CHAPTER ONE INTRODUCTION - bsu.edu.ly

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Libya

Ministry of Higher Education

Bright Star University – Braga


Faculty of Technical Engineering

Department of Chemical Engineering

Reducing Heavy Hydrocarbons in Fuel Gas

Prepared by:

Hawa Fawzi Moftah 21141016

Fatma Hussin Gaith Awad 21141095

Esra Mohamed El-malkey 21152824

Aya Salah Al-den Jalloul 21152845

Supervised by:

Hussin GH. Awad Awami

DEGREE OF BACHELOR IN CHEMICAL ENGINEERING

FACULTY OF TECHNICAL ENGINEERING

CODE OF PROJECT ……………………….

ii

Reducing Heavy Hydrocarbons in Fuel Gas

Prepared by:





Supervised by:

Hussin Awami

Project Report Submitted as Partial Fulfillment of the Requirements for the

Degree of Bachelor in Chemical Engineering

January, 2019

iii

ABSTRACT

There are various methods of conditioning fuel which aim to reduce the fuel’s energy

content and increase its molecular percent in methane and ethane. This allows for the engine to burn

off a cleaner fuel. In many shale-gas plays, especially wet- and/or condensate-rich shale gas plays,

only raw and heavy shale gas is available as fuel for compressor drives and power generation

turbines. As a result of the considerable richness (High Btu Value) of the raw gas in such shale-gas

plays, operators are finding it increasingly challenging to meet the regulatory requirements on the

emissions levels for the local compressor stations apart from having to run their engines running on

substantial de-rates especially for the larger high pressure (HP( range machines. Membrane Fuel

Gas Conditioning Units are completely passive and the feed gas requires no pretreatment, except for

standard filtration. Practical cases of how these units have helped in resolving issues with

problematic fuel gas will be discussed in the paper. In addition, heavy hydrocarbons rich gas can

damage or foul engine components, causing mechanical reliability issues & reduced

compressor/engine efficiencies, even leading to engine or turbine shutdown. Within these days,

there is a proposal to supply Sitre Oil Company power stations (I and II) by Hatieba gas as

alternative source in presence of any shortage in the existing sources, but the power plants

generators don't matching with the gas composition without conditioning. So, establish of Knockout

vertical drum separator and membrane technology for conditioning Hatieba gas is very important to

keep the power plants away of blackout.

Keywords: Heavy shale gas, standard filtration, emissions levels.

iv

DEDICATION

To the utmost knowledge lighthouse, to our greatest and most honored prophet Mohamed

May peace and grace from Allah be upon him. To the spring that never stops giving, to who weaves

my happiness with strings from her merciful heart? " To my mother ". To whom he strives to bless

comfort and welfare and never stints what he owns to push me in the success way who taught me to

promote life stairs wisely and patiently, to my dearest father. To whose love flows in my veins, and

my heart always remembers them, to my brothers and sisters. To those who taught us letters of gold

and words of jewel of the utmost and sweetest sentences in the whole knowledge. Who reworded to

us their knowledge simply and from their thoughts made a lighthouse guides us through the

knowledge and success path, to our honored teachers and professors.

v

ACKNOWLEDGEMENTS

We would like to take this opportunity first of all, submit thank Allah who made all the

things possible. For provided us strength determination and ability for achievement this project.

We would like to express our sincerely appreciation to our supervisor (Special Process Engineer,

Mr. Hussin GH El Awami) for his guidance and constant supervision as well as for providing

necessary information regarding the project & also for his support in completing the project, and

many thanks or gave us the golden opportunity to do this wonderful project on the topic of

(Reducing Heavy Hydrocarbons in Fuel Gas), which also helped us in doing a lot of Research and

we came to know about so many new nice things.

We have taken efforts in this project. However, it would not have been possible without the kind

support and help of many individuals and organizations. We would like to extend our sincere thanks

to all of them.

Words mean nothing to thank the person who were by our side throughout the study period and

especially in this project was supporting us in all its periods from beginning to end, we would like

to say thank you very much , and we know it is not enough to thank you.

vi

APPROVAL

This project report is submitted to the Faculty of Technical Engineering, Bright Star University –

Braga, and has been accepted as partial fulfillment of the requirement for the degree of bachelor in

Chemical Engineering. The members of the Examination Committee are as follows:

________________________________________

Supervisor

Hussin GH. Awad Awami …………………….




____________________________________________

Examiner 1

…………………………........ …………………….




____________________________________________

Examiner 2

…………………………… ….................................




vii

DECLARATION

I hereby declare that the project report is my original work except for quotations and

citations, which have been duly acknowledged. I also declare that it has not been previously, and is

not concurrently, submitted for any other degree at Bright Star University – Braga or at any other

institution.

By:





Date of Submitted: Monday, 21/01/2019 Time, 10:00

Date of Presentation: Monday, 28/01/2019 Time, 10:00

viii

TABLE OF CONTENTS

ABSTRACT III

DEDICATION IV

ACKNOWLEDGEMENTS V

APPROVAL VI

DECLARATION VII

TABLE OF CONTENTS VIII

NOMENCLATURES XIV

CHAPTER 1 1

1.1 Introduction 1

1.2.Membrane Background 2

1.3.How Membranes Work 2

1.4.Membrane Structure 3

1.5. Background 4

1.6. Problem Statement 5

1.7. Objectives 5

1.8. Aims of Project: 6

1.9. Types of Gas-Liquid Separations 8

1.9.1.Gravity Settling 8

1.9.2.Cyclone Flow 8

1.9.3.Inertial Precipitation: De-Misting, Scrubbing 9

1.9.4.Electrostatic Precipitation 9

1.9.5.Coalescence 9

1.9.6.Foam-Breaking 10

1.10.Gas engine application: 12

ix

1.11.Membrane Benefits [21] [22]

14

1.12.Other Applications of Membrane Technology 15

1.13.Membrane technology is an umbrella term referring to the mechanical separation

processes of gaseous or liquid streams with the use of membranes. 15

CHAPTER 2 16

2.MATERIAL AND ENERGY BALANCE 16

2.1. Calculation of dew and bubble points: 23

2.2. The Energy Balance data: 24

2.3. The Energy Balance Error: 24

CHAPTER 3 29

3. SEPARATOR UNIT PROCESS DESIGN 29

3.1. Principles of Separation: 29

3.2. Vertical Separator Parts: 29

3.3. Gas-Liquid Separator Design 30

3.3.1. Specifying Separators 30

3.4. Vertical separators 31

3.4.1. Basic Design Equations 31

3.5. Thickness of the Shell: 33

3.6.Design for the Atorispherical dished closure (cover) 33

CHAPTER 4 34

4.INSTRUMENTATION AND CONTROL 34

4.1 Instrumentation and control objectives 34

4.2 Safe plant operation: 34

4.3 Production rate: 34

4.4 Product quality: 35

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4.5 Typical control systems 35

CHAPTER 5 38

5.COST ESTIMATION 38

5.1.Economic Assumptions and methodology 38

5.2.Capital Costs 38

5.3.Operating costs 39

5.4.The cost of some project equipment : 39

CHAPTER 6 40

SAFETY 40

6.1. Natural gas 40

6.2. Types of Protection Equipment 40

6.2.1. Work Clothing 40

6.2.2. Head Protection 41

6.2.2.1. HARD HAT 41

6.2.3. Face Protection 41

6.2.3.1. Face Shield 41

6.2.3.2. Acid Suit 41

6.2.3.3. Eye Protection 42

6.3. Types of Eye Protection Equipment: 42

CHAPTER 7 44

CASE STUDY 44

7.HATIEBA GAS AS FUEL TO THE COMPANY POWER STATIONS: 44

7.1. Abstract 44

7.2.Introduction. 44

7.3. Hatieba gas analysis: 46

xi

7.4. Conclusion: 50

7.5. Recommendation: 50

CHAPTER 8 51

8.1. Plant Layout: 51

APPINDIX A 52

APPENDIX B 55

REFERENCES: 59

xii

List of Figures

Figure 1.1 Module Housing…….………………………………………………………….4

Figure 1.2 Conditioning fuel gas..………………………………………………………….6

Figure 1.3 Fuel gas conditioning for gas Engine...………………………………..……….13

Figure 1.4 Fuel gas conditioning for gas Turbine...………………………………..………14

Figure 2.1 Material Balance Diagram...……………………………………………………16

Figure 2.2 Overall Material Balance……………………………………………………….18

Figure 2.3 Mixing point Material Balance...……………………………………………….20

Figure 2.4 Stream (D) Mole Fraction...........……………………………………………….21

Figure 2.5 Stripper…………………………………………………………………………22

Figure 2.6 Membrane Energy Balance…………………………………………………….24

Figure 3.1 Separation Cross Section View………………………………………………..30

Figure 3.2 Gas-Liquid Separator Flow Diagram…………………………………………..31

Figure 4.1 Common Control System………………………………………………………36

Figure 4.2 Flow Control Valve…………………………………………………………….37

Figure 6.1 Indicate hard hat helmet………………………………………………………..41

Figure 6.2 Full-Face splash shield…………………………………………………………42

Figure 7.1 Hatieba 30'' gas pipeline distribution…………………………………………..45

Figure 7.2 Hatieba 30'' gas pipeline analysis………………………………………………46

Figure 7.3 Gas-Liquid separation connection……………………………………………..47

Figure 7.4 Hatieba 30'' gas properties……………………………………………………..48

Figure 8.1 power Station plant suppling with NCG………………………………………51

xiii

List of Tables

Table 1.1 Emissions Testing Data……………………………………………………………......6

Table 2.1 Streams mole fractions Calculation…………………………………………………...19

Table 2.2 Stream (W1) Calculation……………………………………………………………....20

Table 2.3 Stream (D) Calculation………………………………………………………………..21

Table 2.4 Stream (M) mole fraction Calculation………………………………………………...22

Table 2.5 Stream (D) Bubble point Calculation………………………………………………….23

Table 2.6 Stream (P) Dew point Calculation…………………………………………………….23

Table 2.7 Hf Calculation……………………………………………………………………….25

Table 2.8 HD Calculation ……………………………………………………………………..26

Table 2.9 HP Calculation………………………………………………………………………27

Table 2.10 HM Calculation…………………………………………………………………….27

Table 2.11 Energy Balance Error Calculation…………………………………………………...28

Table 3.1 Volumetric flow rate…………………………………………………………………..32

Table 5.1 Cost of Project………………………………………………………………………...39

Table 7.1 Cross and net heating value…………………………………………………………...49

xiv

NOMENCLATURES

Symbol Description Unit

NOx Nitrogen Oxides

CO Carbon Monoxide

NMHC Non-methane Hydrocarbons

BTU British Thermal Unit

VOC Volatile Organic Hydrocarbon

SOx Sulphur Oxides

MTR Membrane Technology and Research

BTEX Aromatic (Benzene, toluene, and three xylenes

EQT Membrane Manufacturing Company Name

MMscfd Million Standard Cubic Feet per Day

HP High Pressure

OPEX Operating Expense

Cp Heat Capacity

LCV Level Control Valve

PCV Pressure Control Valve

FCV Flow Control Valve

TCV Temperature Control Valve

S/W Sea Water Cooling System

1

Chapter 1

1.1. Introduction

Raw unprocessed natural gas is widely used to power field turbines and engines that

drive compressors or generate power. Compressor engine exhausts are a major source of a

variety of strictly regulated emissions including Nitrogen Oxides (NOx(, CO, unburned

non-methane hydrocarbons etc. Operators have to meet several stringent emissions

requirements to remain within the thresholds of allowable emissions limits of the above

mentioned components. The situation is highly aggravated when the raw fuel gas is rich in

heavy hydrocarbons. High levels of heavy hydrocarbons content in the fuel gas are

responsible for incomplete combustion and/or pre-detonation in the gas engines which lead

to increased CO and unburned non-methane hydrocarbons emissions (NMHC) beyond the

acceptable limits1. NOx emissions are also affected by high levels of heavy hydrocarbons

due to the richer BTU content of the fuel gas. [1]

