Steam Inflow Temperature

2. Using feed backward controller

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Type of Controller Controlled Variable Manipulated Measurement

Variable
Feed Backward Temperature Steam Inflow Temperature

Safety Aspects:

1. Control system for Maximum Pressure Drop can be in place as is in the case of Heat
Exchanger.
2. The maximum pressure drop on the shell side is controlled by simple feedback and a
proportional controller.

Instrumentation and Control in Distillation Column

The inventory controls on the distillation column are the level controllers which replaces to
depletion and accumulation of material within the column.

Following points are taken into account for control:

1. Pressure drop across the column is a crucial factor in the distillation. To maintain and
control it we employed PI controllers. The flow of feed stream and the flow of steam in
reboiler are controlled by this.
2. The flow of cooling water into the condenser is maintained and control via pressure
controller at the top.
3. Flow of the top product (output from condenser) is maintained and controlled by using
controller and reflux is maintained by using temperature controller (PIO) which measures
the column temperature.
4. Ratio controller is employed to maintain and control the flow of bottom stream between
feed stream and bottom stream.

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Following is the control systems layout for distillation column systems

Independent Variables Output(dependent) variables

(Uncontrolled) Manipulated
Feed Composition Reflux Ratio Distillate Composition
Feed Rate Boil up rate Bottom Composition
Feed Enthalpy Distillate Rate Tray Temperature
Reflux temperature Bottom product rate Rebolier Level
Steam enthalpy Colum Pressure Accumulator Pressure
Safety Aspects:

1. Pressure drop limits must be kept in mind by using PI controller.

2. Flow of cooling water must be controlled appropriately using Proportional, pressure.

3. Advanced control strategies must be applied for required distillation like controller b/w feed
and bottom stream.

4. Rebolier must be controlled carefully to avoid accidents

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The automatic controls to distillation column are tabulated below-

Load Variables Measuring Element Controller Final Control

Element
Feed Flow rate Orifice meter PI Pneumatic pressure
on flow line
Colum Pressure Bonded strain gauge PID Pneumatic pressure
on overhead line
Steam rate Orifice meter PI Pneumatic pressure
in steam line
Distillate Level Controller P Pneumatic pressure
in distillate
Bottom rate Level Controller P Pneumatic pressure
on bottom line
Stripper bottom Thermocouple P Pneumatic pressure
temperature on boiler flow line
Overhead Vapor Thermocouple P Pneumatic pressure
Temperature on reflux line
Boot Water Level Controller P Pneumatic pressure
on boot water
Stripper overhead Thermocouple P Pneumatic Control
rate on Stripper overhead
line

P - Proportional controller

PI - Proportional integral controller

PID- Proportional integral controller

Pressure Control on Overhead line:

The distillation column is based on maintaining the column pressure at constant value. Any
variation in column pressure will upset the control system by changing the equilibrium
conditions of materials in the drum. The set of pressure is a compromise between two extremes.

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The column pressure quickly responds to be overhead flow rate. Hence pressure control line is
used to modulate the flow. The HIC installed on the flare line is cascaded with the pH res MR
1 is used to operate in case of very high pressure.

Level Controls on Reflux Drum

The level of condensed overhead vapors in the reflux drum is maintained constant. The reflux
drum acts as surge. The distillate flow rate is modulated for a quick response in liquid level.
The contra, on distillate line is cascaded with reflux drum level control for manipulation.

The boot water flow control is cascaded with another level controller on reflux drum which
keeps the boot water level to minimum.

Level control on column bottom

Liquid level at the bottom of the column is maintained to avoid any dry up or upset due to in
pressure or temperature. Column bottom level is highly sensitive with the bottoms flow rate.
Hence the level is modulated by manipulating the bottoms flow rate. The flow controller on
the bottoms line is cascaded with the level controller mounted at the column bottom.

Safety Measures:

1. The reflux ratio is controlled by the ratio controller.

2. Flow of cooling water into the condenser is maintained and controlled by using temperature
controller which is measuring the temperature of recycle stream into the column.

Controlled Variable Instrumentation Manipulated Type of Controllers

Variable
Temperature Temperature Cooling water flow PID
Measurement in
Instrumentation and Control in Flash Tank separator

The pressure in the flash tank is controlled by controlling the opening of the valve across which
the pressure drop takes place.

Controlled Variable Instrumentation Manipulated Type of Controllers

Variable
Flash Tank Pressure Pressure Gauge Opening of the Valve PID

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Instrumentation and Control in a Reactor

I. The temperature in the reactor is controlled by using a temperature measurement device and
controlling the flow of steam to the reboiler.

2. The temperature of the outlet recycled stream is controlled by using a temperature

measurement device and controlling the inlet flow rate of water to the condenser.

3. The flow of the outlet stream of the condenser is measured by using a flow measurement
device and controlling the opening of the valve.

4. The liquid level in the reboiler is measured by using a level measurement device and is
controlled by controlling the outlet flow rate.

Controlled Variable Instrumentation Manipulated Type of Controllers

Variable
Regenerator Thermocouple Steam Flow rate PID
Temperature
Condenser Outlet Thermocouple Cooling water flow PID
Temperature rate
Condenser Outlet Orifcemeter Valve Opening PI
flow
Reboiler liquid Level Level Measurement Outlet Flow rate PI
Instrumentation and Control in a Condenser

1. A temperature measurement device is used to measure the temperature of the recycled stream
of the condenser and the temperature is controlled by controlling the flow of water to the
condenser.

2. A level measurement device is used to control the water level in the condenser which controls
the flow rate of the outlet stream.

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Instrumentation and Control in a Cooler

The outlet temperature of the cooler is controlled measuring its temperature and using a feed
forward controller for manipulating the flow rate of entering water to control the outlet
temperature.

Controlled Variable Instrumentation Manipulated Type of Controllers

Variable
Cooler-Outlet Temperature Cooling water flow Feed-Back
Temperature measurement rate Controller

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4 ENVIRONMENTAL PROTECTION & ENERGY

CONSERVATION

4.1 ENVIRONMENTAL ASPECTS

The International Standards are based on the methodology known as Plan-Do-Check-Act

(PDCA). PDCA can be briefly described as follows:

Plan: Establish the objectives and processes necessary to deliver results in accordance
with the organization’s environmental policy.

Do: Implement the process.

Check: Monitor and measure processes against environmental policy, objectives,

targets, legal and other requirements, and report the results.

Act: Take actions to continually improve performance of the environmental

management system. Many organizations manage their operations via the application of a
system of processes and their interactions, which can be referred to as the “process approach”.
Since PDCA can be applied to all processes, the two methodologies are considered to be
compatible.

