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Group Members

• Tanvir Ahmed 2011332005 • Iftekhar Hussain Chowdhury 2011332007 • Sabiha Akter 2011332019 • Md. Shahedul Haque 2011332024 • Md. Foridur Rahman Shishir 2011332038 • Israt Jahan 2011332039 • Khaliquzzaman Choudhury 2011332048 • Sainte Chakma 2011332052 • Sadia Begum 2011332058 • Tanmoy Das 2010332018

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Contents Page No.

Acknowledgement 4

Abstract 5

Chapter- I: Introduction 7-10

I.1 Plant Definition & Objectives

I.2 Definition of Natural Gas

I.3 Classification of natural gas

I.4 Key Definitions & Composition of NG

Chapter- II: Design Basis & Selection of Process 12-17

II.1 Design basis

II.2 Selection of Process

III.3 Comparison among process

Chapter- III: Process Description 19-26

III.1 Necessity of Natural Gas Processing

III.2 Process Description

III.3 MSTE Plant Units

III.4 Liquid Hydrocarbon (Condensate) Processing

Chapter- IV: Utilities 29-30

IV.1 Utilities of the Plant

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Chapter- V: Plant Control System 32-33

Chapter- VI: Material & Energy Balance

Chapter- VII: In Plant Safety 35-40

VII.1 Plant Safety Issues

VII.2 Hazards in Plant

VII.3 Hazard Mitigation Planning & Prevention

Chapter- VIII: Economic Analysis 42-46

VIII.1 Cost Estimation

VIII.2 Cash Flow for Plant Operation

VIII.3 Capital Investment

VIII.4 Plant Income Summary

VIII.5 Return on Investment

VIII.6 Plant Total Cash flow Summary

Plant Layout 47

Conclusion 48

References 49

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Acknowledgement

At first we are grateful to our Almighty Creator who is most beneficent and

merciful. We would like to thank our head of our department, Professor Dr. Md

Mastabur Rahman for granting us permission to perform this plant visit. We

express our deepest and profound respect to our supervisors Prof. Dr. Salma

Akhter and Rahatun Akter. We are indebted to them for helping us by providing

the necessary guidance, encouragement, valuable suggestions, strong inspection

and advice to perform the work successfully. We give special thanks to Md. Abul

Bashar & DGM of the Kailashtilla gas field for helping us on our site visit and

completing it without any obstacles. We also want to thank all the people of

Kailashtilla Gas Field Ltd. for their assistance, encouragement and support.

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Abstract

Bangladesh has a lot of natural resources. Natural gas is the main geo resource

among them. Natural gas of our country is unique in the world for its quality.

Addition to this a lot amount of condensate is extracted in gas processing plants. In

our country the exploration processing and distributing are co-ordinated by the

Bangladesh Oil gas & Mineral Corporation. It has different companies for different

purposes. A number of associated foreign companies are also participating in this

sector. The industrial and power sector of Bangladesh has a great dependency on

the natural gas either for fuel or for raw material. The processed gas is also used in

domestic purpose and nowadays in vehicles as fuel.

This work includes natural gas processing and also how the processing plant works

(i.e. both the structural and functional aspects). The chapters deal with process

description of SGFL, Safety maintenance, fractionation, Laboratory analysis etc.

Details of molecular sieve in Kailashtilla gas fields have been discussed. The

purpose of the de-ethanizer is to separate by fractionation the methane and ethane

components contained in the feed. A de-ethanizer is designed for an assumed feed

composition.

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Chapter I:

Introduction

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I.1 Plant Definition & Objectives

A natural gas processing plant is a facility designed to process raw natural gas by separating

impurities and various non-methane hydrocarbons and fluids to produce what is known as

pipeline quality dry natural gas.

The objective of the project is to design a natural gas processing plant located at Kailashtilla,

Sylhet in Bangladesh, with a production capacity of 21900 MMCF per year, corresponding to a

daily production of 60 MMCFD, and 400 from 420 barrels of NGLs and 650 to 750 barrels of

condensate with sales gas, as by-product, including all offsite auxiliaries, utilities and support

facilities using natural gas as feed.

I.2 Definition of Natural Gas

Natural gas is a mixture of Methane, ethane, propane, butane, pentane, carbon dioxide, Nitrogen

etc. is the most important fuel belonging to this class & is found mainly in the vicinity of coal

mines or oil fields. The natural gas is also found associated with petroleum in Nature. It is not

only used as fuel or domestic or industrial purposes but also used as a chemical raw material for

various syntheses. Most of the natural gas used as fuel is derived from oil fields. However

sometimes the gas evaporated from the oil & diffused through rocks is trapped by impervious

dome shaped structure which may be far off from the original oil deposit. This constitutes a gas

field which may be under high pressure. Due to earth movement or pressure it may suddenly

escape out through fissure. This may result in ignition on its emergence to the atmosphere,

because of the static electricity produced by the rushing gas or because of increased temperatures

caused by friction. This gas is collected from the mine by drilling well & after some processing it

reaches to the consumers.

The global use of natural gas is growing rapidly. This is primarily attributed to the environmental

advantages it enjoys over other fossil fuels such as oil and coal. There is worldwide drive

towards increasing the utilization of natural gas and the need to minimize energy consumption

and increase profit associated with the process. These objectives can be achieved by reducing

time required to get products to market, increasing the quantity and quality of product produced

and designing plants for an optimum performance along their life cycle.