Oftentimes the raw gas composition does not meet the minimum requirements of engine or

turbine suppliers. An excess of ethane, propane and C4+ hydrocarbons results in too low a

methane number for gas engines, or too high a Wobbe Index for turbines. Specifically, high

levels of heavy hydrocarbon components lead to pre-detonation in reciprocating gas

engines. This requires derating of the engines so that they can run smoothly. In turbines,

coking on the nozzles and in the combustion chamber leads to reduced efficiencies due to

fouling or damage to the blades. In both gas engines and turbines, increased emissions of

unburned VOCs will result if the inlet gas is too rich. [3]

Presence of high levels of sulfur, especially H2S, in the fuel gas directly impacts the

Sulphur Oxides (SOx( emissions. Sour fuel gas containing sizeable proportion of H2S will

lead to proportionately higher levels of SOx emissions. Apart from high SOx emissions

levels, an excess of acid gases, specifically carbon dioxide or hydrogen sulfide, can corrode

engine and turbine components, increasing maintenance needs and resulting in unscheduled

downtime. The amount of gas used by field engines is usually in the 0.5 to 5.0 MMscfd

range—too small to make treatment of the gas by conventional amine-based technology

economical. As a consequence, many engine users are forced either to live with the

2

problem gas and the resulting low reliability and high maintenance costs, or to install

costly-to-operate chemical scavenging systems. [1] [2]

The above-described problems can be ameliorated by processing the gas using a special

type of membrane that is more permeable to heavy hydrocarbons and acid gases than to

methane. Early work in this area was performed at Phillips Petroleum almost thirty years

ago.2 Over the last few years, one company, Membrane Technology and Research, Inc.

(MTR), of Menlo Park, CA, has developed commercial systems and processes

incorporating specialized membrane technology to treat heavy or sour fuel gas streams3.

The process, known as FuelSep™, is in use at a number of sites and for a variety of

upstream fuel gas streams. To date, these membranes have been installed at more than sixty

sites for heavy hydrocarbons separation from natural gas. Skid–mounted compact

membrane units make the Fuel Seperation process particularly suitable for remote

wellheads and compression stations where high levels of heavy hydrocarbons present in the

fuel gas are reduced significantly to remain within the emissions threshold limits. This

paper describes and compares two case studies and process configurations. [2] [4] [5]

1.2.Membrane Background

In the mid-1980s, membrane systems to remove carbon dioxide were introduced to the

natural gas processing industry. These membranes separate gases primarily by molecular

size. They permeate the small carbon dioxide molecules faster than the relatively larger

methane molecules, but retain the even larger heavy hydrocarbon molecules in the gas

stream. In contrast, recent advances in membrane technology have allowed development of

membranes that utilize differences in gas solubility to permeate heavy hydrocarbons,

carbon dioxide and water vapor simultaneously though the membrane. [3]

1.3.How Membranes Work

Membranes used to filter liquids are often finely microporous, but membranes used to

separate gases have only transient pores so small they are within the range of the thermal

motion of the polymer chains that make up the selective polymer layer. Permeation through

gas separation membranes is therefore best described by a process called solution-diffusion.

Gas molecules dissolve in the polymer membrane as in a liquid and then diffuse across the

membrane and then desorb from the polymer on the opposite interface which is typically

3

maintained at a lower pressure as compared to the feed. The rate of gas permeation is a

product of a solution term (how many molecules dissolve in the membrane), and a diffusion

term (how fast each individual molecule diffuses across the membrane). [5]

Fuel gas-

conditioning membranes are chosen from materials that maximize the effect of the solution

term. Although each individual molecule of butane, for example, diffuses more slowly

across the membrane than each individual molecule of methane, the very high solubility of

butane more than compensates for the slower diffusion. Fuel gas conditioning membranes

therefore preferentially permeate water, carbon dioxide, hydrogen sulfide, C2+

hydrocarbons and BTEX aromatics, while retaining methane. Because most of us are

familiar with conventional filtration, this result feels counter-intuitive. Nevertheless, these

unique properties are what make the membranes particularly useful in fuel gas conditioning

applications. [7]

1.4.Membrane Structure

Membranes used to separate heavy hydrocarbons from natural gas typically have multilayer

composite structures of the type shown in Figure 1. Composite membranes are used

because the optimum materials for performing the separation are rubbery polymers, which

are mechanically weak. Furthermore, to obtain high permeation rates, the selective

membrane must be very thin, typically between 0.5 and 5.0 μm thick. Finally, the

membrane must be able to support a pressure differential of 200 to 1,500 psi. [6]

Even though composite membranes have extremely thin selective layers, many square

meters of membrane are required to separate a useful amount of gas. The units into which

large areas of membrane are packaged are called membrane modules. In the Fuel

Separation process, spiral-wound 4 membrane modules of the type illustrated in Figure 1

are used. The membranes are formed into a sealed membrane envelope, and then, with

appropriate feed and permeate channel spacer netting, are wound around a perforated

central collection pipe. The module is placed inside a tubular pressure vessel. One to six

modules may be connected in series within each pipe. Pressurized feed gas passes axially

down the module, across the membrane envelope on the feed side.

4

A selective portion of the feed permeates into the membrane envelope, where it spirals

towards the center and is collected through the perforated permeate collection pipe. The

treated gas is withdrawn from the feed side at the residue end of the module. [8]

Fig. 1.1. Module Housing

1.5. Background

The Reduce Emissions for Compressor Stations in Condensate-rich Shale Gas Plays by

Reducing Heavy Hydrocarbons in Fuel Gas.In many shale-gas plays, especially wet- /or

condensate-rich shale gas plays, only raw and heavy shale gas is available as fuel for

compressor drives and power generation turbines.[11] As a result of the considerable

richness (High Btu Value) of the raw gas in such shale-gas plays, operators are finding it

increasingly challenging to meet the regulatory requirements on the emissions levels for the

local compressor stations apart from having to run their engines running on substantial de-

rates especially for the larger HP range machines. In addition, heavy hydrocarbons rich gas

can damage or foul engine components, causing mechanical reliability issues & reduced

compressor/engine efficiencies, even leading to engine or turbine shutdown.[9] The

immediate impact of this is loss of gas and oil production until the components are replaced

or fixed. This paper describes the use of unique reverse-selective membranes which

preferentially removes heavy hydrocarbons components from the raw shale-gas to produce

clean fuel gas at these sites. Numerous fuel gas conditioning units have been installed in

5

several shale-gas plays across the country by companies like EQT Midstream (Marcellus

and Devonian), Peregrine Pipeline (Barnett Shale) and in the Eagle Ford shale area for

reducing the heavy & sour contents from the fuel gas & subsequently also meet the

emissions requirement on the Volatile Organic Compound )VOC) levels.[12] These systems

have no moving parts, are designed for simple, unattended operation and are virtually

maintenance-free. By effectively reducing the heavy hydrocarbons content, Membrane Fuel

Gas Conditioning Units reduces the volume of unburned VOC’s emissions caused due to

incomplete combustion of hydrocarbons in the firing chamber. These units have been used

to fix derate and high maintenance problems due to poor fuel gas quality for Wartsila,

Caterpillar, Waukesha, Superior and other reciprocating engine makers and also for turbine

fuel gas conditioning. Skids have been used to produce from 0.1 to 110 million scfd

(MMscfd) of clean gas. Membrane Fuel Gas Conditioning Units are completely passive and

the feed gas requires no pretreatment, except for standard filtration. Practical cases of how

these units have helped in resolving issues with problematic fuel gas will be discussed in

the paper.

1.6. Problem Statement

To accommodate the significant increase in natural gas production in the oil and gas

industry is expanding the infrastructure needed to transport natural gas to its customers.

Compressor stations are a key component to transporting gas through pipelines.

The problem with using directly produced natural gas as fuel is that, typically, it is very

rich, or abundant in heavier hydrocarbons. The leaner the fuel, meaning fuel consisting of

lighter hydrocarbons such as methane and ethane, burn better and have several benefits

which are discussed later in this chapter. [10]

1.7. Objectives

There are various methods of conditioning fuel which aim to reduce the fuel’s energy

content and increase its molecular percent in methane and ethane. This allows for the

engine to burn off a cleaner fuel.

Analyzing for the main goal of this study is the Membrane Technology for Fuel Separation

system will be used as the method of fuel conditioning.

https://en.wikipedia.org/wiki/Volatile_organic_compound

https://en.wikipedia.org/wiki/Volatile_organic_compound

6

The MTR Fuel Separation system functions with the use of membranes, and this

experiment was designed to validate its function, characterize its performance map,

determine if it is economical to use, and discover any other benefits such as emission

reduction. After gathering over 44 hours of testing data, a performance map was created

which associated the differential pressure across the membrane with its performance index

as well as its rate of return. [10]

Providing Throughout this report more information will be provided on membrane

technology, the design procedures, the results of the testing, and discussion of the unit’s

performance as well as performance in the future.

Fig. 1-2 Conditioning Fuel Gas

1.8.Aims of Project:

1. Study the possibility of purification the shale-gas from heavy hydrocarbon.

2. The purification of natural gas reducing the emissions of unwanted exhaust.

3. Providing the clean fuel gas allow getting high heat value and reducing the high rate

of maintenance cost and replacing spare parts. [7]

Emissions Testing Data

Component Percent Difference

Control vs. Test

Gain or Reduction

%O2 6.54% Gain

ppm CO -21.52% Reduction

ppm NO -82.87% Reduction

ppm NO2 -43.03% Reduction

ppm NOx -60.70% Reduction

Tab. 1-1 Emissions Testing Data

7

Membranes have gained an important place in chemical technology and are being used

increasingly in a broad range of applications. The key property that is exploited in every

application is the ability of a membrane to control the permeation of a chemical species in

contact with it. This article provides a general overview of the entire membrane area. After

a review of the historical development of membranes, the principal types of membrane are

described briefly. The manufacture of the more important types of membrane and the

packaging of membranes in modules to exploit their properties are discussed. The principal

membrane applications, including microfiltration, ultrafiltration, reverse osmosis,

pervaporation, gas separation, and controlled drug delivery are described. The particular

focus is on the use of membranes to solve separation problems. A detailed section on

membrane reactors is included. More complete descriptions of some of the important

specific applications of membranes are given elsewhere.