Classification of emission sources:

Point Sources:

 Combustion sources
 Intermittent vents
 Storage emission
 Condensed stream and treatment system

Non Point Sources:

 Equipment leaks
 Cooling water, waste-water collection and treatment system

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Air Pollution

The sources of air pollution encountered in the plant are-

Carbon Dioxide: The CO2 from the furnace and from final separator is being sent to carbon
sequestration unit. Industrial Standard: 250-350 ppm Ambient Air

Carbon Sequestration: Carbon sequestration describes long-term storage of carbon dioxide

or other forms of carbon to either mitigate or defer global warming and avoid dangerous climate
change. It has been proposed as a way to slow the atmospheric and marine accumulation of
greenhouse gases, which are released.

Carbon dioxide is naturally captured from the atmosphere through biological, chemical or
physical processes. Some artificial sequestration techniques exploit these natural processes,
while some use entirely artificial processes.

Carbon dioxide may be captured as a pure by-product in processes related to petroleum refining
or from flue gases from power generation. CO2 sequestration includes the storage part of carbon
capture and storage, which refers to large-scale, artificial capture and sequestration of
industrially produced CO2 using subsurface saline aquifers, reservoirs, ocean water, aging oil
fields, or other carbon sinks.

Carbon Monoxide:

Possible Source: Purge Stream

Effluent Time Average Concentration Method of Concentration

in Ambient Air Measurement in Residual
Industrial Area
CO 8 hrs 5 mg/m3 Non Dispersive 2
Infrared
Spectroscopy
CO 1 hrs 10 mg/m3 4

Treatment of Carbon Monoxide:

 Install an effective ventilation system that will remove CO from work areas.
 Catalysts for CO-selective methanation
 Catalysts for CO-selective oxidation

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b. Liquid Effluent:

Release of various used chemicals, waste water to river, canal etc. cause water pollution.
Amount of some of contaminant present may be higher, thus causes various diseases, mutation
(high concentration). The flow, type and concentration of pollutant depend on process and
water used.

Release of various used chemicals, waste water to river, canals, etc. cause water pollution.
Amount of some of contaminant present may be higher, thus causes various diseases, mutation
(high concentration). The flow, type and concentration of pollutant depend on process and
water used.

The liquid effluent may contain Mono Diethanolamine which is toxic.

b. i. Possible Sources:

1. Leaks from pipelines (chemicals)

2. Tanks areas including unloading and loading facilities for raw material intermediate
product and finished product.
3. Spillage and leakage from unit.
4. Absorber bottom stream

b. ii. Effluent Standards:

The water act 1974 to provide prevention of control of water pollution and maintaining
wholesomeness of water. (Applicable in all states)

b. iii. Necessary Treatment:

 Waste water treatment

 Use storage tank for treatment
 Appropriate Chemicals for neutralizing harmful chemical.
 Color doesn’t have significant pollution but should be removed as much as possible.
Chemical coagulation is an effective method to reduce the color level of the raw water.
 Gravity settling tank, filtration are employed for removal of suspended solid present.

Dissolved organic matter which escapes the settling tank are removed by microbes consuming
the organic matter as food, and converting it to carbon dioxide, water and energy for their own
growth and reproduction. Also reduces biological oxygen demand of water.

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Disinfection with chlorine: Removes or deactivate or kill pathogenic microorganisms.

Microorganisms are destroyed or deactivated, resulting in termination of growth and
reproduction

c. Solid effluents

Possible source: Solid disposal of carbon from reformer.

Treatment: Disposal is done by thermal incineration or by tipping (landfilling). The design of

a solid waste incinerator is difficult to do due to the wide variety of feed to be disposed. It is
thus important to determine the burning characteristics of the solid carbon material.

A major problem with solid incinerator is fly ash control. Various methods employed for this
purpose are two-stage combustion, filter baffle and provision of large secondary chambers
where velocities are low and settling takes place. If the fly ash problem is chronic, special
separation devices like electrostatic precipitators can be employed. The flash produced can be
used as a landfill.

d. Noise Pollution

Noise has recently been recognized as a pollutant. It is a great means in thickly populated area.
There is simple evidence that affects speech, hearing and general health of people exposed to
it over an extended period.

In our process noise is produced from various types of columns and various mechanical
equipment like compressors, reactors etc. This type of noise possesses a potential damage to
the various plant personal who work very close to this equipment.

Various equipment that would be used in the production of dimethyl ether, their noise levels
and control measures are listed in the table below:

Equipment Sound Level (dB) Possible noise control measures

Pumps 75-90 Acoustically lined fan covers, enclosures and
motor mutes
Electric Motors 90-110 Acoustically lined fan covers, enclosures and
motor mutes
Valves 80-108 Avoidance of sonic velocities, limited pressure
drop and mass flow, replacement with special
low noise valves, vibration isolators and

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lagging
Piping 90-105 Inline silencers, vibration isolators and lagging
Heaters and Furnaces 90-110 Acoustic plenums, intake mufflers, lined/
damped ducts

Generalized recommendations to reduce noise with rose of trees and shrubs include:

 Plant the noise buffer close to the noise source (rather than close to the area to be
protected).
 Plant trees/shrubs as close together as the species will allow and not be overly inhibited.
 When possible use plant with dense foliage. A diversity tree species, with a range of
foliage shapes and sizes within the noise buffer may also improve noise reduction.
 Foliage of the plants should persist from the ground up. A combination of shrubs and
trees may be necessary to achieve this effect.
 Evergreen varieties that retain their leaves will give better year-round protection.
 When possible use tall plants. Where the use of tall trees is restricted, use combinations
of shorter shrubs and tall grass or similar soft ground cover as opposed to harder paved
surfaces.

4.2 ENERGY CONSERVATION

With the rising population of the world and rapidly increasing per capita consumption in the
developing countries, energy conservation as become the focus of attention all around the
world, particularly in energy intensive petrochemical industry.

The fast depleting petroleum resources, which are estimated to be just around 89×109 barrels
as reserves (sufficient for just another 30 years) have let to the exploration of new energy
resources. In this context, both conventional and non-conventional sources of energy are to be
studied.

Energy Conservation Measures

The increasing cost of primary fuel has broadened the range of the heat recovery applications
that can be economically justified. In a typical chemical concern with a profit margin of Rs. 4
per 100 sales, a saving of Rs. 1 in energy cost is approximately equivalent to an increase of Rs.

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25 in sales. The entire gamut of energy conservation operations can be classified into two broad
categories:

a) Energy Concept
The term energy has its origin in last of thermodynamics. It can be redefined in terms
of enthalpy or entropy change or temperature difference. In each process, the sum of all
the inputs are always greater than the sum of all the outputs, the difference being the
energy losses. The endeavor of all energy conservation step is to minimize this energy
loss.
b) Pinch Concept
Every chemical industry used cold and hot streams. The hot streams are cooled while
the cold streams get heated up. These are called the hot and cold end “Approach”. ∆T,
that is, the temperature difference between hot and cold end need not remain same
through the temperature range. In a grand composite curve, all the hot and cold streams
are combined to form the hot composite and cold composite respectively. There is a
situation when ∆T becomes minimum. This point of closest approach is called pinch of
the integrated heat exchanger (HEN) and signifies zero heat transfer in the grand
composite curve. To achieve energy conservation, the following three rules must be
followed:
- No heat transfer across the pinch.
- No cooling above the pinch.
- No heating below the pinch.