In Bangladesh this resource is controlled by the Bangladesh Oil gas & mineral Corporation

(PetroBangla). It has different departments to control different sections.

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I.2 Classification of Natural Gas

The natural gas derived from wells are divided into three types, according to consisting of

different kinds of Hydrocarbon.

1. Dry Gas: If the lower hydrocarbons like methane ethane etc. are present at large amount

& small amount of water in well gas is called dry gas.

2. Wet Gas: If higher hydrocarbons are present with natural gas then it is called wet gas. It

is also called “marsh gas”.

I.3 Key Definitions & Composition of NG

Methane:

Methane is the predominant component of natural gas typically forming of 70% -99% of bulk

gas. It is colorless, odorless flammable gas. It is chemically inactive sparingly soluble in water &

is lighter than air.

Condensate:

It refers to the portion which condenses and separates out from NG as liquids when the gas is

produced at the surface. This liquid is composed of heavier hydrocarbon that exists as vapor

dissolved in NG in underground pressure temperature condition but turned to liquid at the

surface wellhead condition. Condensate is a valuable product & is processed to use commercially

as fuel.

Natural Gas Liquids (NGL):

NGL refers to a mixture of all hydrocarbons except methane which can be extracted by

compression and cooling in separator. After extraction NGL is distilled to be separated into

ethane, propane, butane & natural gasoline.

Liquefied Petroleum Gas (LPG):

LPG refers to mixture of essentially propane and butane which is extracted from wet natural gas.

LPG is also available during of crude oil. It is used as fuel to run automobiles.

Liquefied Natural Gas (LNG):

LNG refers to liquid form of natural gas that is produced by special liquefaction process in a

plant surface. LNG is suitable for transportation.

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Compressed Natural Gas (CNG):

It refers to the NG made available in compressed form for the use as fuel in vehicles. Usually

NG is compressed to 300 pounds per square inch gauge in refining station and put in cylinder for

CNG run vehicles cooling the gas to 160oC.

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Table I.3-1: Constituents of Natural Gas

Components Amount (%) Pie-Chart

Methane 0.931

Ethane 0.03

Propane 0.007

i-Butane 0.0028

n-Butane 0.0028

i-Pentane 0.0025

n-Pentane 0.0023

n-Hexane 0.0022

n-Heptane 0.002

n-Octane 0.0018

n-Nonane 0.0015

n-Decane 0.0011

n-C11 0.0009

n-C12 0.0007

n-C13 0.0005

H2O 0.0109

Methane

Ethane

Propane

i-Butane

n-Butane

i-Pentane

n-Pentane

n-Hexane

n-Heptane

n-Octane

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Chapter II:

Design Basis &

Selection of Process

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II.1 Design Basis

Natural gas is considered 'dry' when it is almost pure methane, having had most of the other

commonly associated hydrocarbons removed. When other hydrocarbons are present, the natural

gas is 'wet'. Raw natural gas comes primarily from any one of three types of wells: crude oil

wells, gas wells, and condensate wells.

Crude oil wells—raw natural gas that comes from crude oil wells is called associated gas. This

gas can exist separate from the crude oil in the underground formation, or dissolved in the crude

oil. Condensate produced from oil wells is often referred to as lease condensate.

Dry gas wells—these wells typically produce only raw natural gas that does not contain any

hydrocarbon liquids. Such gas is called non-associated gas. Condensate from dry gas is extracted

at gas processing plants and, hence, is often referred to as plant condensate.

Condensate wells—these wells produce raw natural gas along with natural gas liquid. Such gas

is also called associated gas and often referred to as wet gas.

Natural gas that comes from crude oil wells is typically called associated gas. This gas can have

existed as a gas cap above the crude oil in the underground formation, or could have been

dissolved in the crude oil.

Natural gas from gas wells and from condensate wells, in which there is little or no crude oil, is

called non-associated gas. Gas wells typically produce only raw natural gas, while condensate

wells produce raw natural gas along with other low molecular weight hydrocarbons. Those that

are liquid at ambient conditions (i.e., pentane and heavier) are called natural gas

condensate (sometimes also called natural gasoline or simply condensate).

Natural gas is called sweet gas when relatively free of hydrogen sulfide; however, gas that does

contain hydrogen sulfide is called sour gas. Natural gas, or any other gas mixture, containing

significant quantities of hydrogen sulfide, carbon dioxide or similar acidic gases, is called acid

gas

The term NGL (natural gas liquids) is a general term which applies to liquids recovered from

natural gas and as such refers to ethane and heavier products. The term LPG (liquefied petroleum

gas) describes hydrocarbon mixtures in which the main components are propane, iso and normal

butane, propene and butenes.

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Liquefied petroleum gas or liquid petroleum gas (LPG or LP gas), also referred to as simply

propane or butane, are flammable mixtures of hydrocarbon gases used as fuel in heating

appliances, cooking equipment, and vehicles

Natural-gas condensate is a low-density mixture of hydrocarbon liquids that are present as

gaseous components in the raw natural gas produced from many natural gas fields. Some gas

species within the raw natural gas will condense to a liquid state if the temperature is reduced to

below the hydrocarbon dew point temperature at a set pressure.

Raw material: Feed gas inlet at 40C and well head pressure 1800 psi

Product:

Maximum Production capacity 90 MMcfd

Current production 60 MMcfd

Gas Recovery 58.5 MMcfd

Condensate Production 710 bbl/day

NGL Production 420 bbl/day

Gas-condensate ratio 18.83 bbl/MMcfd

Geographical Information: Kailashtilla; 35 mile south-west of Sylhet.