The gas has a high heating value, high hydrocarbon dew point, and low octane number,

which can cause operating problems. In gas engines, the rich fuel may pre detonate which

can severely damage the internals of the firing chamber. Also, the condensation of

hydrocarbons (due to day-night temperature variations) may damage combustion chambers

in gas engines and gas turbines, increasing maintenance cost and downtime.

Since the engines drive and turbines drive other machinery, any disruption in their

operation will reduce production resulting in significant revenue loss. [11]

To increase the reliability and reduce unscheduled downtime of such key equipment, fuel

conditioning through membrane technology is a simple way to solve this problem.

The conditioned fuel gas is significantly depleted in the higher hydrocarbons, is

completely dehydrated, and still retains the heating value needed to drive a compressor.

The feed gas is first compressed and sent to a condenser where it is cooled. A portion of the

heavy hydrocarbon fraction condenses and is recovered as a liquid. [13]

The non-condensed portion of the gas, which still contains a significant fraction of the

heavy hydrocarbon components, passes across the surface of the membrane.

8

1.9. Types of Gas-Liquid Separations

Two general situations are liquid-dispersed-in-gas and gas-dispersed-in-liquid. The first

situation arises for instance when

Vapor from a boiling or sparged pool of liquid carries (entrains) liquid droplets

Vapor emerges from a flashing two-phase flow

A gas-vapor mixture is cooled.

The second situation may arise when

Gas passes through, or vapor is generated within, a liquid, and is particularly

pronounced if the liquid is viscous

A liquid is agitated vigorously.

In general these gas-liquid mixtures are undesired and require separation. [14]

The liquid-in-gas situation is examined first. The method of separation depends on the size

of the liquid droplets and also on the loading in the gas. We examine the methods starting

with the largest droplets and the highest loadings.

1.9.1. Gravity Settling

Two-phase mixtures emerging from gas-liquid pipelines often have large liquid loadings

and gross dispersion of liquid in the gas. A typical liquid concentration is 50 litres per

cubic meter of gas. A simple ‘knock-out’ pot can do the initial separation of gas and liquid

and should be installed ahead of any more sophisticated device. Gas leaves at the top and

liquid leaves at the bottom, both streams probably containing some amount of the other

phase. [15]

1.9.2. Cyclone Flow

For liquid content in the range 1 to 50 litres per cubic meter a cyclone is effective in

separating liquid from gas, especially if the liquid droplets are larger than 10-50 microns.

However, smaller droplets are carried out with the gas stream. [16]

9

1.9.3. Inertial Precipitation: De-Misting, Scrubbing

For droplets greater than 5-50 microns, passage of the gas-liquid through a wire-mesh pad

can remove most of the liquid. The gas passes around the wire elements but the liquid,

having more inertia, collides with the wire and collects (precipitates) on it. The liquid runs

together (i.e., coalesces) and forms droplets that are large enough to detach and fall back

against the main flow. The cut size of the droplets removed (i.e., the diameter of droplet

such that 50 percent are removed from the gas) may be estimated from the formula.

Cut size = 2.302 x 106 x [(gas viscosity x wire diameter) / (liquid density x gas velocity)]

1/2

It is common to install a mesh pad at the top of a knock-out pot, to remove some of the

liquid that still remains in the gas.

Another variety of inertial precipitation is the scrubber where the droplets which it is

desired to remove collide with larger drops of liquid sprayed into the path of the gas. These

drops are large enough to settle by gravity. This type of system is used for droplets 20

microns or less. There are several styles of scrubbers, some of them very thorough.

1.9.4. Electrostatic Precipitation

Droplets as small as 2 microns may be removed from a stream of gas by being given a

charge through (ionization of the gas) and then being collected on an electrode. The

method works better at larger sizes, e.g., above 50 microns. [16]

1.9.5. Coalescence

When droplet size is very small, say less than a micron, the inertial techniques become

ineffective. Mists and fogs comprise droplets in this size range. Small particles follow the

motion of the gas so closely that there is little chance for capture by impingement. In this

case the phenomenon of choice is coalescence. The gas-liquid mixture is passed through a

bed of fine fibers onto which the liquid droplets adhere in passing and on which they grow

to a size that lets them separate after the gas-liquid mixture leaves the coalescer. The bed is

typically a hollow cylinder, either vertical or horizontal. Gas and liquid enter at one end and

emerge from the outside of the cylinder all along its length. The fibers are sized to enhance

the growth of droplets. [17]

10

They may have a non-wetting fluoropolymer coating which preserves the captured droplets

as droplets and enhances their ability to unite with one another. [4]

1.9.6. Foam-Breaking

The other type of gas-liquid mixture sometimes requiring separation is the mixture where

the liquid forms the continuous phase, i.e., froths and foams. Sometimes it is essential to

separate the liquid components from the gas components. Often however, the problem is

just that the foam takes up space in a reactor or in the stages of a distillation column. In the

extreme, foam may start issuing from the vessel where gas was expected. There are three

situations. [15]

1. A liquid is boiling or gas is being passed through it. Even though the gas separates from

the liquid by leaving the top surface it still occupies space within the bubbly mixture. The

in situ liquid volumetric fraction in the mixture is generally described by an expression of

form. [18]

Gas & liquid, in

Gas,

out

Coalesced

liquid

11

vol frac. liquid = 1 / ( 1 + a * US )

Where, US is the superficial velocity of the gas (volumetric flow divided by cross-sectional

area) and (a) is a constant the value of which depends on the system and particularly on

liquid viscosity. This behavior is simply a fact of life: the expansion of the liquid into a

bubbly mixture has to be taken into account when designing or filling a vessel. [5]

2. A gas has been introduced into the liquid during part of a process but that part is over.

While most of the bubbles have risen and disappeared, a population of small slowly-rising

bubbles remains. This situation occurs most commonly with viscous liquids. The rise

velocity is proportional to bubble diameter squared and inversely to liquid viscosity. If the

gas must be removed and if it is not practical to wait long enough, then a vacuum may be

applied in order to increase the size of the bubbles or the liquid may be heated to reduce its

viscosity. [19]

3. A true foam is present, i.e., a layer of stable bubbles at the top of the liquid pool.

Generally a third, trace component is responsible for the stability of the bubbles.

Mechanical means, like rotating bars or paddles, are sometimes used to stir and break the

bubbles. More commonly a chemical, generally at low concentration (a few parts per

million), is added as an anti-foam. The nature and operative mechanism of these

substances varies but it is thought that they may substitute their activity for that of the

component causing the foam. In any case they cause the liquid membrane between the

bubbles to rupture or to thin and drain back into the pool, thus allowing the gas in the

bubbles to escape. Silicones are a popular anti-foam, as are several different organic

compounds and a few inorganics. Anti-foams are chosen for their effectiveness in the

system at hand and also for the lack of any adverse effects on the process or product. For

instance, some anti-foams are unacceptable in food or in packaging materials that will come

in contact with food. [6]

12

1.10. Gas engine application:

The membrane separates the gas into two streams: a permeate stream enriched in heavy

hydrocarbons and a residue stream which is depleted of heavy hydrocarbons.

A- The permeate stream is recycled to the compressor inlet while the residue stream (which

is maintained at pressure) is the treated natural gas stream. [2]

B- Natural gas is commonly used as a fuel in gas engines and turbines in the hydrocarbon

processing industry.

C- Frequently, raw natural gas is the only fuel available to operate compressor stations in

remote locations and on offshore platforms. This gas has a high heating value, high

hydrocarbon dew point, and low octane number, which can cause operating problems.

D- In gas engines, the rich fuel may pre-detonate which can severely damage the internals

of the firing chamber.

E- In addition, condensation of hydrocarbons (due to day-night temperature variations) may

damage the combustion chambers in gas engines and gas turbines, increasing

maintenance costs and downtime. [18]

F- Since the engines and turbines drive other machinery, any disruption in their operation

will reduce production resulting in significant revenue loss.

G- Fuel gas conditioning is particularly important for gas turbines on offshore platforms,

where this equipment is the only source of power.

H- To increase the reliability and reduce unscheduled downtime of such key equipment, a

simple technology that conditions fuel gas is required. [19]

13

A flow diagram of the membrane to condition raw natural gas is shown in Fig. 1.4.

Fig. 1.3. Fuel gas conditioning for gas Engine

The gas, at a pressure of 100 psig, is compressed to 1000 psig and cooled in an air cooled

after cooler.

The heavy hydrocarbons are condensed and recovered as a liquid. The high-pressure gas,

saturated in heavy hydrocarbons, contains 6.2% of C4+ hydrocarbons and over 5000 ppm

hydrogen sulfide. [17]

This gas is not an ideal engine fuel. To improve the gas quality, the pressurized fuel stream

is sent to the membrane system which reduces the total C4+ hydrocarbon content to 2.1%

and removes about 80% of the hydrogen sulfide.

The treated gas is then routed to the gas engine as fuel. The heavy hydrocarbon rich

permeate stream is sent to the feed side of the compressor. The fuel conditioning system is

completely passive. The power to drive the separation is provided by the existing

compressor, so that no new rotating equipment is required. In addition, the conditioning

occurs at ambient temperature, avoiding the issues of hydrate formation. [20]

The turbines are frequently powered by raw, associated gas produced with the oil. This raw

gas is typically rich in condensable hydrocarbons and at low pressure.

Fig. 1.4. Shows process flow diagram of a fuel conditioning system for gas turbine. The

fuel is compressed in a screw compressor from 35 to 285 psig.

14

The gas is then cooled, partially condensing the heavier hydrocarbons, which are removed

from the gas in a separator. Since the gas from the separator is fully saturated, condensation

may occur in the fuel line to the turbine. [21]

Moreover, this gas is very rich in hydrocarbons and may not meet the fuel specifications of

the turbine manufacturer.

Rich fuel tends to burn less efficiently in the combustors, leading to carbon formation,

which fouls and damages the turbine blades. Injection of liquid hydrocarbons and

incomplete combustion of the rich fuel can lead to unscheduled downtime and lost

production.

Fig. 1.4. Fuel gas conditioning for gas Turbine

1.11. Membrane Benefits [21] [22]

Removes heavy components such as C3+ to clean up fuel gas.

Removes significant portions of acid gases such as H2S and CO2 that will reduce

acid formation in the turbine or engine exhaust and reduce emissions.

Increases reliability of gas engines and turbines.

Operates at ambient conditions with no external heating required to prevent hydrate

formation.

Eliminates need to de-rate gas engine.

Decreases maintenance costs and reduces unscheduled downtime.

Increases recovery of liquids.

Contains no moving parts, simple to operate and maintain

15

1.12. Other Applications of Membrane Technology

1.13. Membrane technology is an umbrella term referring to the mechanical

separation processes of gaseous or liquid streams with the use of membranes.

Although it is a relatively young technology, it proves to have many benefits to a variety of

industries.