Apart from the above, some more measures taken for the energy conservation are:

1. Recover from the process:

Reuse the bottoms of the distillation columns and to preheat the feed to the
distillation columns. The heated product from methanol reactor is used to preheat
the reactor feed.

2. Computer control:

Computer control of critical parameter in the plant provides another opportunity for
saving energy and increasing the capacity utilization. With the help of the optimal
control, energy consumption can be minimized

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5 PLANT UTILITIES
In chemical process plants, plant utilities play a critical role in supporting the operation of the
facility. Typical plant utilities include steam, electricity, refrigerants, inlet water sources,
compressed air, industrial gases, heat transfer fluids, cooling towers, and more. Proper design,
operation and maintenance of the engineering systems needed to provide these items is key.

5.1 HEAT TRANSFER MEDIA

Heating utilities are necessary for proper usage of distillers, reactors, condensers, and several
other integral types of equipment. More specifically, steam, fired heat, and hot oil/specialized
heat transfer fluids.

5.1.1 Type and Requirement

Steam is the most commonly used heat utility used in chemical plants, and as a result
understanding how it is used is essential in the study of Utility systems. Steam is used both as
a process fluid and utility.

Here are a few advantages of using steam as opposed to other methods of process heating:

1. By controlling the pressure of the steam, one can control the temperature at which the heat
is released.

2. Steam is an efficient heat source because the heat of condensation of steam is very high.

3. Heat exchangers that use steam are relatively cheap because condensing steam has a high
heat transfer coefficient.

4. Steam is non-flammable, nontoxic, and inert to several process fluids.

5.1.2 Steam Generation System

Chemical plants generally have a network of pipelines exclusively for providing steam. These
networks generally have steam at a low pressure, a medium pressure, and a high pressure.

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In the diagram above, boiler feed water at a high pressure is preheated and fed to other boilers.
These other boilers superheat the steam to create a high pressure and high temperature steam
stream. The steam is superheated past the dew point to account for heat loss in the pipelines. A
portion of the high pressure steam is used for process heating in areas of the plant that require
high temperatures. The rest of the high pressure steam is turned into medium pressure steam
by valves and steam turbines. The medium pressure steam is then used to heat medium
temperature processes and to form low pressure steam. The low pressure steam can be used to
heat low pressure processes and it can be expanded in condensing turbines to create shaft work
and energy. In summary, steam can be used for an innumerable amount of action items in a
plant. High pressure, medium pressure, and low pressure steam can all be used as a heat source.
Low pressure steam has utilities in creating electricity and it also has several other uses.

5.2 ELECTRICITY/ POWER

Power is required for pumps, compressors and lighting purposes. For further distribution of
power, a substation in the plant is essential. We shall use a captive power plant, the pressure of
steam is brought down in turbines and the electricity generated is used to run the plant. If any
extra power is required at any time, we can buy some grid power.

The plant consumes electricity in the following areas:

1. All pumps require electrical power for their operation.

2. All blowers and compressors require electrical power for their operation.

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3. Control room requires power for its operation.

5.3 WATER

5.3.1 Process and General Water Requirement and Standard

Use of Raw Water: A plant water supply is separated into process, boiler feed, cooling, potable,
fire water and utility water systems. Brief descriptions of the different water uses in refineries
are given below.

Process Water: Water is typically used for various purposes where the water is closely
contacted with the hydrocarbons. Softened water is usually used for these purposes.

Cooling Water: Water-cooled condensers, product coolers (heat exchangers) and other heat
exchangers can use a large amount of water in a refinery. Some refineries use air coolers, where
the process stream is exchanged with air prior the being sent to a cooling water heat exchanger.
This will minimize the use of cooling water in the refinery.

Fire Water: The requirements for fire water in refineries are intermittent, but can constitute a
very large flow. Often, refineries collect storm water from non-process areas and store it in a
reservoir dedicated to the fire water system in the plant. Provisions are typically made for a
connection (for use in emergency situations) of the fire water system into the largest available
reservoir of water. Usually this is the raw water supply since fire water requires no treatment.
Sea water or brackish water is often used as fire water by plants located along coastal areas.

Potable Water: Potable water is required for use in kitchens, wash areas and bathrooms in
refineries as well as in safety showers/eyewash stations. City water or treated groundwater can
be used for this purpose. In remote locations or in small towns a portion of the treated water
from the plant softening unit may be diverted for potable water use. The treated water must be
chlorinated to destroy bacteria, and then pumped in an independent system to prevent potential
cross-contamination. Potable quality water may also be required in some specialist chemical
operations (e.g. as a diluent).

Utility Water: Utility water is used for miscellaneous washing operations, such as cleaning an
operating area. It should be free from sediment but does not require any other treatment.

5.3.2 Water Treatment

The raw water treatment in a plant creates wastewater and sludge that require disposal. The
following section describes the best practices with respect to these discharges.

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Lime softening: When lime softening is used for raw water treatment, the sludge generated in
this process should be thickened, and optionally dewatered. The thickener overflow water can
be discharged directly without any further treatment, when local regulations allow. The sludge
that is generated should be disposed off-site. Not discharging it to the sewer in the refinery will
prevent the introduction of inert solids into the sewer in the refinery which in turn will avoid
creation of more oil sludge that requires disposal.

Sour Water: The typical treatment for sour water is to send it to a stripper for removal of H 2
S and CO2. Steam is used to inject heat into the strippers. High performance strippers are able
to achieve < 1 ppm H2S and < 30 ppm CO2 in the stripped sour water. In sour water stripper,
all the sour water produced in the refinery is flashed in a drum and any separated oil is sent to
refinery slops. The vapours from this drum are sent to the flare. The sour water from the drum
is then sent to a storage tank which provides the required surge in the system. The sour water
is then passed through a feed/bottoms exchanger where it is heated up and then sent to the
stripper. The separated vapors containing H2S and co2 are sent to the Sulphur plant. The
stripped water is routed via the feed/bottoms exchanger and a trim cooler for reuse in the
refinery. Any excess water that cannot be reused would be sent to a wastewater treatment plant.