Climate Condition:

Ambient temperature: Max. = 38oC, Min. = 12oC

Average relative humidity: 85%

Annual maximum rainfall: 2800 mm

Average annual rainfall: 1550 mm

Barometric pressure (at sea level): 99.967 kPa

Wind direction: In Summer, from south-east

In Winter, from north-east

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Utility conditions:

Electric power:

Power generation - 40 KV, 3 phase, 50 Hz

Motor and pumps - 440 volts, 3 phase, 50 Hz

Fuel: Raw natural gas or pipeline gas, Ethane

II.2 Selection of Process

There are several methods of dehydrating natural gas. The refrigeration(direct cooling and

indirect cooling), Liquid desiccant (glycol) dehydration and solid desiccant dehydration, the first

two methods employ cooling to condense the water molecules to the liquid phase with the

subsequent injection of inhibitor to prevent hydrate formation. The other two methods utilize

mass transfer of the water molecular into a liquid solvent (glycol solution) or a crystalline

structure (dry desiccant). However, the choice of dehydration method is usually between glycol

and solid.

1. Dehydration:

(i)Direct cooling: The saturated vapor content of natural gas decreases with increased pressure or

decreased temperature in direct cooling.

(ii)Adsorption: Molecular sieves (zeolites), silica gel, and bauxite are the desiccants used in

adsorption processes

(iii)Absorption: In absorption processes, the most frequently used desiccants are diethylene and

triethylene glycols.

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2. NGL Extraction Process:

1. Short Cycle Dry Desiccant Adsorption

2. Cooling

– Joule-Thomson Expansion (JT valve)

– Refrigeration

a) With glycol

b) With methanol

– Turbo-Expander

3. Lean Oil Absorption

In this plant, Joule-Thomson (JT valve) and Turbo Expander used in parallel for cryogenic processing.

II.3 Comparison among Process

Based on dehydration of natural gas and NGL extraction, we can use a several methods

Dehydration:

Direct cooling: Reduced the temperature low enough to liquefies the water vapor in gas.

Cons: Gas dehydrated by cooling still at its dew point, so water vapor exists in significant

amount

Indirect cooling: A huge temperature drop can be achieved by expansion done by expander or

Joule-Thomson effect

Cons: Required extent of dehydration can not be achieved

Either two of this process cannot be used solely in gas dehydration. They are used in conjunction

with these two processes:

I. Dehydration by absorption: Tri ethylene glycol(TEG), Tetra ethylene glycol(TREG)

II. Dehydration by adsorption: Molecular sieve(zeolite), Activated Alumina

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Dehydration by absorption:

Ethylene glycol (EG), Diethylene glycol (DEG), Triethyleneglycol (TEG), and Tetraethylene

glycol (TREG) are used as liquid desiccant widely

Advantages:

• Strong affinity for water

• Ease of regeneration and operation

• Low potential for corrosion and low volatility

• Low solubility in hydrocarbon

• Good thermal stability to prevent high temperature decomposition

Disadvantages:

• Lower depression of dew point relatively solid sorbent

• Glycol is susceptible to contamination

• Glycol can be very corrosive on contaminated or decomposed

• Loses occur due to high solubility I hydrocarbon condensate

Dehydration by adsorption:

Molecular sieve (zeolite) Activated alumina, Silica Gel are mostly used as solid desiccant

Advantages:

• Larger surface area for high capacity

• High mass transfer rate

• Capable of dehydration to less than 0.1 ppm water content

• Small resistance to gas flow

• Easy regeneration

• High mechanical strength to crushing and dust formation

• Cheap, nontoxic, non-corrosive and chemically inert

Disadvantages:

• High capital cost to set up

• High space and weight requirement

• Deactivation may occur by small particulate deposition

• High energy required for regeneration

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NGL extraction

• For hydrocarbon dew point control only:

-Short cycle adsorption

-Joule-Thomson expansion

-Refrigeration about -20oC

• For basic NGL recovery:

-Lean oil absorption at ambient temperature

-Turbo expander without external refrigeration

-Refrigeration to about 20oC

• For high NGL recovery, including ethane:

-Turbo expander

-Refrigerated lean oil absorption (but not suited for ethane recovery)

-Refrigeration to about -30oC

By analysis the raw gas properties, its composition and required quality of pipeline transmission;

we found that our best suited process is Molecular Sieve Turbo Expander (MSTE).

Project Life Cycle:

Figure II.3-1: Project Life Cycle

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Chapter III:

Process Description

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III.1 Necessity of Natural Gas Processing

Removal of unwanted and corrosive components (water, sludge, dust, H2S, CO2 etc.) to

meet the pipeline quality gas.

Recovery of the valuable components(liquid hydrocarbons)

Maintaining the delivery pressure and temperature

III.2 Process Description

• Firstly raw natural gas is collected from the well heads and then sent to gas processing

plant also named.

• Molecular sieves are used for gas dehydration

• Turbo expander/ J-T valve (cryogenic process) used for natural gas liquid (NGL)

recovery.