Membrane systems can be found in water treatment using reverse osmosis, in waste water

purification because of ultra and microfiltration that can be achieved with membranes,

filtration in the food industry, for medical applications such as artificial kidneys and lungs,

as fuel cells, in gas separation processes, and these are just a few examples.

One of the reasons this technology is becoming more useful is because membranes use less

energy than other separation processes. [23]

16

Chapter 2

2. Material and Energy Balance

Fig.2-1 Material Balance Diagram

The base of calculation is 100 Kmol/hr of raw natural gas. Stream (F)

Assume that 2 % of raw natural gas containing heavy hydrocarbon. Stream (W1)

For overall material balance:

Then, from the feed gas composition we can calculate:

Then from the feed gas composition we can calculate:

F = P + D + M ……………………………………………………………………………..(2-1)

Where, F= 100 Kmol/hr

We assume the separation conversion is 98%

Then, F + N = W1 ……………………………………………………………………….…(2-2)

Then, W1 = D + R …………………………………………………………………………(2-3)

Fin Fan

Cooler

Membrane System 94%

Conditioned Fuel Gas74% C1

9% C217% C3+

Permeate

Separator

Heavy Hydrocarbonesand Water

Natural Gas

Raw Gas

To Supply Power Stations

Membrane Technology for Fuel Gas Conditioning

CO2= 0.0130H2S= 0.0050

C1= 0.7250C2= 0.0950C3= 0.0990i-C4= 0.0240

n-C4= 0.0250n-C5= 0.0130H2O= 0.0010

C3+

D = 2.082466 Kmol/hr

P = 93.877551 Kmol/hr

Conversion = 98 %

W1

W2 = 8.163265 Kmol/hr

Stripper

Off GasesM= 4.039983 Kmol/hr

N= 4.123282 Kmol/hr

F= 100.00 Kmol/hr

17

From equation (2) and (3) we get that,

F + N = D + R

For C1 Balance:

YC1 (F) * F + YC1(N) * N = YC1(D) * D + YC1(R) * R ……………………………………(2-4)

YC1(N) and YC1(D) = 0

Then, YC1 (F) * F = YC1(R) * R

The separation Conversion is 98 %

Then, YC1 (R) = YC1(F) * 98 %

YC1(R) = 0.7250 * 0.98 = 0.7105

From Equation (4) YC1 (F) * F = YC1(R) * R

R = (0.7250 * 100) / 0. 7105 = 102.040816 Kmol/hr

Then, W1 = R * (100/98)

= 102.041 Kmol/hr * (100/98) = 104.123282 Kmol/hr

From Equation (3) W1 = D + R

D = W1 - R = 104.123 – 102.041 = 2.082466 Kmol/hr

Fron Equation (2) F + N = W1

Then, N = W1 – F = 104.123 – 100 = 4.123282 Kmol/hr

Membrane System Separation (MSS) percentage is 92 %

Then, P = 92 % of R P = 102.041 * 0.92 = 93.877551 Kmol/hr

Where, R = P + W2 ……………………………………………………………………….(2-5)

Then, W2 = R – P W2 = 102.041 – 93.877 = 8.163265 Kmol/hr

From the Material Balance around the Stripper, we can calculate the Off-gas stream (M)

Where, W2 = N + M ………………………………………………………………………(2-6)

Then, M = W2 – N M = 8.146 – 4.123 = 4.039983 Kmol/hr

18

Fig.2-2 Overall Material Balance

We assume that the percentage of stream P which is:-

C1= 74 % Y(C1) = 0.74

C2 = 09 % Y(C2) = 0.09

C3+ = 17 % Y(C3

+) = 0.17

Total 1.0000

Then, the moles of the stream P components are:-

𝑪𝟏 = 𝑃 ∗ 𝐶1% = 93.877551𝐾𝑚𝑜𝑙

ℎ𝑟 ∗

74

100 = 69.469388 Kmol/hr

𝑪𝟐 = 𝑃 ∗ 𝐶2% = 93.877551𝐾𝑚𝑜𝑙

ℎ𝑟 ∗

9

100 = 8.448979 Kmol/hr

𝑪𝟑+ = 𝑃 ∗ 𝐶3+% = 93.877551𝐾𝑚𝑜𝑙

ℎ𝑟 ∗

17

100 = 15.959183 Kmol/hr

Total 93.877551 Kmol/hr

C1 = 0.74

C2 = 0.09

C3+= 0.17

1.00

F = P + D + M

Overall M. BF= 100 Kmol/hr

P= 93.877551 Kmol/hr

D= 2.082466 Kmol/hr

CO2 = 0.0130H2S = 0.0050

C1 = 0.7250C2 = 0.0950C3 = 0.0990i-C4 = 0.0240

n-C4= 0.0250n-C5= 0.0130H2O = 0.0010

M = 4.039983 Kmol/hr

19

Then, 15.959183 Kmol/hr of (C3+) in stream (P) is consisting of the following percentage:-

C3 mole fraction = 94% of (C3+) X 0.17 = 0.1598

C3 quantity = 0.1598 𝑋 𝟏𝟓.𝟗𝟓𝟗𝟏𝟖𝟑

0.17 = 15.001632 Kmol/hr

iC4 mole fraction = 2.4% of (C3+) X 0.17 = 0.00408

iC4 quantity = 0.00408 𝑋 𝟏𝟓.𝟗𝟓𝟗𝟏𝟖𝟑

0.17 = 0.383020 Kmol/hr

nC4 mole fraction = 2.6% of (C3+) X 0.03 = 0.00442

nC4 quantity = 0.00442 𝑋 𝟏𝟓.𝟗𝟓𝟗𝟏𝟖𝟑

0.17 = 0.414938 Kmol/hr

nC5 mole fraction = 0.9% of (C3+) X 0.17 = 0.00153

nC5 quantity = 0.00153 𝑋 𝟏𝟓.𝟗𝟓𝟗𝟏𝟖𝟑

0.17 = 0.143633 Kmol/hr

H2O mole fraction = 0.01 of (C3+) X 0.17 = 0.000017

H2O quantity = 0.000017 𝑋 𝟏𝟓.𝟗𝟓𝟗𝟏𝟖𝟑

0.17 = 0.001596 Kmol/hr

C3+ in stream (P):- i) Total Mole fraction = 0.17

ii) Total Moles = 15.959183 Kmol/hr

To calculate Stream (W1) mole fraction we have to calculations stream (N) mass and

mole fraction as following:-

Streams (F) (Kmol/hr) (N) (Kmol/hr) (N) Mole Frac.(Kmol/hr)

C3 = YC3 x 100 = 9.9 𝑁

𝐹 𝑥 C3(F) = 2.519784

𝐶3 (𝑁)

𝑇𝑜𝑡𝑎𝑙 =

2.519784

4.123282 = 0.611111

iC4 = YiC4 x 100 = 2.4 𝑁

𝐹 𝑥 iC4(F) = 0.610856

𝑖𝐶4 (𝑁)

𝑇𝑜𝑡𝑎𝑙 =

0.610856

4.123282 = 0.148148

nC4 = YnC4 x 100 = 2.5 𝑁

𝐹 𝑥 nC4(F) = 0.636309

𝑛𝐶4 (𝑁)

𝑇𝑜𝑡𝑎𝑙=

0.636309

4.123282 = 0.154321

nC5 = YnC5 x 100 = 1.3 𝑁

𝐹 𝑥 nC5(F) = 0.330881

𝑛𝐶5 (𝑁)


0.330881

4.123282 = 0.080247

H2O = YH2O x 100 = 0.1 𝑁

𝐹 𝑥 H2O(F) = 0.025452

𝐻2𝑂 (𝑁)


0.025452

4.123282 = 0.006173

Total 16.2 4.123282 1.000000

Tab. 2-1 Streams Mole. Fractions Calculation

20

Fig. 2-3 Mixing Point Material Balance

Equation to calculate mole fraction of stream (W1) for {CO2, H2S, C1 and C2} is the;

Yxi (W1) = 𝑌𝑥𝑖(F) ∗ F

W1 …………………………………………………………………….(2-7)

Where, the equation to calculate the heavy hydrocarbons of stream (W1) for {C3, iC4,

nC4, nC5 and H2O} is the; Yxi (W1) = (𝑌𝑥𝑖(F) ∗ F)+ (𝑌𝑥𝑖(N) ∗ N)

W1 ………………………...(2-8)

Stream (W1) Calculation Mole Frac. Moles (Kmol)

1. YCO2(W1) = 0.013 ∗ 100

104.123282 = 0.012485 1.3

2. YH2S(W1) = 0.005 ∗ 100

104.123282 = 0.004803 0.5

3. YC1(W1) = 0.725 ∗ 100

104.123282 = 0.696289 72.5

4. YC2(W1) = 0.095 ∗ 100

104.123282 = 0.091238 9.5

5. YC3(W1) = (0.099 ∗ 100) +(0.611111 ∗ 4.123282)

104.123282 = 0.119279 12.4197

6. YIC4(W1) = (0.024 ∗ 100) +(0.148148 ∗ 4.123282)

104.123282 = 0.028916 3.0109

7. YnC4(W1) = 0.025 ∗ 100 +(0.154321 ∗ 4.123282)

104.123282 = 0.030122 3.1363

8. YnC5(W1) = 0.013 ∗ 100 +(0.080247∗ 4.123282)

104.123282 = 0.015663 1.6309

9. YH2O(W1) = 0.001 ∗ 100 +(0.006173∗ 4.123282)

104.123282 = 0.001205 0.1255

Total = 1.000000 104.1233

W1 = F + N

Mixing Point M. BF= 100 Kg/hr W1= 104.123282 Kg/hr

CO2 = 0.0130H2S = 0.0050

C1 = 0.7250C2 = 0.0950C3 = 0.0990i-C4 = 0.0240

n-C4= 0.0250n-C5= 0.0130H2O =0.0010

N= 4.123282 Kg/hr

21

Tab. 2-2 Stream (W1) Calculation

Stream (D) mole fraction calculations:-

Fig. 2-4 Stream (D) mole fraction calculations

Streams (W1) (Kmol/hr) (D) (Kmol/hr) (D) Mole Frac

YCO2(W1) = 1.3 YCO2(D) = 1.3 x 0.02 = 0.0260 𝐶𝑂2 (𝐷)

𝑇𝑜𝑡𝑎𝑙= 0.012466

YH2S(W1) = 0.5 YH2S(D) = 0.5 x 0.02 = 0.0100 𝐻2𝑆 (𝐷)

𝑇𝑜𝑡𝑎𝑙= 0.004806

YC1(W1) = 72.5 YC1(D) = 72.5 x 0.2 = 1.4500 𝐶1 (𝐷 )

𝑇𝑜𝑡𝑎𝑙= 0.696314

YC2(W1) = 9.5 YC2(D) = 9.5 x 0.02 = 0.1900 𝐶2 (𝐷)

𝑇𝑜𝑡𝑎𝑙= 0.091248

YC3(W1) = 12.4197 YC3(D) = 12.4197 x 0.02 = 0.2484 𝐶3 (𝐷)