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6 ORGANIZATIONAL STRUCTURE & MANPOWER

MANAGEMENT

Need for an organization; A proper organization would assist in the most effective use the
physical assets-plants and machinery, tools, material and supplies. The human resource of the
industry should be skilled so that the unit may be perpetuated and the objectives, including that
of profit, may be achieved. The need for organization grows with the increase in the size of the
unit. The concept of the organization has five basic elements namely:

1. The assembly of men, machines, materials and money to produce a product in the unit
in accordance with the plan.

2. The identification and grouping of the work, i.e., work division and work allotment.

3. Definition of responsibility for every function.

4. Delegation of appropriate authority.

5. The establishment of structural relationships.

An organization provides the mechanism for purposive, integrated development. According to

Herbert Simon, the term organization suggests the complex pattern of communication and other
relation in a group of human beings. Thus pattern provides to each member of the group much
of the information , assumptions, goals , and attitudes that cuter into his decision , provides him
also with a set of stable comprehensible expectations as to what the other members of the group
are doing , and they will react to what he says and does.

The success of organization depends upon the behavior of human beings. An organization
structure is a framework which holds the various functions together according to the pattern,
order topical and legal arrangements in- built relationships.

Importance of organization: Organization is the foundation of management.it is processes in

which individuals interact to accomplish define objectives. Organization has the following
advantages:

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 It encourages specialization and ensures higher productivity.

 It streamlines the process of activities and ensures their smooth functioning.

Duplication of and consequent confusion as well as wasted, effort are likely to be
removed if there is an adequate organization and fixing of responsibility.

 It focuses on co-ordination of various in an integrated manner towards the attainment

of specific objectives.

 It facilitates a precise and effective delegation of authority.

 It ensures a proper direction, motivation, co-ordination and control.

 It aids in the expansion and growth of an enterprise. A sound organizational plan avoids
all the pitfalls of rapid growth.

 It provides for the optimum use of technological improvement and manpower for higher
growth.

 An effective organization promotes growth and diversification though decentralization

and divisionalisation on geographical or on product basis.

Organization structure should manage conflict so that it helps the company rather than tears it
apart. It is helpful to understand the basic determination of power in organizations and how
conflicts are related.

No single ultimate criteria of effectiveness can be found organizational effectiveness includes

at minimum the following criteria;

 Organizational efficiency.

 Adaptability to extend changes.

 Satisfaction of individual needs.

Board of directors:

1. Establish objectives.

2. Overall accountability.

3. Operate business to accomplish objectives.

4. Align the interests of stockholders (owners) and the management of the firm.

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Operating management:

1. Overall coordination and activities.

2. Necessary to accomplish objectives.

3. Meet targets as established by stockholders and the board

It is very important and most essential to specify the kind of structural organization and the
total labor to requirement of the plant complex. Before beginning the construction and
commissioning of the plant. Sufficient capita, good equipment and efficient technology will
not be able to achieve the aim of efficient production alone, without good organization set up.
The operating management and the labor are two of the most important factors, which
contribute to the efficient functioning of the production unit.

Types of structure:

Keeping in view the above three types of organization structure which exists, normally:

(a) Functional: Where each major function of the report to the company’s president. Here
similar activities function together and may be grouped as safety, production, marketing,
finance and so on. This is more suitable to chemical engineering where the market demand and
technology do not change as rapidly as is the realm of computers.

(b) Product: Here the vice president of major groups report the to the president. At the next
level Departments are organized on a functional basis. Hence there would be a vice president
in charge of products of special chemicals for new materials and so on .Each vice president is
responsible for a particular

(c) Regional: This third method groups organizations according to reigns and is more suited
to banks and railways. Here we have northern zone, southern zone and so on.

The organization structure shown in the chart is more economically and in chemical and
process industries.

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DIVISIONS OF ORGANIZATION:

Keeping the above factors in the mind the organization can be divided into following
categories:

(a) Safety Division

(b) Production Division

(c) Marketing Division

(d) Finance Division

(e) Human Resources Division

(f) Quality Service Division

(g) Staff and labor

(a) Safety Division: A Vice President heads the safety division of the plant. Aim of this
department is:

 To ensure all activities are carried out safely

 To conduct safety training sessions for the employees and laborers

 To conduct safety audits and ensure proper functioning of fail safe equipment

(b) Production Division: The department is headed by Vice President assisted by various
managers. He is a technical man and is responsible for the overall production and the smooth
functioning of the plant which would include managing the throughput of the plant. This
division has an experience maintenance engineer who looks after the proper functioning of the
equipment.

(c) Marketing Division: The marketing manager heads it. He is the responsible for the
development of the new marketing strategies and publicity, advertising and sales of product.
Moreover, this department also contains various executives who are expected to make product
sales (on ground salesman).

(d) Finance Division: They take care of the plant expenses and budgeting. He is associated in
his work by the chief accountant and his staff.

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(e) Human Resource Division: It is managed by various managers who have an expertise in
business management. They are skilled in human psychology and deal with various day to day
plant disputes, compensation scale of employees and various employee oriented
bonding/coordination activities.

(f) R&D Department: This department includes scientists who work in the area of chemistry
and chemical engineering enhancing the plant performance in terms of using better
technologies to enhance product yields. Moreover, they also have quality officers whose job is
to check the quality of produced product and its quality as compared to market and company
standards, and suggest any amendments if any.

(g) Staff and labor: Staff and labor can be divided into:

 Technical Skilled (engineers)

 Technical unskilled labor(operations)

Every chemical industry requires a proper mixture of both to ensure smooth operation of the
plant. The Vessels rule and the rule of thumb are two methods that have been suggested to
determine the man power requirement.

ORGANISATION COMPENSATION SCHEME

Grade Gross salary (per month in rupees)

A0 6,00,000

A1 4,50,000

A2 3,00,000

A3 2,10,000

A4 1,50,000

A5 54,000

A6 25,500

B0 1,50,000

B1 60,000

B2 18,000

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Designation Minimum education Number Grade

qualification

President BTech +MBA with at least 20 1 A0

years experience

Vice President BTech+MBA with at least 15 2 A1

years experience

Administration

General Manager BTech+MBA with at least 12 2 A3

Medical Officers years experience

Legal Head LLB 1 A3

Security Head Retired army officer 1 A3

Fire and Safety Head Graduate(B.A.) 1 A3

Fire Man Diploma 5 A6

Medical Staff Diploma 4 A6

Personal(HR)

General Manager BTech+MBA with at least 12 1 A2

years experience

Staff Graduate 4 A5

Finance

General Manager CA with 10 years of experience 1 A2

Accountants M.com 4 A4

Production

General Manager BTech+MBA with at least 12 1 A2

years experience

Managers BTech(chemical) 4 A4

Shift Engineers BTech(chemical) 12 B0

Operators BTech(chemical) 16 B1

Labor BTech(chemical) 30 B2

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Technical

General Manager BTech(chemical) with 5 years 1 A2

experience

Engineers BTech 10 B0

Staff Graduate 12 B1

Maintenance

Senior Manager BTech(chemical) with 5 years 1 A3

experience

Engineer BTech(chemical) with 5 years 2 A4

experience

Operator Diploma 6 B1

Labor High School 10 B2

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7 MARKET PROSPECTS

7.1 A BRIEF ANALYSIS OF DEMAND AND SUPPLY OF THE PRODUCT

According to IHS Markit, global demand of methanol reached 75 million metric tons in 2015
(24 billion gallons/91 billion liters), driven in large part emerging energy applications for
methanol which now account for 40% of methanol consumption. China is leading the world
with the largest production of Methanol. China with 47 Million Tons (MT) of production in
2015 accounted for 55% of the global methanol production (85MT).