III.3 Molecular Sieve – Turbo Expander (MSTE) Plant

In Kailashtilla gas field raw natural gas is collected from the well heads which is a mixture of

natural gas, water, natural gas condensate etc. In natural gas process plants these different

components are separated and pipeline quality natural gas is extracted. In this plant Molecular

Sieves are used for gas dehydration and Cryogenic process (Turbo expander / J-T Valve) is

applied for Natural Gas Liquid (NGL) recovery. The process units of the plant are described

below:

1. Inlet heater:

It is a double pipe type heat exchanger. Gas from the wells is fed to three separate inlet heaters

to raise the temperature above 26°C. It is done to prevent hydrate formation when inlet gas

pressure is reduced to 88bar from 150bar. Gas is passed through the tubes and hot oil

(Therminol-6, 6) on the shell side.

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PFD Diagram:

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PFD Diagram: (with utility)

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2. Inlet separator / Three Phase Separator:

Gases from three inlet heaters are fed to three corresponding inlet separator. In these separators

components are separated by specific gravity and a pressure of 88bar is maintained. Feed is

separated into Gas, water and Condensate. Water level in the separator is maintained at a certain

level and excess is drained, gas is fed to inlet filter and condensate is charged into Stabilizer at 7

bar and 20°C.

3. Inlet Filter Separator:

Feed gas from the three-phase separator is further filtered here to protect the molecular sieve in

the dehydrator tower. There are two units, one is always on duty and another is spare. This unit

consists of filter area with replaceable filter element and a vent type mist extractor.

4. Molecular Sieve Type dehydrator:

There are different types of gas dehydrator based on desiccants such as silica-gel type, TEG

(Glycol) type, Molecular sieve type etc. In this plant Molecular sieves are used in dehydration of

gas stream. Two dehydrators are used; one is on duty and another in regeneration for time cycle

of 8 hours.

Molecular sieve has porous cavities to entrap moistures. Feed gas at 88bar pressure and 29°C are

fed to one online dehydrator from the top in a down flow pattern for 8 hours. When desiccants

are exhausted the unit is turned into regeneration cycle and the other one is made online.

Regeneration of Molecular sieves:

Regeneration is done by passing hot gas through the bed; this gas is fed from the bypass of the

residue gas. The steps in regeneration are:

Depressurization:

First the flow of gas to the tower to be regenerated is cut off by closing the valve and

depressurized slowly from 88bar to 32bar over a time period of 30 minutes to avoid high

gas velocity that can damage the bed. The residue gas from expander-compressor or J-T

valve is passed through a heat exchanger and gas temperature is raised to 276°C. The hot

gas is then passed through the bed for 4 hours, bed temperature become 180°C and water

in the molecular sieves are vaporized and flow with hot gas.

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To make the bed ready for dehydration residue gas is passed through a bypass line

instead of the heat exchanger and then passed through the bed for 3 hours. Bed

temperature is decreased to 42°C.

Pressurization:

The tower is pressured back to 88bar from 32bar in a period of 30min. Then the inlet gas

is bypassed to this tower for dehydration and the other one starts regeneration.

5. Regeneration gas heater:

It is a shell & tube type heat exchanger. Hot oil at 276°C passes through the tube side and gas is

passed through the shell side and gas is heated for using in regeneration of bed.

6. Regeneration gas cooler:

This is an air cooled heat exchanger. It is used to condense the water and hydrocarbon vapor

produced during the regeneration heat cycle. The outlet temperature is 16 to 49°C.

7. Regeneration Gas scrubber:

In this unit gas is passed to separate gas and any liquid contents. Gas leaves this vessel at the top

and passes through a mesh screen so that any residue is collected.

8. Dust Filter:

Dusts maybe present in the gas and also can be the cracked particles of molecular sieves. Dusts

are removed by passing the gas stream through a dust filter. Water molecules present after

dehydration are also entrapped here. Outlet stream of this unit is then passed to the Gas to gas

heat exchanger (97%) and De-ethanizer feed heater (3%).

9. Gas to Gas heat exchanger:

It is a shell and tube type heat exchanger which is used to cool the gas. The cooling gas is the gas

stream from the top of the De-ethanizer column which is at a temperature of - 47°C as a result of

going through the cryogenic process. The hot stream is at 29°C that is to be cooled down.

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10. Cold separator:

In gas-gas heat exchanger the inlet gas is cooled down to -18°C, as a result liquid is formed by

condensation. Cold separator extracts this condensed liquid.

Inlet gas then flows through the 3 expanders or their bypass J-T (Joule Thomson) valves. Then

flows to the expander separator. Liquid formed in this unit also flows to the expander separator.

11. Turbo expander:

A turbo expander, also referred to as an expansion turbine, is a centrifugal or axial flow turbine

through which a high pressure gas is expanded to produce work that is often used to drive a

compressor. Turbo expanders are very widely used as sources of refrigeration in industrial

processes such as the extraction of ethane and natural gas liquids (NGLs) from natural gas.

Inlet gas from the cold separator flows through the 3 expanders at 88bar. The expansion of the

gas releases energy and provides work. As a result gas stream is cooled down to - °C and as the

temperatures of the gases drop below the dew point, they condense out as liquid and higher

hydrocarbon such as propane, butane is recovered as NGL.

12. J-T (Joule-Thomson) valve:

It is an alternative to the turbo expander, also when turbo expander is overloaded JT valve is

used to expand the excess gas stream.

The use of turbo expanders, however, does not eliminate the need for the Joule Thompson valve.

This is typically referred to as the expander bypass valve but operates under the Joule Thompson

effect. The valve is used to enable a more efficient startup and shutdown of the turbo expander. It

is also used to continue the process when the expander goes offline or if flow increases beyond

the full speed capacity of the turbo expander.