𝑇𝑜𝑡𝑎𝑙= 0.119285

YIC4(W1) = 3.0109 YIC4(D) = 3.0109 x 0.02 = 0.0602 𝑖𝐶4 (𝐷)

𝑇𝑜𝑡𝑎𝑙= 0.028911

YnC4(W1) = 3.1363 YnC4(D) = 3.1363 x 0.02 = 0.0627 𝑛𝐶4 (𝐷)

𝑇𝑜𝑡𝑎𝑙= 0.030112

YnC5(W1) = 1.6309 YnC5(D) = 1.6309 x 0.02 = 0.0326 𝑛𝐶5 (𝐷)

𝑇𝑜𝑡𝑎𝑙= 0.015655

YH2O(W1) = 0.1255 YH2O(D) = 0.1255 x 0.02 = 0.0025 𝐻2𝑂 (𝐷)

𝑇𝑜𝑡𝑎𝑙= 0.001203

Total 104.1233 2.0824 1.000000

Tab. 2-3 Stream (D) Calculation

W1= 104.123282 Kmol/hr

R = 102.041816 Kmol/hr

D = 2.082466 Kmol/hr

Se

pa

rato

r9

8 %

CO2 = 0.012485H2S = 0.004803

C1 = 0.696289C2 = 0.091238C3 = 0.119279i-C4 = 0.028916

n-C4 = 0.030122n-C5 = 0.015663H2O = 0.001205

1.000000

22

From overall material balance we can calculate the stream (M) mole fraction from equation (1)

F = D + P + M

Cxi (F) = Cxi (D) + Cxi (P) + Cxi (M) ''Kmol/hr''………….………………………..…… (2-9)

Where, C3+ is equal to {C3 + iC4 + nC4 + nC5 + H2O} ###

Comp.

Stream

(F)

Kmol/hr

Stream

(D)

Kmol/hr

Stream

(P)

Kmol/hr

Stream

(N)

Kmol/hr

Stream

(M)

Kmol/hr

Stream

(M) mole

Fraction

CO2 1.3 0.026 0 0 1.274 0.315348

H2S 0.5 0.01 0 0.49 0.121288

C1 72.5 1.45 69.469388 0.110433 1.470179 0.363907

C2 9.5 0.19 8.448979 0.055217 0.805804 0.199457

C3+ 16.2 0.406466 15.959183 3.957632 0 0

Total 100.000 2.082466 93.877551 4.123282 4.039983 1.000000

Tab. 2-4 Stream (M) Mole Fraction Calculation

Fig. 2-5 Stripper

From overall material balance:

F = D + P + M

100 Kmol/hr = {2.082466 + 93.877551+ 4.039983} = 100 Kmol/hr

Error % = Input−Output

Input × 100 Material Inpot = Material Outpot

= 0.00 %

Strip

per

W1 (Permeate)

M (Off Gases)

N (C3+ Recovery)

23

2.1. Calculation of dew and bubble points:

Only sufficient trial Calculation will be made to illustrate the method used.

For the same basis in material balance which equals to 100 kmol/hr of feed:

Estimation of dew and bubble points:

Bubble point ∑ xi = ∑ Kixi = 1.0

Dew point ∑ yi = ∑ yi / Ki = 1.0

The K values are taken from the DePriester charts. (Appendix – A)

For stream (D)

Tab. 2-5, Stream (D) Bubble Point Calculation

For stream (P)

Tab. 2-6, Stream (P) Dew Point Calculation

com's xi ki @ 80 oC xi * ki ki @ 90 oC xi * ki ki @ 85 oC xi * ki

800 Kpa 800KPa

C1 …… 26 33 32.5

C2 …… 7.2 15 14.9

C3 0.0944 3.1 0.29264 8 0.7552 7.9 0.74576

I-C4 0.0228 1.6 0.03648 5 0.114 4.9 0.11172

N-C4 0.0237 1.2 0.02844 4.3 0.10191 4.4 0.10428

N-C5 0.0123 0.49 0.006027 2.35 0.028905 2.5 0.03075

total 0.363587 1.000015 0.99251

Estimate the Bubble Point of Stream (D)

com's Yi ki @ -25 oC ki @ -20 Oc yi / ki ki @ -15 oC yi / ki

800 Kpa 800 Kpa 800 Kpa

C1 0.7366 12.5 0.058928 13 0.05666154 13.3 0.055383459

C2 0.1508 1.4 0.107714286 1.5 0.10053333 1.6 0.09425

C3 0.0581 0.28 0.2075 0.33 0.17606061 0.38 0.152894737

I-C4 0.0141 0.09 0.156666667 0.18 0.07833333 0.13 0.108461538

N-C4 0.0147 0.054 0.272222222 0.068 0.21617647 0.076 0.193421053

N-C5 0.0076 0.0134 0.567164179 0.016 0.475 0.01921 0.395627277

total 1.370195354 1.10276528 1.000038064

Estimate the Dew Point of Stream (P)

24

2.2. The Energy Balance data:

1) The temperature of streams F, P , D and M

2) Enthalpy calculations for gaseous streams are according to the equation:

H= T

T

nCpdT0

(KJ/hr)

Where:

Cp = a + bt + cT2

J/K mol ºC

H = Enthalpy change from T toT0 (KJ/hr)

n = Molar flow rate (K mol/hr)

T = Temperature of stream

To = Reference temperature, taken at 25 ºC

a, b and c = Constants of Heat capacity.

Fig. 2.6 Membrane Energy Balance

Cp= a (T-TO)+ 2b (T

2-TO

2)+ 3

C (T3-TO

3) ……………………………………(2-10)

HF =∑( n * (Cp) *T) ……………………………………………………………(2-11)

See Index (B) Heat Capacity Constants values

25 oC

20 oC R

25 Oc

100 = 100

# # #

Input = Outpot

F = D + P + M

100 = 2.082466 + 93.877551 + 4.039983

Membrane Unit

D = 2.082466 kmol/hr

F = 100 kmol/hr

P = 93.877551 kmol/hr

M = 4.039983 kmol/hr

25

For stream (F)

Calculation of HF as follow:

Cp = a (T-TO) + 2b (T

2-TO

2)+ 3

C (T3-TO

3)

Hf =∑( n * (Cp) *T)

1.3 [(17.46 * (25-20)) + (0.09/2 * (25^2-20^2)) + (-1.01E-4/3 *

(25^3-20^3))] * (25-20) = 25599.394 J/hr HCO2

0.5 [(13.67 * (25-20)) + (0.11/2 * (25^2-20^2)) + (-1.21E-4/3 *

(25^3-20^3))] * (25-20) = 201.044 J/hr HH2S

72.5 [(26.39 * (25-20)) + (0.01/2 * (25^2-20^2)) + (-2.38E-5/3 *

(25^3-20^3))]*(25-20) = 48217.72 J/hr

HC1 9.5 [(7.56 * (25-20)) + (0.16/2 * (25^2-20^2)) + (-3.21E-5/3 *

(25^3-20^3))]*(25-20) = 2646.63 J/hr

HC2 9.9 [(-4.10 * (25-20)) + (0.30/2 * (25^2-20^2)) + (1.63E-4/3 *

(25^3-20^3))] * (25-20) = 676.38 J/hr

HC3 2.4 [(-2.48 * (25-20)) + (0.39/2 * (25^2-20^2)) + (-2.2E-4/3 *

(25^3-20^3))]*(25-20) = 384.41 J/hr

HiC4 2.5 [(-2.49 * (25-20)) + (0.36/2 * (25^2-20^2)) + (-2.13E-4/3 *

(25^3-20^3))] * (25-20) = 343.86 J/hr

HnC4 1.3 [(0.45 * (25-20)) + (0.45/2 * (25^2-20^2)) + (-1.75E-4/3 *

(25^3-20^3))] * (25-20) = 340.79 J/hr HnC5

0.1 [(34.51 * (25-20)) + (-0.01/2 * (25^2-20^2)) + (4.69E-5/3 *

(25^3-20^3))] * (25-20) = 85.77 J/hr

HH2O 25599.394 + 201.044 + 48217.72 + 2646.63 + 676.38 + 384.41 +

343.86 + 340.79 + 85.77 = 78495.998 J/hr

= 78.495998 KJ/hr

Total

HF

Tab. 2-7 HF Calculation

26

For stream (D)

Calculation of HD as follow:

Cp = a (T-TO) + 2b (T

2-TO

2) + 3

C (T3-TO

3)

HD = ∑( n * (Cp) *T)

0.026 [(17.46 * (20-25)) + (0.09/2 * (20^2-25^2)) + (-1.01E-4/3 *

(20^3-25^3))] * (20-25) = 12.632 J/hr HC O2

0.01 [(13.67 * (20-25)) + (0.11/2 * (20^2-25^2)) + (-1.21E-4/3 *

(20^3-25^3))] * (20-25) = 3.402 J/hr HH2S

1 .45 [(26.39 * (20-25)) + (0.1/2 * (20^2-25^2)) + (-2.38E-5/3 *

(20^3-25^3))] * (20-25) = 9758.1345 J/hr HC1

0.19 [(7.56 * (20-25)) + (0.16/2 * (20^2-25^2)) + (-3.21E-5/3 *

(20^3-25^3))] * (20-25) = 52.933 J/hr HC2

0.2484 [(-4.1 * (20-25)) + (0.3/2 * (20^2-25^2)) + (1.63E-4/3 *

(20^3-25^3))] * (20-25) = 16.772 J/hr

HC3

0.0602 [(-2.48 * (20-25)) + (0.39/2 * (20^2-25^2)) + (-2.2E-4/3 *

(20^3-25^3))] * (20-25) = 9.306 J/hr HiC4

0.0627 [(-2.48 * (20-25)) + (0.39/2 * (20^2-25^2)) + (-2.2E-4/3 *

(20^3-25^3))] * (20-25) = 9.692 J/hr HnC4

0.0326 [(0.45 * (20-25)) + (0.45/2 * (20^2-25^2)) + (-1.75E-4/3 *

(20^3-25^3))] * (20-25) = 8.5462 J/hr HnC5

0.0025 [(34.51 * (20-25)) + (-0.01/2 * (20^2-25^2)) + (4.69E-5/3 *

(20^3-25^3))] * (20-25) = 2.1443 J/hr HH2O

11.789 + 3.402 + 9758.1345 + 52.933 + 16.772 + 9.306 + 9.692 +

8.5462 + 2.1443 = 9872.719 J/hr

= 9.872719 KJ/hr

Total

HD

Tab. 2-8 HD Calculation

27

For stream (P)

Calculation of HP as follow:

Cp = a (T-TO) + 2b (T

2-TO

2) + 3

C (T3-TO

3)

Hp =∑( n * (Cp) *T)