Fig. 5 (Source: Methanol Institute12)

The two figures above depict the sectoral consumption of methanol globally and in China in
2015. India is at a nascent stage in methanol production and usage, but it has a large potential
given its wide applications. There are 5 main producers of methanol in India –

i. Gujarat Narmada Valley Fertilizer & Chemicals limited

ii. Deepak Fertilizers

iii. Rashtriya Chemicals and Fertilizers

iv. Assam petrochemicals

v. National Fertilizers Limited

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The following figures would give an overview of the methanol industry in India.
Capacity Domestic Consumption Capacity
Year (MT) Production (MT) (MT) Utilization (%)
2010-11 0.496 0.375 1.14 76%
2011-12 0.496 0.360 1.44 73%
2012-13 0.474 0.255 1.47 54%
2013-14 0.474 0.307 1.54 65%
2014-15 0.474 0.210 1.80 44%
2015-16 0.474 0.163 1.83 34%
Table 4
(Source – Ministry of Chemicals and Petrochemicals12)
Table 3 suggests that the domestic production of methanol has fallen by 57% from 2010-11 to
2015-16, whereas the consumption has risen by 61% over the same period. Since, the installed
production capacity of methanol has largely been static, falling domestic production has led to
constant decline in the capacity utilization factors of Methanol Industry. In 2015, the per liter
cost of methanol production in India was INR 25-27 or even more depending on the volatility
in the price of imported natural gas. India Methanol demand is to grow at 7% till 2025 by “India
Methanol Market study, 2011-2025”.

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Fig. 6 World Consumption of Methanol (Source - IHS Markit13)

Fig. 7 World Methanol Demand by region (Source - IHS Markit13)

7.2 PRESENT PRODUCTION/LICENSED CAPACITY OF THE COUNTRY

India’s currently installed capacity of methanol production is 0.47 million tons and total
domestic production is 0.2 million tons. The total methanol consumption of country in 2016
was 1.8 million tons.

7.3 EXPORT POTENTIAL

According to report by the “Ministry of Chemicals and Petrochemicals” shows that there has
been continuous increase in methanol imports in India as they have more than doubled from
2010-11 to 2015-16. Though, India has been exporting methanol as well, the amount is very
small in comparison with the imports.

Year Imports (MT) Exports (MT) Net Imports (MT)

2010-11 0.81 0.044 0.77
2011-12 1.20 0.120 1.08
2012-13 1.40 0.185 1.21
2013-14 1.31 0.082 1.23
2014-15 1.64 0.049 1.59
2015-16 1.71 0.044 1.67

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Table 5 (Source: India`s leapfrog to methanol economy12)

It can be inferred from Table 4 that in spite of having un-utilized capacity in India, it imports
methanol in order to meet its requirements. Rather, 90% of methanol requirement is met
through imports. This is primarily because, it is cheaper for India to import methanol in
comparison with domestic production. India imports 99% of its methanol from Iran (1.31 MT)
and Saudi Arabia (0.38 MT), where methanol is produced from natural gas which is abundantly
available in latter countries at extremely low prices. On the other hand, India relies on imported
natural gas for methanol production due to which it loses its competitiveness in comparison
with imports. Moreover, there is a considerable forex outgo on the imports of methanol which
is indicated in the figure below.

Fig. 8 Value of Methanol imports Vs Exports (Source- Ministry of fertilizers and

petrochemicals12)

7.4 MARKETING SET UP AND AREA OF CONSUMPTION

The National Institution for Transforming India (NITI) Aayog is planning to set up Methanol
Economy Fund worth Rs 4,000-5,000 crore to promote the product. The NITI Aayog has
planned to set up more no. of production plants. It expects that two plants can be
commissioned in the next 3-4 years. .

The government also proposing road map to achieve its target of increasing penetration of
methanol as alternative fuel to petrol and diesel. NITI Aayog ramping up facilities to convert
Coal, Standard Gas and Biomass to methanol. NITI Aayog is also working on converting

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certain diesel-powered rail engines, boats and ships used in inland waterways to work on
methanol.

Methanol is primarily converted to formaldehyde, which is widely used in many areas,

especially polymers. Acetic acid can be produced from methanol. Condensation of methanol
to produce hydrocarbons and even aromatic systems is the basis of several technologies related
to gas to liquids. Methanol is a promising energy carrier because, as a liquid, it is easier to store
than hydrogen and natural gas. Methanol is occasionally used to fuel internal combustion
engines. It burns forming carbon dioxide and water.

Fig. 9 Areas of consumption of Methanol

(Source:: India`s leapfrog to methanol economy12)

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8 SITE SELECTION & PROJECT LAYOUT

8.1 SITE SELECTION

The feasibility of the plant and site selection is mainly based upon the following:

1. Raw Materials availability

2. Markets
3. Energy availability
4. Climate
5. Transportation facilities
6. Water Supply
7. Water disposal
8. Labor Supply
9. Taxation and legal restrictions
10. Site Characteristics
11. Flood and fire protection

The proposed location for this plant is near Kudal village in Satara District of Maharashtra.
The site is not prime agricultural land. This is flat land whereby cutting-filling will be balances
and there will be no/low borrowing from nature. There is no tropical forest, biosphere reserve,
national park, wild life sanctuary and coral formation reserve within 10.0 km influence zone.

This site has a connecting road from Satara District and is 3-4km far from NH-4 and has good
approachability. There is no sensitive establishment in the vicinity such as hospital,
archaeological monuments, sanctuaries, etc. The normal wind direction is found to be favorable
at this site. All villages nearby have a good connection of road network.

The raw material which is biogas is available in abundant quantity through a Biogas producer
“Green Elephant” established in Satara District nearly 10 – 12 km from the plant site. It
produces more than 25000 m3/day of biogas which is sufficient to sustain the input of the plant.