Inlet gas flows through the 3 expanders or their bypass J-T (Joule Thomson) valves. Then it

flows to the expander separator.

13. Expander / Cold separator:

It is designed to separate the NGL liquid from the gas stream which is coming from turbo

expander / JT valve. This separator has to inlet, one from cold separator bottom and another from

expander outlet. The gas from this unit is passed through a mist extractor to recover residual

NGL. Separated NGL from this unit is then fed to the De-ethanaizer.

14. De-ethanizer feed heater:

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This heat exchanger is used for pre heating the De-ethanizer feed. Process gas from dust filter is

used as heating media. The feed is heated so that ethane recovery becomes easier.

15. De-ethanizer:

It is a fractionation column. The purpose of de-ethanizer is to remove ethane and trace amount of

methane from NGL that contains propane, butane etc. It consists of number of trays with bubble

caps. Lighter components are stripped from NGL and these gases leave the tower at the top. De

ethanized NGL is then stored in NGL storage tanks.

16. De ethanizer Reboiler:

It is a kettle type reboiler that supplies sufficient heat to the bottom liquid to produce enough

vapors to strip the lighter components from NGL feed. Hot oil flows through tube bundle. The

reboiler shell has spillover internal weir that keep the tube bundle submerged in liquid.

17. Residue Gas Compressor:

There are five gas compressors which are identical and separate self-contained packaged unit.

Each unit has lube oil and cooling systems. These compressors work in parallel. Gas from

expander compressor common discharge header in cryogenic section is fed to these compressors

after compression gas pressure is increased to 55 bar and fed to the pipeline

18. Gas Cooler:

Temperature of the gas raise as the pressure increased. So gas needs to be cooled. Compressed

gas cooled at 300C by a gas cool and fed to the pipeline

Final Gas pressure and temperature in the pipeline is 55 bar at 300C.

III.4 Liquid Hydrocarbon (Condensate) Processing

1. Liquid Stabilizer:

The stabilizer with 16 trays to handle hydrocarbon Liquid that drops out in the three inlet

separators. Liquid from the inlet separator is flashed to 12.1bar and is feed into the top of the

stabilizer. The stabilizer operates at 200C on the top tray and 1800C on the bottom tray. The

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stabilizer reboiler outlet temperature is controlled at 2120C at 7 bar. The liquid is cooled to 350C

and then pumped to NGL surge drum. The vapor product is fed to fuel gas system at a rate of

500 m3/hr. 97% of the ethane & 62% propane plus heavier components exit the bottom as a

stabilized NGL product. In this process all of the N2 & CO2 from the feed stream is removed. The

total liquid stream from tray number 8 is routed through the separator where the water settles out

of the hydrocarbon. The hydrocarbon is then returned to the stabilizer on to tray no 9.

The tower feed is saturated with water; therefore a water separator is required to remove the

undesired water. The separator is fed from a draw-off tray below tray-8 & returns hydrocarbon

condensate must flow through the mesh pad mater molecules are coalesced to from larger

droplets of water. In the separator section water is separated from the hydrocarbon condensate &

accumulated in the separated boot. Water accumulated in the separated boot must be drained

manually at regular intervals to prevent flooding in the stabilizer, which may reduce the

efficiency of the stabilizer.

Heat is added to the bottom of the tower by the stabilizer reboiler. The reboiler is a kettle type

with hot oil circulated through the tube bundle. The hot oil flow is temperature controlled to

maintain a constant tower bottom temperature. The reboiler shell is equipped with a spill-over

weir which ensures that the tube bundle is completely submerged in liquids at all times. The weir

forms a reservoir on the down streamside where NGL product is collected. The excess NGL

product is level controlled from the reservoir section through the stabilizer product cooler.

2. Stabilizer Product Cooler:

The 1750C NGL product from the stabilizer is cooled to 300C by to identical forced draft air-

cooled exchanger. One air cooler is spare & appropriate isolating valves are provided. Each air

cooler has three fans driven by 1.6KW electric motors. After cooling, NGL product is pumped to

the surge drum.

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Chapter VI:

Material & Energy

Balance

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Chapter- IV:

Utilities

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VI.1 Utilities of the Plant

Several systems work together in the gas plant to produce electricity, steam heat, and chilled

water to meet the needs of production. The purpose of the Utilities Plant is to provide utility

commodities: steam, instrument air, utility air, fuel gas, emergency power, conditioned boiler

feed water, utility water and most importantly in a gas plant is heating oil.

Among the most important utility system these are mandatory for gas plant operation:

1. Heating oil system

2. Gas turbine generator

3. Chillers

4. Potable Water system

5. Instrument Air generation

6. Air compressor

1. Heating oil:

In MSTE gas processing plant used high boiling point oil for heating purpose in different

instrument (heater, heat exchanger etc). The most used heating oil is mainly Theol oil. Here is a

list of oils that are used for heat transfer mechanism:

Abbreviation Full Name Norm boil point (oC)

MT-IG-2* Multitherm-IG-2 436

MT-PG-1* Multitherm-PG-1 361

MT-503* Multitherm-503 329

THEOL-LT* Therminol-LT 181

THEOLD12* Therminol-D12 193

THEOL-44* Therminol-44 363

THEOL-55* Therminol-55 351

THEOL-59* Therminol-59 289

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2. Gas Turbine Generator:

This mainly used for generating electric current for the plant operation and other instrument

power.