69.469388 [(26.39 * (25-20)) + (0.01/2 * (25^2-20^2)) + (-2.38E-5/3 *

(25^3-20^3))] * (25-20) = 46202.183 J/hr

HC1

8.448979 [(7.56 * (25-20)) + (0.16/2 * (25^2-20^2)) + (-3.21E-5/3 *

(25^3-20^3))]*(25-20) = 2353.818 J/hr

HC2

15.959183 [(-4.1 * (25-20)) + (0.3/2 * (25^2-20^2)) + (1.63E-4/3 *

(25^3-20^3))] * (25-20) = 1090.355 J/hr

HC3+

46202.183 + 2353.818 + 1090.355 = 49646.356 J/hr

= 49.646356 kJ/hr

Total

Hp

Tab. 2-9 HP Calculation

For stream (M)

Calculation of HM as follow:

Cp = a (T-TO) + 2b (T

2-TO

2) + 3

C (T3-TO

3)

HM =∑( n * (Cp) *T)

1.274 [(17.46 * (25-20)) + (0.09/2 * (25^2-20^2)) + (-1.01E-5/3 *

(25^3-20^3))] * (25-20) = 6204.34 J/hr HCO2

0.49 [(13.67 * (25-20)) + (0.11/2 * (25^2-20^2)) + (-1.21E-5/3 *

(25^3-20^3))] * (25-20) = 1977.01 J/hr HH2S

1.470179 [(26.39 * (25-20)) + (0.01/2 * (25^2-20^2)) + (-2.38E-5/3 *

(25^3-20^3))] * (25-20) = 9777.76 J/hr HC1

0. 805804 [(7.56 * (25-20)) + (0.16/2 * (25^2-20^2)) + (-3.21E-5/3) *

(25^3-20^3))] * (25-20) = 2444.91 J/hr HC2

6204.34 + 1977.01+ 9777.76 + 2444.91 = 20404.02 J/hr

= 20.40402 kJ/hr Total HM

Tab. 2-10 HM Calculation

28

Output (KJ/hr) Input (KJ/hr) Streams

0 78.495998 F

49.646356 0 P

9.872719 0 D

20.40402 0 M

79.923095 78.495998 Total

Tab. 2-11 energy balance error Calculation

2.3. The energy balance error:

Error % = Output−Input

Output × 100 ………………………………………………………(2-12)

= 𝟕𝟗.𝟗𝟐𝟑𝟎𝟗𝟓 − 𝟕𝟖.𝟒𝟗𝟓𝟗𝟗𝟖

𝟕𝟗.𝟗𝟐𝟑𝟎𝟗𝟓 𝑋 100 = 0.017856 %

29

Chapter 3

3. Separator Unit Process Design

3.1. Principles of Separation:

Three principles used to achieve physical separation of gas and liquids or solids are

momentum, gravity settling, and coalescing.

Any separator may employ one or more of these principles, but the fluid phases must be

"immiscible" and have different densities for separation to occur.

3.2. Vertical Separator Parts:

Regardless of shape, separation vessels usually contain four major sections, [4]

The primary separation section, A, is used to separate the main portion of free liquid

in the inlet stream. It contains the inlet nozzle which may be tangential, or a diverter

baffle to take advantage of the inertial effects of centrifugal force or an abrupt

change of direction to separate the major portion of the liquid from the gas stream.

The secondary or gravity section, B, is designed to utilize the force of gravity to

enhance separation of entrained droplets. It consists of a portion of the vessel

through which the gas moves at a relatively low velocity with little turbulence. In

some designs, straightening vanes are used to reduce turbulence.

The coalescing section, C, utilizes a coalescer or mist extractor which can consist of

a series of vanes, a knitted wire mesh pad, or cyclonic passages. This section

removes the very small droplets of liquid from the gas by impingement on a surface

where they coalesce. A typical liquid carryover from the mist extractor is less than

0.013 ml per m3.

The sump or liquid collection section, D, acts as receiver for all liquid removed

from the gas in the primary, secondary, and coalescing sections. [3]

30

3.3. Gas-Liquid Separator Design

3.3.1. Specifying Separators

Separator designers need to know pressure, temperature, flow rates, and physical

properties of the streams as well as the degree of separation required. It is also prudent

to define if these conditions all occur at the same time or if there are only certain

combinations that can exist at any time. If known, the type and amount of liquid should

also be given, and whether it is mist, free liquid, or slugs. [4]

The following steps were used in mechanical design of the separator that to remove

about 2.082466 Kmol/hr of heavy hydrocarbons and water from the bottom to

condensate bit for tail process and select about 102.040816 Kmol/hr of free gas from

the top of the separator for next gas conditioning process. The total capacity of the

separator is 104.123282 Kmol/hr.

Fig. 3-1 Separator Cross Section View

Gas Inlet

Clean Out

Inspection

Vapor Outlet

Liquid Outlet

104.123282 Kmol/hr

102.040816 Kmol/hr

2.082466 Kmol/hr

98 % Conversion

31

3.4. Vertical separators

A vessel used to separate a mixed-phase stream into gas and liquid phases that are

"relatively" free of each other. Other terms used are scrubbers, knockouts, line drips, and

decanters. The layout and typical proportions of a vertical liquid gas separator are shown

below.

3.4.1. Basic Design Equations

Some typical values of the separator sizing factors, K and C,

See Appendix B (Typical K & C Factors)

The two most common are the critical velocity equation: [6]

𝑢𝑡 = 𝐾√𝜌𝑙− 𝜌𝑔

𝜌𝑔 = …………………………………………………………………(3-1)

Where, 𝑢𝑡 is settling velocity, m/s

𝜌𝑙 is liquid density, = 524.8 kg/m3 from (D) Separator Bottom Product ''Hysis Calculation''

𝜌𝑔 is vapor density, = 34.14 kg/m3 from (R) Separator Top Product ''Hysis Calculation''

𝑢𝑡 = 0.07 𝑚𝑠𝑒𝑐⁄ √

(524.8 𝐾𝑔

𝑚3⁄ − 34.14 𝐾𝑔

𝑚3⁄ )

34.14 𝐾𝑔

𝑚3⁄ = 0.2654 𝒎 𝒔𝒆𝒄⁄

Fig. 3-2 Gas-Liquid Separator Flow Diagram

The diameter of the vessel must be large enough to slow the gas down to below the velocity

at which the particles will settle out. So the minimum allowable diameter will be given by:

32

Where, 𝑢𝑡 = ( 𝑉𝑡

𝐴) = (

𝑉𝑡𝜋

4𝐷2

) = (4 𝑉𝑡

𝜋 𝐷2)

𝐷𝑠2 = (

4 𝑉𝑡

𝜋 𝑢𝑡) ………………………………………………………….…………..…….(3-2)

Then, 𝐷𝑠 = √(4 𝑉𝑡

𝜋 𝑢𝑡)

Where, Vt, gas volumetric flow rate (m3/sec) which is equal to;

Volumetric Flow Rate Appendix A Eq, 10-10 (p-461)

Streams Kmol/hr m3/sec

Mixture (W1) 104.123282 0.64773

Vapour (P) 102.040816 0.63492

Liquid (D) 2.082466 0.01296

Tab. 3-1 Volumetric Flow Rate

𝐷𝑠 = √4 (0.64773) 𝑚3

sec ⁄

𝜋 (0.2654)𝑚sec ⁄

= √3.10744 𝑚2 = 1. 7628 m outside diameter,

The height of the vessel outlet above the gas inlet should be sufficient to allow for

disengagement of the liquid drops. A height equal to the diameter of the vessel or 1 m,

whichever is the greatest, should be used. [11]

ℎ𝑣 = 𝐷𝑠 = 1.7628 𝑚

The liquid level will depend on the hold-up time necessary for smooth operation and

control; typically 10 minutes hold-up would be allowed.

Volume held in vessel = 0.01296 m3/sec * (10 min * 60 sec/min) = 7.776 m3

Liquid depth required, ℎ𝑙 =𝑉𝑜𝑙𝑢𝑚𝑒 ℎ𝑒𝑙𝑑−𝑢𝑝

𝑉𝑒𝑠𝑠𝑖𝑙𝑒 𝐶𝑟𝑜𝑠𝑠 𝑆𝑒𝑐𝑡𝑖𝑜𝑛𝑎𝑙 𝐴𝑟𝑒𝑎 ………………………………….(3-3)

ℎ𝑙 =𝟕. 𝟕𝟕𝟔 𝐦𝟑

𝜋 (0.8664)2 = 𝟑. 𝟐𝟗𝟕 𝒎

Increase to 0.3 m to allow space for positioning the level controller.

Liquid depth required, ℎ𝑙 = 3.297 m + 0.3 m = 3.597 m

The height of the vessel (L) = ℎ𝑙 + ℎ𝑣 ……………………………………….………..(3-4)

= 3.597 + 1.763 = 5.36 m

33

3.5. Thickness of the Shell:

To calculate the value for the thickness. The following equation ratio was estimated:

4𝐿

𝑑𝑜=

𝑑𝑜

𝑡 ………………………………………….…………………………………..(3-5)

𝑡ℎ𝑒𝑛, 𝑡 = (0.8664)2

4∗5.36 = 𝟎. 𝟎𝟏𝟐𝟑 𝐦 = 12.3 mm

To estimate the pressure, which the thickness assumed can be taken:

𝑃𝑎𝑙𝑙𝑜𝑤 =𝐵

𝑑𝑜 𝑡⁄ …………………………………………………………………..(3-6)

𝑾𝒉𝒆𝒓𝒆: 𝐵= 31000 𝑟𝑜𝑚 𝑡ℎ𝑒 𝑔𝑟𝑎𝑝ℎ 𝑃. 153 is a constant according to the material

of construction with the ratio which were tested at temperature of (158 ℃) in the

evaporator. The value of pressure allowed is close to atmospheric pressure, then

the assumed value of the thickness.

Inside diameter (d) = Outside diameter (do) - Thickness (t)

= 1.7628 – (2 * 0.0123) = 1.7382 m

Height of the separator (L) = 5.36 m

𝑃𝑙𝑙𝑜𝑤 =𝐵

𝑑𝑜 𝑡⁄ ………………………………………………...……………..(3-7)

= 31000

0.8664 0.0123⁄ = 𝟒𝟒𝟎 psig

3.6.Design for the A torispherical dished closure (cover)

The radius of dish (Radius of curvature) ''r''

r = do – 2t …………………………………………………………………………(3-8)

= 0.8664 – 2(0.0123) = 0.8418 m

Dish thickness at atmospheric pressure (tdish) = 𝑝∗ 𝑑𝑜

𝐵 …………………...……….(3-9)

= 14.7 ∗ 0.8664

31000 = 0.0123 m

Since the assumed corrosion thickness = 3 mm

So, the total thickness of dish = 4.1 mm + 3 mm = 7.1 mm

The minimum thickness of the shell constructed from stainless steel were the diameter of

shell is more than (1 m) is equal to (8 mm).

So, the thickness of (7.1 mm) should be taken as (8 mm), and for the allowance of pressure

choosing thickness of (10 mm).

34

Chapter 4

4. Instrumentation and Control

Instruments are provided to monitor the key process variables during plant operation. They

may be incorporated in automatic control loops, or used for 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.