Some details about the site are given below:

1. Nearest Town: Wai (16 km)

2. Nearest Railway Station: Wathar (20km)
3. Nearest Airport: Pune (120 km)

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4. Nearest National Highway: NH-4 (Mumbai – Bengaluru )

5. Nearest River: Krishna (3 – 4 km)
6. Working labor: 64000 ( 50 % employed)
7. Annual Rainfall: 420 mm – 6200 mm

8.2 PLANT LAYOUT CONSIDERATIONS

After selecting a site for the plant, plant layout is a crucial factor in the economics and safety
of process plant. Some of the ways, in which plant layout contributes to safety and loss
prevention (SLP), & which are included in the layout design are:

1. Economic considerations: construction and operation cost.

2. Segregation of different risks.

3. Minimization of vulnerable pipe work.

4. Containment of accidents.

5. Limitation of exposure.

6. Efficient and safe construction.

7. Efficient and safe operation.

8. Efficient and safe maintenance.

9. Safe control room design.

10. Emergency control facilities.

11. Firefighting facilities.

12. Access for emergency services.

13. Security.

14. Future Expansion.

15. Modular construction.

Our plant layout mainly includes the following buildings and construction as per the process
requirements and support activities:

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1. Plant Area (including boiler house, pump house, cooling tower, water treatment plant
etc.).
2. Power Plant.
3. Storage.
4. Repair & Maintenance Workshop.
5. Plant Utilities.
6. Loading Area (train, tankers, trucks etc.).
7. Stores.
8. R & D Centre.
9. Laboratories.
10. Quality Control Wing

11. Pollution Control Wing.

12. Fire & Safety Station.

13. Medical Centre.

14. Bank & Post Office.

15. Recreation & Staff Facilities.

16. Administrative Block.

17. Marketing Block.

18. Training Centre.

19. Petrol Pump.

20. Security Wing.

21. Canteen.

22. Parking (Light Vehicles & Heavy Vehicles)

23. Lawns & Fountains.

24. Green Belt Area.

25. Space for Future Expansion.

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A site layout for the plant is provided on the next page. Considerations have been given for the
future expansions. Some area has been marked for Green Belt. Hazardous materials are kept at
a safe distance from the offices and other staff facilities.

Description:

Location of building

o Buildings which are the work base for a number of people should be located so as to limit
their exposure to hazards. Analytical laboratories should be in a safe area, but otherwise as
close as possible to the plants served. So should workshops and general stores. The main
office block should always be near the main entrance and other administration buildings
should be near this entrance if possible.
o Other buildings, such as medical centers, canteens, etc., should also be in a safe area and
the latter should have ready access for food supplies.
o All buildings should be upwind of plants which may give rise to objectionable features.
Water drift from cooling towers can restrict visibility and cause corrosion or ice formation
on plants or transport routes, and towers should be sited to minimize this.
o Another problem is recycling of air from the discharge of one tower to the suction of
another, which is countered by placing towers crosswise to the prevailing wind. The
entrainment of effluents from stacks and of corrosive vapors from plants into the cooling
towers should be avoided, as should the siting of buildings near the tower intakes.
o The positioning of natural draught cooling towers should also take into account resonance
caused by wind between the towers. The problem of air re circulation should also be borne
in mind in siting air-cooled heat exchangers.

Economic considerations

o The cost of construction can be minimized by adopting a layout that gives the shortest run
of connecting pipe between equipment, and the least amount of structural steel work.
However, this will not necessarily be best arrangement for operation and maintenance.
o Some features which have a particularly strong influence on costs are foundations,
structures, piping and electrical cabling. This creates the incentive to locate items on the
ground, to group items so that they can share a foundation or a structure, and to keep pipe
and cable runs to a minimum.

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Safety considerations

o Plants which may leak flammables should generally be built in the open or, if necessary, in
a structure with a roof but no walls. If a closed building cannot be avoided, it should have
explosion relief panels in the walls or roof with relief venting to a safe area. Open air
construction ventilates plants and disperses flammables but, as already indicated, scenarios
of leakage and dispersion should be investigated for the plant concerned.
o Fire spread in buildings should be limited by design, as should fire spread on open
structures. Sprinklers and other protective systems should be provided as appropriate.
Plants which may leak toxics should also generally be built in the open air. The hazardous
concentrations for toxics are much lower than those for flammables, however, and it cannot
be assumed that an open structure is always sufficiently ventilated.
o Ventilation is necessary for buildings housing plants processing flammables or toxics. Air
inlets should be sited so that they do not draw in contaminated air. The relative position of
air inlets and outlets should be such that short circuiting does not occur. Exhaust air may
need to be treated before discharge by scrubbing or filtering.
o Blast walls may be needed to isolate potentially hazardous equipment, and confine the
effect of the explosion. At least two escape routes for operators must be provided from each
level in the process building.

Operations

o Access and operability are important to plant operation. The routine activities performed
by the operator should be studied with a view to providing the shortest and most direct
routes from the control room to items requiring most frequent attention.
o Equipment that needs to have frequent operator attention should be located convenient to
the control room. Valves, sample points and instruments should be located at convenient
positions and heights. Sufficient working space and headroom must be provided to allow
easy access to equipment.
o Good lighting on the plant is important, particularly on access routes, near hazards and for
instrument reading. Operations involving manipulation of equipment while observing an
indicator should be considered so that the layout permits this.

Maintenance

o Maintenance costs are very large in the chemical industry. In some cases the cost of
maintenance exceeds the company’s profit. The engineer must design to reduce these costs.

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o Heat exchangers must be sited such that tube bundle can be easily withdrawn for cleaning
and tube replacement.
o Vessels that require frequent replacement of catalyst or packing should be located on the
outside of the building.
o Equipment that requires dismantling for maintenance, such as compressors and large
pumps, should be placed under cover.

Modular construction

o For convenience of efficient management, the whole plant is assembled section wise at the
plant manufacturer’s site in the form of modules. These modules will include the
equipment, structural steel, piping and instrumentation. Modules are then transported to the
plant site, by road or sea.

Future Expansion

o We know that technology is improving day by day. That’s why keeping future expansion
in mind, equipment should be located so that it can be conveniently tied in with any future
expansion of the process.

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9 ECONOMIC EVALUATION & PROFITABILITY OF PROJECT

Plant Economics-
An acceptable plant design must present a process that is capable of operating under conditions
which yield a profit. Since Net Profit equals total income minus all expenses. It is essential that
the Chemical Engineer be aware of the many different types of costs involved in manufacturing
processes.

A capital investment is required for any industrial process and determination of the necessary
investment is an important part of a plant design project. The total investment for any process
consists of fixed capital investment for physical equipment and facilities in the plant plus
working capital which must be available to pay salaries, keep raw materials and products on-
hand and handle other special items requiring a direct cash outlay. Thus in an analysis including
income taxes must be taken into consideration.

Step.1 Purchased Equipment Cost

Equipment capital cost estimating aid is the order-of-magnitude method. These costs are
helpful during a project's early development and budgeting. The actual cost of a piece of
equipment depends upon many factors.