3. Chiller:

Chillers are mainly used to cool down the hot gas temperature to a certain limit. Sometimes it

can bring gas temperature to negative so that liquid fraction separation becomes easy.

Actually it is one kind of heat exchanger usually setup before the liquid separation tank.

4. Turbine and Compressor:

Turbine and compressor are mainly used for ensuring high pressure flow of gas in supply

line. After heavy condensate extraction, gas need to be supply in distant places with high

pressure. High power compressors are driven by turbine. In some case internal combustion

gas turbine are used for high power production.

5. Potable water system:

Water is collected from underground reservoir through a number of tube wells and filtered to

remove any impurities.

6. Instrument Air:

Existing pneumatic gas supply piping, control instruments, and valve actuators of the gas

pneumatic system can be reused in an instrument air system. In these systems,

atmospheric air is compressed, stored in a volume tank, filtered and dried for instrument use.

THEOL-60* Therminol-60 329

THEOL-66* Therminol-66 341

THEOL-75* Therminol-75 383

THEOLVP1* Therminol-VP1 257

PathrmHE* Paratherm HE 415

PathrmNF* Paratherm NF 346

MritrmS* MARLOTHERM SH 390

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Chapter V:

Plant Control System

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Plant Control System

Industrial control system (ICS) is a general term that includes several types of control systems

used in industrial production, including SCADA, DCS, and other smaller control system

configurations such as PLC often found in the industrial sectors and critical infrastructures.

In this plant Control system is based on SCADA and PLC.

SCADA:

(Supervisory Control and Data Acquisition) is an industrial automation control system at the

core of many modern industries.

SCADA systems deploy multiple software and hardware elements that allow industrial

organizations to:

Monitor, gather, and process data

Interact with and control machines and devices such as valves, pumps, motors,

and more, which are connected through HMI (human-machine interface) software

Record events into a log file

In basic SCADA architectures, information from sensors or manual inputs are sent to PLCs

or RTUs (remote terminal units), which then send that information to computers with

SCADA software.

SCADA software analyzes and displays the data in order to help operators and other workers

to reduce waste and improve efficiency in the manufacturing process.

PLC:

A Programmable Logic Controller (PLC) is an industrial computer control system that

continuously monitors the state of input devices and makes decisions based upon a custom

program to control the state of output devices.

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Example of Control System:

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Chapter VII:

In Plant Safety

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VII.1 Plant Safety Issues

Safety is a term consists of some precautionary measures that are observed by the people at the

time of performing a job inside the factory with the help of some machines & equipments.

The ultimate aim of safety is the complete prevention of personal injury, loss of life &

destruction of property. Effective plant safety & fire protection are essential for every phase of

operation and maintenance of equipment& machines. Equipments & other individual items must

be examined time to time for normal service and also for emergency demand. All buildings,

workshops, installation & equipments must be furnished and maintained so as to protect the

workers against accidents & professional diseases.

VII.2 Hazards in Plant

Incidents occur in natural gas processing due to

-Toxic, Reactive, Flammable, Explosive

-Temperature, Pressure, Level, Composition etc.

Safety hazards associated with gas extraction activities are-

1. Vehicle Collision

2. Struck-By/Caught-In/Caught-Between

3. Explosions And Fire

4. Falls

5. Chemical exposure

6. Confined Spaces

7. Ergonomic Hazard

8. High Pressure lines And Equipment

9. Electrical And Other Hazardous Energy

10. Machine Hazard

11. Gas Flare

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1. Vehicle Collisions

Workers and equipment are required to be transported to and from well sites. Wells are often

located in remote areas, and require traveling long distances to get to the sites. Highway vehicle

crashes are the leading cause of gas extraction worker fatalities. One of the main reasons for

these reckless accidents has been carelessness and less alertness or exhausted drivers. Many a

time’s trucks were found to be in disrepair and in a bad condition.

OSHA's Motor Vehicle Safety and NIOSH's provide Prevention Strategies for Employers which

give sufficient guidance and safety regulations to prevent vehicle collisions for oil rig workers.

2. Struck-By/Caught-In/Caught-Between

Three of every five on-site fatalities in the oil and gas extraction industry are the result of struck-

by/caught -in/caught-between hazards. Workers might be exposed to struck-by/caught-in/caught-

between hazards from multiple sources, including moving vehicles or equipment, falling

equipment, and high-pressure lines. The following OSHA and NIOSH documents provide

guidance on recognizing and controlling these hazards.( Crane, Derrick, and Hoist Safety,

Struck-By Guidelines on the Stability of Well Servicing Derricks)

Relevant OSHA standards applicable to these hazards include:

Eye and face protection 1910.133

Head protection 1910.135

Foot protection 1910.136

Hand protection 1910.138

Handling materials - General 1910.176

Powered industrial trucks 1910.178 App A

Crawler locomotive and truck cranes 1910.180

Slings 1910.184

Machinery and machine guarding 1910 Subpart O

General requirements for all machines 1910.212

Mechanical power-transmission apparatus 1910.219

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3. Explosions and Fires

Oil and gas rigs house a lot of highly combustible chemicals and gas, which means there is

always a chance of a fire breaking out or explosions. Most of the times these occur without the

slightest warning and so are difficult to prevent. You need to be ready with all possible

preventive measures to face such hazards.