It is desirable that the process variable to be monitored be measured directly; often,

however, this is impractical and some dependent variable, that is easier to measure, is

monitored in its place. For example, in the control of distillation columns the continuous,

on-line, analysis of the overhead product is desirable but difficult and expensive to achieve

reliably, so temperature is often monitored as an indication of composition. The

temperature instrument may form part of a control loop controlling, say, reflex flow; with

the composition of the overheads checked frequently by sampling and laboratory analysis.

4.1 Instrumentation and control objectives

The primary objectives of the designer when specifying instrumentation and control

schemes are: [17]

4.2 Safe plant operation:

a) To keep the process variables within known safe operating limits.

b) To detect dangerous situations as they develop and to provide alarms and

automatic shut-down systems.

c) To provide interlocks and alarms to prevent dangerous operating

procedures.

4.3 Production rate:

To achieve the design product output, the material balance shows the up and down

streams rate for on-spike quality production.

35

4.4 Product quality:

To maintain the product composition within the specified quality standards either in the top

product of separator in stream (R) that handling about 102.040816 Kmol/hr which equal to

2286 m3/hr as gas free of heavy hydrocarbons and water to get high heat value and also,

this quantity of gas entering the membrane technology system to remove the impurities of

acid gases, deferential pressure will control and monitoring the activity of the membrane,

where it is reduced by increasing the delta P across the separator. [16]

4.5 Typical control systems

Identify and draw in those control loops that are obviously needed for steady plant

operation, such as:

a) Level control System

In any equipment where an interface exists between two phases (e.g. liquid-vapour),

some means of maintaining the interface at the required level must be provided.

This may be incorporated in the design of the equipment, as is usually done for

decanters or by automatic control of the flow from the equipment.

We have fixed level control transmitter to control the liquid level in the

bottom of the separator and there are both signals, one of them for high level

connected with high level alarm and the other for low level and low level

alarm connected too.

In case of high the control valve LCV on the discharge pump will open to

maintain the level in the separator and close in low level case to keep enough

amount of liquid in the separator to prevent gas passing from the bottom and

working as sealing in the bottom.

b) Pressure Ccontrol System

Pressure control will be necessary for most systems handling vapor or gas. The

method of control will depend on the nature of the process. The transmitter fixed in

the top of the separator to control the pressure of the vessel, (PCV) is open due the

high pressure signal from the transmitter to maintain the pressure at certain setting

of operating condition and the PCV is close immediately as soon as the pressure

drop down. Also, there are two safety valves fixed on the top of the separator to

36

release any sudden increase in pressure above the set point to prevent damage in the

vessel and recycle the excess gas released to the suction of compressor or to the

flare header.

c) Temperature control System

The temperature controlled by varying the flow of the cooling or heating

medium. So, in our process sea water (S/W) is used as cooling media, it is

control by TCV on the S/W downstream of the gas cooler. [25]

If the temperature of process gas indicated increase the transmitter send

signal to the TCV to open and pass more cooling water to reduce the

temperature to the normal setting on the other hand the TCV close to reduce

the water flow and increase the process gas temperature.

Fig. 4.1 common control system

Stream D

Level Control Valve

LCV

Pressure Control Valve PCV

Liquid Out

Stream R

Sep

arat

or

Cooler

Temperature Control Valve

TCV

Stream W1

S/W In

S/W Out

37

d) Flow Control

Flow control is usually associated with inventory control in a storage tank or other

equipment. There must be a reservoir to take up the changes in flow-rate. To provide flow

control on a compressor or pump running at a fixed speed and supplying a near constant

volume output, a by-pass control would be used,

120

8To FUEL GAS

SYSTEM

120I-61

FIC

102

FCV

Fig. 4-2 Flow Control Valve

In our fuel conditioning study flow control valve stablished on the product line to control

the flow rate to the storage tank or to the fuel system, FCV take the signal from the prior

orifice plate and keep the flow within the product required rate.

38

Chapter 5

5. Cost Estimation

5.1.Economic Assumptions and methodology

The capital and operating costs are estimated for the Benfield High Pure process and its

alternatives within the operating and economic environments .The total capital cost

includes all key process equipment shown in the process flow diagrams, plus a general

facilities cost. The design parameters of equipment like absorber columns, flash vessels and

pumps are obtained from the plant design data sheets. The rest of the equipment is sized in

to provide information on equipment’s costs as required by the calculations. The operating

cost includes fixed general maintenance costs comprising labor, local taxes and general

insurance. The process operating expenses are estimated through the unit cost of utilities

and consumables with reference to the techno-economic performance parameters. To

enable complete investigation of the process, information on both equipment and operating

cost is obtained from a number of sources including vendor and public sources. The

assumptions used in carrying out the economic analysis and evaluation are given in table

below. Economic gains for the existing process and its alternatives are compared using the

economic potential and net present value/worth.

For Overview of the Economic Assumptions, See Appendix (B) Tab. 5-1

5.2.Capital Costs

The total capital expense (CAPEX) is divided into two main components:

i) The fixed capital investment.

ii) The working capital investment. All the cost estimates are represented in constant

million US dollars using the 2000 cost. ''Index (B). Tab. 5.1'' gives the cost factors used to

estimate all the costs involved in the construction of the plant basing on the purchase cost

for each individual equipment. ''index (B) Tab. 5.2'' gives an overview of the equipment

cost estimates for the Benfield High Pure process in million US dollars (M$).

The most expensive equipment’s are the absorber and the regenerator, which are

responsible for about 45% of the fixed cost on investment.

39

Cost factors for the effects of material of construction, temperature and pressure are also

included in the capital cost estimation of the equipment. Equipment such as valves, steam

jet ejectors and pipes were neglected in this study. As shown in Tab. 5.2 Typical factors for

capital cost based on delivered equipment. [26]

5.3.Operating costs

The total operating expense (OPEX) is divided into five sections:

i) The charges.

ii) Direct production costs.

iii) Plant overhead costs.

iv) General expenses.

v) Utility costs.

Tab. 5.3 Appendix (B) gives an overview of these expenses in million US dollars (M$). 40%

of the operating costs is for the direct production costs and only 11% is spent on utilities

basically steam and electricity.

Tab. 5.3 : Typical Overview of Annual Expenditure. ''Index (B)

5.4.The cost of some project equipment :

Equipment No Discription Cost in

2015 $

Cost in

2019 $

Risk

Fact.

30%

Site Net

Cost $

Compressor 1 Multistag Compressor $350,563.00 515,327.00 1.3 696,925.00

Cooler 1 Water – Gas Cooler $88,440.00 130007.00 1.3 169,009.00

Separator 1 Gas - Liquid Separator 65,286.00 95,970.00 1.3 124,761.00

Membrane 1 73,193.00 107,593.00 1.3 139,871.00

Stripper 1 Gas Recovery 61,248.00 90,035.00 1.3 117,045.00

Total 1,247,611.00

Tab. 5.1 cost of project

40

Chapter 6

Safety

6.1. Natural gas

Natural gas is produced from our field and according to its hydrogen sulphide content is

considered either (below 0.5 vol% H2S) or gas (above 0.5 vol.% H2S).

Natural gas typically contains about 70-80% methane (CH4) with some Ethane (C2H6)

propane (C3H8) and Carbon dioxide (CO2) as impurities.

After purification it is colourless odourless non corrosive and lighter than air. As the

purified gas cannot be smelled a trace of a standard strongly smelling substance

(Mecaptan) is added to help detect any gas leaks.

6.2. Types of Protection Equipment

6.2.1. Work Clothing

Work clothing must be suitable for protection. Against common hazards expected

for industrial areas in .General.

Work clothing should be kept as clean as possible. If splashed with Oil or a chemical, it

must be removed as soon as possible. Any Affected part of the body must be washed

with soap and water, and then clean clothing put on. Any con tac t wi th an

Aggres s ive c h e m i ca l , m u s t b e r e p o r t e d t o Supervision Immediately. The

above rules represent the normal minimal requirements. Where necessary,

additional personal protective clothing and Equipment specified by the Company must' be

worn by employees. Exceptions from the above rules which are justified by the nature of

work or Special environment may be permitted if approved by the Superintendent, Safety

& Fire Protection or his substitute. Insulated clothing may be required for work

assignments involving Temperature extremes, such as welding, the handling of

cryogenic liquids, Working in food cold storage facilities etc. [8]

41

6.2.2. Head Protection

An approved hard hat consists of a hard impact shell and an adjustable inside cradle'

arid distributed over the head 'surface area. Wearing of safety hard hats (helmets) is

mandatory for:

All employees who Work in industrial area.

Work on a construction site.

work in a hard-hat use designated area, and

In any situation where a hazard exists for head injury from a falling object or

bumping against overhead structure or objects.

6.2.2.1. HARD HAT

Exceptions are the situations where normally no hazard exists for a head injury, such

as working in offices, control rooms, classrooms, etc. A hardhat shell is known to lose

its protection value with t ime .

Fig. 6-1 indicate Hard Hat helmet

6.2.3. Face Protection

6.2.3.1. Face Shield

Provides protection from a corrosive or a hot liquid splash, and from small flying

particles. It is not a substitute for eye protection,' and must be used in addition to

wearing safety glasses or chemical goggles. (Example shown below) [8]

6.2.3.2. Acid Suit

Protects face and head from a splash or .mist o corrosive Liquid. Situations which

require use of a hood 'usually also require protection of the body by an acid or

chemical suit.

42

Fig. 6.2 Full-Face Splash Shield

6.2.3.3. Eye Protection

Appropriate eye protection is required in these situations

Where exposure to flying particles may exist.

Where exposure to corrosive liquids exists.

When disjointing equipment that could be under pressure.

When specified on- Work Permit, or by a Supervisor.

6.3. Types of Eye Protection Equipment:

1. Ordinary safety glasses - These have plain (non-prescription shatter proof

glass inside safety frames and must also have attached side shields. They

provide frontal protection from flying particles or a liquid splash. Protection is

satisfactory for many activities where the hazard is moderate. [27]

2. Green lens safety glasses - With side shields they provide protection

from glare and sunshine. Special dark-green glasses can also be obtained and

are used in some welding applications.

3. Chemical safety goggles protects your eyes from liquid splashes, mists or

corrosive chemicals.

4. A face shield is used in addition to eye protection in hazardous.

In an industrial environment there are many situations in which some hazards cannot

be practically eliminated. In such cases employees are requested to use personal

43

The basic minimum required with regard to personal protection for

working in any industrial area consists of the following

Hard hat

Work gloves

Safety shoes or boots

Safety glasses or goggles

Hearing protection

44

Chapter 7

Case Study

7.Hatieba Gas as fuel to the company power stations:

7.1. Abstract

Hatieba gas plant is the main supplier of gas to the 30" pipeline containing high CO2, and

low of H2S. The gas travels from Hatieba and joins the original 30" pipeline at Km-81.5,

here the pipeline is blanked. The section back to Zelten is used for storage purposes. Also at

km-81.5 are spillover facilities allowing gas from Sahel & Assmoud fields to be used in

making up any gas shortfall. Due to the containing of huge amount of water and heavy

hydrocarbon condensate caring with Hatieba gas in 30 '' pipeline to Brega facilities,

separation process should be done for this type of gas especially during winter season.