All the equipment costs are taken from "Matches process Equipment Cost Estimates" and from
"Coulson and Richardson's, Volume 6. Edition". The base year taken is 2018. All the
equipments are scaled to the present worth using the 'Chemical Engineering Plant Cost Index'
published regularly in the Chemical Engineering Magazine using the formula-

(𝑖𝑛𝑑𝑒𝑥 𝑣𝑎𝑙𝑢𝑒 𝑎𝑡 𝑝𝑟𝑒𝑠𝑒𝑛𝑡 𝑡𝑖𝑚𝑒)

𝑝𝑟𝑒𝑠𝑒𝑛𝑡 𝑐𝑜𝑠𝑡 = 𝑜𝑟𝑖𝑔𝑖𝑛𝑎𝑙 𝑐𝑜𝑠𝑡
𝑖𝑛𝑑𝑒𝑥 𝑣𝑎𝑙𝑢𝑒 𝑎𝑡 𝑡ℎ𝑒 𝑡𝑖𝑚𝑒 𝑜𝑟𝑖𝑔𝑖𝑛𝑎𝑙 𝑐𝑜𝑠𝑡 𝑤𝑎𝑠 𝑜𝑏𝑡𝑎𝑖𝑛𝑒𝑑

CEPCI value for 2018 is 397

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Calculation for total project cost including Fixed Capital, working Capital requirements,
preliminary and pre-operative expenses.
S.No Equipment Name Nos Price (Rs.)
1 E-100 1 14560000
2 E-101 1 4354000
3 E-102 1 6090000
4 E-103 1 4543000
5 E-104 1 5425000
6 E-105 1 10500000
7 E-106 1 24010000
8 E-107 1 5047000
9 K-100 1 28770000
10 K-101 1 28770000
11 K-102 1 32830000
12 K-103 1 9590000
13 REFORMER 1 76300000
14 Methanol Reactor 1 52660300
15 V-100 1 20972000
16 V-101 1 20466600
17 V-102 1 20589100
18 V-103 1 20986000
19 Reboiler 1 20874000
20 Distillation Column 1 3913000
21 Absorption Column 1 8750000

Total cost of purchased equipments=6000000 INR

Total Direct Costs
S.No. Description Grand Total in Rs.
1 Purchased Equipment 6000000
2 Purchased Equipment Installation 2400000
3 Instrumentation and Controls 4200000
4 Piping 1200000
5 Electrical Equipment and Materials 600000
6 Buildings(Including services) 900000
7 Yard Improvements 3000000
8 Service Facilities 900000
9 Land 300000
Total Direct Costs (D) 1428000000 INR

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Indirect Plant Cost

S.No. Description Grand Total in $.
1 Engineering and Supervision 1800000
2 Construction Expenses 2040000
3 Legal Expenses 240000
4 Contractor’s Fee 480000
5 Contingency 600000
Total Indirect Costs 361200000 INR

Other Figures Value In Rs.

Fixed Capital Investment (FCI), D+I= 1789200000
Working Capital (WC),15% of FCI= 268380000
Total Capital Investment (TCI)= 205780000

Basis for calculating total product cost is:

 The Total product cost is calculated based on the Annual Cost Basis.
 Number of days working per year is taken as 330 days.
 Plant is running in 3-shifts i.e. 24 hours per day.
 Input capacity of the plant per year is 26,650,800 kg.

Detailed statement indicating the cost of production covering elements of cost

Cost of raw material and utilities
Type Description No. of units/ Cost/unit(in Total Annual
year (kg/yr) Rs) Cost in Rs.
Raw Biogas 26650800 7 186555600
material
MDEA 7200000 110 792000000

Cost of Power and Utilities

S.No. Description No. of units/ Cost/unit(in Total Annual
year Rs) Cost in Rs.
1 HP Steam 146903.225 1800 264425806.5
2 LP Steam 83032.26 1500 124548387.1
3 Electricity(in process 11773823.04 5.5 64756026.72

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plant)
4 Cooling Water 1555.2 30 46656
5 Electricity(for other 1177382.304 3.5 4120838.064
purposes)
6 Plant Air 37157201.17 0.7 26010040.82
7 Fuel Oil 2636.88 1200 3164256
Total Annual Cost of Power and Utilities 487072011.1

Total Annual Direct Production Cost

S.No. Description Total Annual Cost in Rs.
1 Raw Materials 978555600
2 Operating Labour 244638900
3 Operating Supervision 46348000
4 Power and Utilities 487072011.1
5 Maintenance and Repairs 178920000
6 Operating Supplies 26838000
7 Laboratory Charges 34761000
Total Annual Direct Production Cost 1984234611
Table: Total Annual Direct Production Cost
Total Annual Fixed Charges
S.No. Description Total Annual Cost in Rs.
1 Depreciation 196812000
2 Taxes 35784000
3 Insurance 17892000
Total Fixed Charges 250488000
Table: Total Annual Fixed Charges
Also, Plant Overhead cost is taken to be 30% of the cost of operating labour, supervision
and maintenance.
Thus, Plant Overhead Cost=137102400 INR

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Total Manufacturing Cost

S.No. Description Total Annual Cost in Rs.
1 Direct Production Cost 1984234611
2 Fixed Charges 250488000
3 Plant Overhead Cost 137102400
Total Manufacturing Cost 2371825011

Total Product Cost (TPC)

S.No. Description Total Annual Cost
1 Administrative Expenses 69522000
2 Distribution and Marketing Expenses 178920000
3 Research and Development 268380000
Total cost of General Expenses 516822000
Total Product Cost 2888647011

Cash Flow Chart

S.No Annual Sales AnnuProductionCost Depreciation CashFlow CumulativeCashFlow CCF-TCI

1 2221560000 1812435180 196812000 524192388.9 524192388.9 -1533387611
2 2221560000 1812435180 196812000 524192388.9 1048384778 -1009195222
3 2221560000 1812435180 196812000 524192388.9 1572577167 -485002833.3
4 2221560000 1812435180 196812000 524192388.9 2096769556 39189555.6
5 2221560000 1812435180 196812000 524192388.9 2620961945 563381944.5
6 2221560000 1812435180 196812000 524192388.9 3145154333 1087574333
7 2221560000 1812435180 196812000 524192388.9 3669346722 1611766722
8 2221560000 1812435180 196812000 524192388.9 4193539111 2135959111
9 2221560000 1812435180 196812000 524192388.9 4717731500 2660151500
10 2221560000 1812435180 196812000 524192388.9 5241923889 3184343889
11 2221560000 1812435180 196812000 524192388.9 5766116278 3708536278
12 2221560000 1812435180 196812000 524192388.9 6290308667 4232728667
13 2221560000 1812435180 196812000 524192388.9 6814501056 4756921056
14 2221560000 1812435180 196812000 524192388.9 7338693445 5281113445
15 2221560000 1812435180 196812000 524192388.9 7862885834 5805305834
16 2221560000 1812435180 196812000 524192388.9 8387078222 6329498222
17 2221560000 1812435180 196812000 524192388.9 8911270611 6853690611
18 2221560000 1812435180 196812000 524192388.9 9435463000 7377883000
19 2221560000 1812435180 196812000 524192388.9 9959655389 7902075389
20 2221560000 1812435180 196812000 524192388.9 10483847778 8426267778
Cash flow pattern for the plant for 20 years

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Thus, we find that from 3rd year CCF-FCI becomes positive which implies that the cost invested
is recovered.