A detailed firefighting plant:

need to have equipment, extinguishers and suppression agents ready in case of an

emergency

Most of the accident prone areas like gas chambers, oil tanks and electricity rooms are

under continuous threat of fire and explosion; it is important that all the machinery and

equipment susceptible to fire should be inspected on a regular basis.

Placing adequate amount of extinguishers and safety equipment in and around such

places.

Offering proper safety training to the employees working in such hazardous areas.

Regular inspection and maintenance of such places and equipment can reduce the risks

of such hazards.

Fig VII.2-3: Fire Safety Appliances

Fire Hydrant

A fire hydrant is a connection point by which firefighters can tap from a water supply. It is a

component of active fire protection. The user attaches a hose to the fire hydrant, then opens a

valve on the hydrant to provide a powerful flow of water.

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4. Falls

Workers might be required to access platforms and equipment located high above the ground.

OSHA requires fall protection to prevent falls from the mast, drilling platform, and other

elevated equipment.

It is important that the floor is kept clear of unnecessary tools, ropes or cords. Also make

it a point to clean oil or chemical spills immediately.

Making use of slip resistant and waterproof boots to reduce slips and trips.

5. Confined Space

Workers are often required to enter confined spaces such as petroleum and other storage tanks,

mud pits, reserve pits and other excavated areas, sand storage containers, and other confined

spaces around a wellhead. Safety hazards associated with confined space include ignition of

flammable vapors or gases. Health hazards include asphyxiation and exposure to hazardous

chemicals. Confined spaces that contain or have the potential to contain a serious atmospheric

hazard must be classified as permit-required confined spaces, tested prior to entry, and

continuously monitored.

Avoid entering confined spaces, e.g. by doing the work from outside.

If entry to a confined space is unavoidable, develop and implement a safe system of

work.

And devise an appropriate emergency plan before the work start.

6. Chemical Exposure

Most of the gas rigs release high concentrations of H2S (Hydrogen sulfide). Pipeline operator

faces maximum risks caused by dangerous levels of H2S. It can cause paralysis, leukemia and

other cancers or even death. Other side effects of toxic exposure that have been reported are

headaches, nausea, dizziness, eye and skin irritation and chemical burns. It is important that

proper eye, face and respiratory protection masks are used on gas plant.

7. Ergonomic Hazard

Oil and gas workers might be exposed to ergonomics-related injury risks, such as lifting heavy

items, bending, reaching overhead, pushing and pulling heavy loads, working in awkward body

postures, and performing the same or similar tasks repetitively. Risk factors and the resulting

injuries can be minimized or, in many cases, eliminated through interventions such as pre-task

planning, use of the right tools, proper placement of materials, education of workers about the

risk, and early recognition and reporting of injury signs and symptoms.

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8. High Pressure Line and Equipment

Workers might be exposed to hazards from compressed gases or from high-pressure lines.

Internal erosion of lines might result in leaks or line bursts, exposing workers to high-pressure

hazards from compressed gases or from high-pressure lines. If connections securing high-

pressure lines fail, struck-by hazards might be created.

Ensure the regulator and pipework is appropriate for the type of gas and pressure regime.

Do not use grease or PTFE tape on threads - this can present an explosion risk and

indicates unsatisfactory seal being made which could leak.

Ensure the cylinder is secured in a trolley or securely chained/strapped to the wall or

bench.

Do not store flammable gases near any source of ignition.

9. Electrical and Other Hazardous Energy

Workers might be exposed to uncontrolled electrical, mechanical, hydraulic, or other sources of

hazardous energy if equipment is not designed, installed, and maintained properly. Further,

administrative controls such as operating procedures must be developed and implemented to

ensure safe operations.

Have only licensed electricians install, repair and dismantle jobsite wiring.

Do a thorough check for electrical wiring before cutting through any wall, floor or

ceiling.

Inspect power tools on a regular basis.

Check insulated tools for damage before each use.

Ensure that all electrical components stay dry.

10. Machine Hazard

Oil and gas extraction workers may be exposed to a wide variety of rotating wellhead equipment,

including top drives and Kelly drives, draw works, pumps, compressors, catheads, hoist blocks,

belt wheels, and conveyors, and might be injured if they are struck by or caught between

unguarded machines.

Machines used for drilling activities generally cause a lot of noise and vibration which

can harm the operator. While using such equipment the operator should make it a point to

wear protective gear like gloves and earplugs.

It is important to follow OSHA regulations to guard machinery, update equipment and

keep them in good working condition to ensure safe use.

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The following OSHA and NIOSH documents provide guidance on recognizing and controlling

these hazards: (Barrier Guard for Draw works Drum at Oil Drilling Sites, Caught-Between

Machine Safety).

11. Gas Flare

A gas flare alternatively known as a flare stack, is a gas combustion device used in industrial

plants such as Gas plant. Fire stacks are primarily used for burning off flammable gas released

by pressure relief valves during unplanned over-pressuring of plant equipment, during plant or

partial plant starts and shutdowns.

When industrial plant equipment items are over pressured, the pressure relief valve is an

essential safety device that automatically releases the gases. The released gases and liquids are

routed through large piping systems called flare headers to a vertical elevated flare.

VII.3 Hazard Mitigation Planning & Prevention

Identification & Evaluating the hazards at the worksite is very important. Many companies

within the oil and gas industry use the Job Safety Analysis Process (also referred to as a JSA,

Job Hazard Analysis, or JHA) to identify hazards and find solutions.

Establishing ways to protect workers, including developing and implementing safe practices

for:

Confined space; excavations

Chemical handling; exposure

Chemical storage

Electrical work

Emergency response

Equipment/machine hazards

Fall protection

Fire protection

Hot work, welding, flame cutting operations

Personal protective equipment use

Power sources (lockout/tag out provisions, safe distance from power lines)

Working in the heat, long shifts

Providing personal protective equipment (PPE). When engineering controls alone cannot

protect worker overexposure to chemicals, noise, or other hazards, the employer must

provide PPE.

Training of the workers & planning for contractor safety and their training also.

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Chapter VIII:

Economic Analysis

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VIII.1 Cost Estimation

An acceptable plant design must present a process that is capable of operating under conditions

which will yield a profit. Since net profit equals total income minus all expenses, it is essential to

be aware of the many different types of costs involved in manufacturing processes.

So a capital investment is required to meet up all the expenses involved in the plant and

determination of the necessary investment is an important part of a plant-design project.

VIII.2 Cash Flow for Plant Operation

Fig VII.2: Tree diagram for cash flow

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VIII.3 Capital Investment

The capital needed to set up our described plant can be divided into two major categories:-

1. Fixed Capital Investment

2. Working Capital Investment

1. Fixed Capital Investment

The capital needed to supply the necessary manufacturing and plant facilities is called the Fixed

Capital Investment.

2. Working Capital Investment

The capital needed to supply the payment of expenses involved in the plant operation is called

the working capital investment.

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1. Fixed Capital Investment:

Components Cost (Crore TK.) Assumed % of total

Purchased Equipment 240 40

Purchased Equipment Installation 66 11

Instrumentation 27 4.5

Piping 24 4

Electrical 36 6

Building 36 6

Yard Improvement 12 2

Service Facilities 54 9

Land 6 1

Engineering and supervision 45 7.5

Construction expenses 21 3.5

Contractor's fee 9 1.5

Contingency 24 4

Total Fixed Capital 600

2. Working Capital Investment:

Raw Material Cost

Finished product in stock & semi-finished product in manufacturing

Accounts Receivable

Operating Cost

Accounts Payable

Taxes Payable

Total Working Capital (approx.) = 120 Crore taka

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VIII.4 Plant Income Summary

Components Unit Selling Rate Income (crore

tk)

Gas Production 58.5

MMCFD $8.39/thousand cubic ft 143.68

Natural Gas Liquid

(NGL)

420

barrel/day $20/ barrel 24.53

Condensate 710

barrel/day $40 /barrel 81.792

Total Income From

Selling 250 Crore taka

VIII.5 Return on Investment

Total Income From Selling, Sj = 250 crore taka

Operating Cost, Co = 73% of Working Capital = 120 × 0.73 = 87.6 crore taka

Depreciation Cost, d = 2.75% of Equipment cost of the plant (Purchased + Installation) =

306 × 0.0275 = 8.415 crore taka / yr

Net profit before tax, Npo = Sj – Co – d = (250 – 87.6 – 8.415) = 153.985 crore taka/yr

Net profit after tax (34% of the Npo ), Np = 153.985 – (153.985 × 0.34) = 101.63 crore

taka / yr

So, Return on Capital Investment = 𝐹𝑖𝑥𝑒𝑑 𝐶𝑎𝑖𝑡𝑎𝑙 𝐶𝑜𝑠𝑡

𝑁𝑝 =

600 𝑐𝑟𝑜𝑟𝑒 𝑡𝑎𝑘𝑎

101.63 𝑐𝑟𝑜𝑟𝑒 𝑡𝑎𝑘𝑎/𝑦𝑟

= 6 year (approx.)

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Fig VII.5: Return on Investment chart

VIII.6 Plant Total Cash flow Summary

Items Cost (Crore taka)

Fixed Capital Cost 600

Working Capital 120

Total Capital Investment 720

Income From Total Selling 250

Net Profit After Tax (34%) 101.63

So in our case, Return on Capital Investment = 6 years

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Plant Layout

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Conclusion

Energy sector may be defined as the key of the world economy. Natural resources like natural

gas play an important role in this regard. Natural gas is main energy source of our power

generation and another chemical industry. It is also used as raw material in several industries.

Petrobangla has excellent consequences in survey exploration, drilling and gas processing.

Different kinds of processing plants exist in our country. Molecular Sieve Turbo Expander

(MSTE) plant is one of the modern technologies of the world. Another conventional technology

like silica gel and glycol extraction plant is used. We have used ASPEN HYSIS, Auto CAD and

MS Visio in different parts of this report. Plant training is like a bridge between academic and

practical knowledge. As plant trainee we have been introduced with the different processing

plants, fractionations, maintenance, utilities, metering and also with drilling. From this sessional

course we have learned application of basic engineering courses in actual field of process

designing, development of a clear concept on real plant scenario, process optimization-selection

of best suitable process for the plant and designing a new plant that meets economic feasibility.

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References

1. Datasheet from SGFL, Kailashtilla field

2. www.petrobangla.com

3. www.bapex.com.bd

4. Donald L. Kaltz and Robert L. Lee; Natural Gas Engineering: production

and storage

5. Plant Design & Economics For Chemical Engineers (Max Peters).pdf

6. https://www.osha.gov/SLTC/oilgaswelldrilling

7. Sam Mannan (Editor) (2005). Lee's Loss Prevention in the Process

Industries: Hazard Identification, Assessment and Control, Volume 1 (3rd

ed.)