Profitability Analysis
Profitability Analysis
To calculate Profitability analysis the following method has been employed.
Based on selling price of the finished product API calculated at 100%, capacity.

Formulas:
 𝐴𝑛𝑛𝑢𝑎𝑙 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 𝑡ℎ𝑟𝑜𝑢𝑔ℎ 𝑆𝑎𝑙𝑒𝑠 = 𝑃𝑒𝑟𝑐𝑒𝑛𝑡 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 ∗ 𝑀𝑎𝑟𝑘𝑒𝑡
 𝐺𝑟𝑜𝑠𝑠 𝑃𝑟𝑜𝑓𝑖𝑡 = 𝐴𝑛𝑛𝑢𝑎𝑙 𝑅𝑒𝑣𝑒𝑛𝑢𝑒 𝑡ℎ𝑟𝑜𝑢𝑔ℎ 𝑆𝑎𝑙𝑒𝑠 − 𝐴𝑛𝑛𝑢𝑎𝑙 𝑂𝑝𝑒𝑟𝑎𝑡𝑖𝑛𝑔 𝐶𝑜𝑠𝑡
 𝑁𝑒𝑡 𝑃𝑟𝑜𝑓𝑖𝑡 = 𝐺𝑟𝑜𝑠𝑠 𝑃𝑟𝑜𝑓𝑖𝑡 ∗ (1 − 𝑡𝑎𝑥%)
𝑇𝑜𝑡𝑎𝑙 𝑖𝑛𝑣𝑒𝑠𝑡𝑚𝑒𝑛𝑡
 𝑃𝑎𝑦𝑏𝑎𝑐𝑘 𝑃𝑒𝑟𝑖𝑜𝑑 = 𝑁𝑒𝑡 𝑃𝑟𝑜𝑓𝑖𝑡+𝐷𝑒𝑝𝑟𝑒𝑐𝑖𝑎𝑡𝑖𝑜𝑛
Where total investment =Fixed capital Investment
𝑁𝑒𝑡 𝑝𝑟𝑜𝑓𝑖𝑡
 𝑅𝑎𝑡𝑒 𝑜𝑓 𝑅𝑒𝑡𝑢𝑟𝑛 = 𝑇𝑜𝑡𝑎𝑙 𝐼𝑛𝑣𝑒𝑠𝑡𝑚𝑒𝑛𝑡 ∗ 100

Market Value of finished product 35 Rs/Kg

Annual Revenue Through Sales 2221560000 Rs
Gross Profit 524192388.9 Rs
Assuming Tax percent 35 %
Net Profit 355933252.8 Rs
Payback Period 3.23 Years
Rate of Return 17.29 %

Break-even Point Analysis with detailed calculation and graphical representation

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Chart Title
1E+10

8E+09

6E+09

4E+09

2E+09

0
0 5 10 15 20 25
-2E+09

-4E+09

From graph it is clearly visible that 3.23 years is the break-even point for the plant that has
been designed.

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10 REFERENCES
1. Timo Blumberg , Tatiana Morosuk and George Tsatsaronis. A Comparative
Exergoeconomic Evaluation of the Synthesis Routes for Methanol Production from Natural
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2. Hyman D. Gesser, Norman R. Hunter, and Chandra B. Prakash. The direct conversion of
methane to methanol by controlled oxidation.

3. Lee, Speight, and Loyalka, 2007. Sunggyu Lee, James G. Speight, and Sudarshan K.
Loyalka. Handbook of Alternative Fuel Technologies. CRC Press, 2007.

4. Nitin Kumar, Maryam Shojaee and JJ Spivey. Catalytic bi-reforming of methane: from
greenhouse gases to syngas.

5. Kim Aasberg-Petersen, Charlotte Stub Nielsen, Ib Dybkjær and Jens Perregaard.

Large Scale Methanol Production from Natural Gas.

6. Jean-Michel Lavoie. Review on dry reforming of methane, a potentially more

environmentally-friendly approach to the increasing natural gas exploitation.

7. Calvin H. Bartholomew. Fundamentals of industrial catalytic processes.

8. Dr. P. Ferreira‐Aparicio , M. J. Benito & J. L. Sanz.New Trends in Reforming

Technologies: from Hydrogen Industrial Plants to Multifuel Microreformers.

9. George A. Olah, Alain Goeppert, Miklos Czaun, Thomas Mathew, Robert B. May,
and G. K. Surya Prakash. Single Step Bi-reforming and Oxidative Bi-reforming of
Methane (Natural Gas) with Steam and Carbon Dioxide to Metgas (CO-2H2) for
Methanol Synthesis

10. Benjamín Cañete, Carlos E. Gigola and Nélida B. Brignole. Synthesis Gas Processes
for Methanol Production via CH4 Reforming with CO2, H2O, and O2.

11. C.Robinson & D.B.Smith. The auto-ignition temperature of methane.

12. Dr. VK Saraswat & Ripunjaya Bansal. India`s leapfrog to methanol economy.

13. https://ihsmarkit.com/products/methanol-chemical-economics-handbook.html

14. http://gbes.in/financial-analyses-of-biogas-to-bio-cng-projects-in-india-projections-
based-case- study-analyses/

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15. M.R. Riazi and David Chiaramonti.Biofuels. Production and Processing

Technology,Pg 189-191

16. Stanisław Ledakowicz, Lech Nowicki, Jerzy Petera, Jarosław Nizioł1,Paweł

Kowalik, Andrzej Gołębiowski. Kinetic Characterisation of catalysts for methanol
synthesis.Chemical and Process Engineering 2013

17. J.I. Huertas, N. Giraldo and S. Izquierdo.Removal of H2S and CO2 from Biogas by
Amine Absorption

18. Coulson Richardson's Chemical Engineering Vol.6 Chemical Engineering Design 4th
Edition

19. William L. Luyben. Design and Control of a Methanol Reactor/Column Process, 2010

20. Raquel De María, Ismael Díaz*, Manuel Rodríguez, and Adrián Sáiz. Industrial
Methanol from Syngas: Kinetic Study and Process Simulation

21. P. Mondala, G.S. Dangb, M.O. Garg .Syngas production through gasification and
cleanup for downstream applications — Recent developments

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