Hatieba gas supply only both Ammonia plants (I and II) and Methanol plant (I) as process

and fuel gas.

Within these days, there is a proposal to supply Sitre Oil Company power stations (I and II)

by Hatieba gas as alternative source in presence of any shortage in the existing sources,

but the power plants generators don't matching with the gas composition without

conditioning.

So, establish of Knockout vertical drum separator and membrane technology for

conditioning Hatieba gas is very important to keep the power plants away of blackout.

Key Words; Hatieba gas, Facilities, membrane Technology.

7.2.Introduction.

The case study of using Hatieba gas as power plants fuel gas is to be collecting data for the

composition of gas and try to comparative in between with gas transmission gas that

existing supply to the power plants where, Hatieba gas is deferent, and need to more

separation and conditioning to remove the high content of CO2.

45

The pipeline enters the slugcatcher area of the L.N.G. plant. Here there is a 30" sphere

receiver which is unused at the present time. The gas flow "T"s off through the valve LBV-

1355, which can be closed automatically, or remotely from the DCS, and opened/closed

locally.

The vessel is drained to the area burn pit, through a manual operated control valve. The gas

leaves V-360 from the top and passes to supplying gas to the Gas Plant fuel system (as

required). [11]

30" G

AS P

IPEL

INE

DIST

RIBU

TION

@ S

LUG

CATC

HER

AREA

20" H

EADE

R FR

OM

MOV

-375

A/B

16"

20"

FROM

FICV

-303

FROM

FICV

-302

36" B

SPI

LLOV

ER G

AS

AMM

-1 /

MET

H-1

& PO

WER

PLA

NT

AMM

-2 /

MET

H-2

MOV

-375

B

MOV-375

B

(OPERATE

FROM D

CS/LOCAL)

375ATR 375BTR

375APR 375BPR

FR-3

75A

FR-3

75B

20" H

EADER TO P

.C. P

LANTS

20"

16" F

UEL

SYST

EM

SUPP

LY H

EADE

R

36"B

PIP

ELINE G

AS

TO F

UEL

SUPPLY H

EADER

PILO

T GA

S TO

BURN

PIT

V - 360

M

OV-3

65(O

PERA

TE L

OCAL

ONL

Y)

LCV-

360

TO B

URN

PIT

(OPE

RATE

LOC

AL O

NLY)

MOV

-826

(CLO

SE F

ROM

DCS

,

OPEN

ON

RESE

T)

LBV-

1355

(CLO

SE F

ROM

DCS

,

OPEN

/CLO

SE L

OCAL

)

16" B

YPAS

S

LBV-

1355

/ M

OV-8

25

30" G

AS T

O G.

T.S.

(34"

)

MOV

-825

(CLO

SE F

ROM

DCS

,

OPEN

ON

RESE

T)

RBB-

338

(CLO

SE F

ROM

DCS

,

OPEN

/CLO

SE L

OCAL

)

30" S

PHER

E

RECE

IVER

MOV

-135

0/13

51

MOV

-135

2

Fig. 7.1 30 '' Hatieba gas pipeline distribution

46

7.3. Hatieba gas analysis:

Fig. 7.2 30 '' Hatieba gas pipeline Analysis

47

Fig. 7.3 Gas – Liquids Separation Connections

48

Fig. 7.4 30 '' Hatieba gas Properties

49

Energy content or calorific value is the same as the heat of combustion, and can

be calculated from thermodynamicc values, or measured in a suitable apparatus:

A known amount of the fuel is burned at constant pressure and under standard

conditions (0°C and 1 bar) and the heat released is captured in a known mass of water in a

calorimeter. If the initial and final temperatures of the water are measured, the energy

released can be calculated using the equation. [27]

H = ΔT mCp …………………………………………………………………………….(7-1)

where H = heat energy absorbed (in J), ΔT = change in temperature (in °C), m = mass of

water (in g), and Cp = specific heat capacity (4.18 J/g°C for water). The resulting energy

value divided by grams of fuel burned gives the energy content (in J/g).

The combustion process generates water vapor and certain techniques may be used to

recover the quantity of heat contained in this water vapor by condensing it.

Higher Calorific Value (= Gross Calorific Value - GCV = Higher Heating Value -

HHV) - the water of combustion is entirely condensed and the heat contained in the

water vapor is recovered

Lower Calorific Value (= Net Calorific Value - NCV = Lower Heating Value -

LHV) - the products of combustion contains the water vapor and the heat in the

water vapor is not recovered

The table below gives the gross and net heating value of fuels gas as well as some

alternative fuels. [4]

Fuel

Density Higher Heating Value (HHV)

(Gross Calorific Value - GCV)

Lower Heating Value (LHV)

(Net Calorific Value - NCV) @32°F, 1bar

Gaseous

fuels [kg/m

3] [MJ/kg] [MJ/m

3] [MJ/kg] [MJ/m

3]

Nat. gas 0.777 52.2 40.6 47.1 36.6

[kg/lit] [MJ/kg] [MJ/l] [MJ/kg] [MJ/l]

LPG* 0.537 49.3 26.5 45.5 24.4

Tab. 7.1 Gross and net heating value

https://www.engineeringtoolbox.com/standard-heat-of-combustion-energy-content-d_1987.html

https://www.engineeringtoolbox.com/stp-standard-ntp-normal-air-d_772.html

https://www.engineeringtoolbox.com/stp-standard-ntp-normal-air-d_772.html

https://www.engineeringtoolbox.com/gross-net-heating-value-d_824.html

50

7.4. Conclusion:

The problem with using directly produced natural gas from Hatieba as fuel is that,

typically, it is very rich, or abundant in heavier hydrocarbons.

The cleaning fuel meaning fuel consist of lighter hydrocarbons such as methane and ethane

which give more heat value than the heavier fuel gas.

The power station burners designed for use lighter hydrocarbons didn't matching with fuel

containing water and heavy hydrocarbons and machine trip may cause due to condensing

small amount of heavy hydrocarbon in the burners.

Fuels which consist of a mixture of several different compounds may vary in quality

between seasons and markets. The given values are for fuels with the given density. The

variation in quality may give heating values within a range 5 -10 % higher and lower than

the given value.

7.5. Recommendation:

1) Established of vertical separator to make sure remove the condensing heavy

hydrocarbons.

2) The feed of fuel gas should be heated before interring the burning system to avoid

condensation during winter season.

3) Hatieba feed gas to the power station should conditioning by new technology of

membrane osmometric system to remove the traces amount of corrosive acidic

gasses such as CO2 and H2S.

51

Chapter 8

8.1. Plant Layout:

The philosophy and strategy of plant layout required to determine the equipment locations

in the yard of plant and how they distributed according to their functions.

Main gate is used to employee and small car entrance while the Truck entrance is for

maintenance and emergency escape at any emergence case.

Flaring unit should far away of the plant equipment at least at the end of the corner fence

while the control room, car barking and offices are near the main gate and also, the fire

fitting unit is in the generator house.

The fuel gas line brake valve is in the first equipment at entering point to the plant yard and

the next facilities combine in one skid.

Exhausting stack should be outside the power generator house.

Power Generator House

Compresor

SeparatorCooler

Car Barking

Control Room

Inlet Valve

Membrane

Stripper Condy. Bit

Exaust S

tack

Truck Entrance

Main Gait

Fire

Fighting

House

Tra

nsfo

rm

er

Fla

ring

Unit

Fig. 8.1 Power Station Plant Suppling with Natural Conditioning Gas

52

APPINDIX A

(Kmol/hr * 1000 mol/Kmol * 22.4 lit/mol * m3/1000 lit* hr/3600 sec)

Volume flow rate (Tab. 3-2) Page-23

Chapter 5 Symbol Nomenclature

symbol Nomenclature

TI Temperature indicator

TIRC Temperature indicator

recorder controller FC Flow controller

FRC Flow recorder Controller

FI Flow indicator

PI Pressure indicator

PC Pressure controller

XC Ratio controller

FR Flow recorder

LIR Level indicator recorder

PRC Pressure recorder controller

CI Composition indicator

LA Level alarm

PA Pressure alarm

53

K Values in light hydrocarbon system, high temperature range.

54

K Values in light hydrocarbon system, low temperature range.

55

Appendix B

Separator Type

K Factor

(m/s)

C Factor

(m/h)

Horizontal 0.12 to 0.15 430 to 540

Vertical 0.05 to 0.11 200 to 400

Spherical 0.05 to 0.11 220 to 400

Wet Steam 0.076 270

Most vapors under vacuum 0.061 220

Salt & Caustic Evaporators 0.046 160

Atmospheric 100

1000 kPa 90

2000 kPa 85

4000 kPa 80

8000 kPa 75

Typical K & C Factors

Heat Capacity Constants

Heat capacity constants

components a b c

C1 26.39 0.01 -2.38E-05

C2 7.56 0.16 -3.21E-05

C3 -4.1 0.3 1.63E-04

C4 -2.48 0.39 -2.20E-04

C5 0.45 0.45 -1.75E-04

H2O 34.51 -0.01 4.69E-05

CO2 17.46 0.09 -1.01E-04

H2S 13.67 0.11 -1.21E-04

56

Tab. 5-1 Economic Assumptions

Item 20

Factors

Direct Cost

Equipment delivered 1

Equipment Erecting 0.4

Piping 0.7

Instrumentation and Control 0.2

Electrical 0.1

Utilities 0.5

Off-sites 0.2

Building 0.2

Site Preparation 0.1

Total Capital Cost of Installed Equipment 3.4

Indirect Cost

Design Engineering & Construction 1

Contingency 0.4

Total Fixed Capital Cost 5.8

Tab. 5-2 Typical factors for capital cost based on delivered equipment

Economic Assumptions

Project (yrs.) 22.0

Equipment Salvage Value 0.0

Construction Period (yrs.) 3.0

Plant operating time (hr/yr.) 7920.0

Interest rate (%) 5.0

Row material Cost ($/kg) 3.0

Chemical Cost ($/kg) 3.8

Renewal Cost ($/kg) 2.6

DGA cost ($/kg) 4.06

DIPA cost ($/kg) 3.0

Natural gas Price ($/MMBTU) 3.5

Tax rate (%) 20.0

57

Range Used Value Cost(M$/yr)

Fixed Charge a 10-20% OPEX 20 8.99

Local Taxes a 1-10% FCI 9 1.18

Insurance a 0.2-1% FCI 1 0.12

Direct Production Cost

Raw Material a 10-60% OPEX 10 4.50

Operating Labor(OL) a 10-20% OPEX 20 8.99

Activated Carbone Filter b 0.08

Maintenance & Repairs (M) a 7-11% FCI 8 0.95

Supervision & Clerical Assistance(S) a 15% of OL 15 1.35

Operating Suppliers a 15% M 15 0.14

Laboratory Charges a 10-20 % OL 20 0.27

Patents & Royalties a 0-6%OPEX 3 1.35

Plant Overhead Cost 50-

70%(M+OL+S)

60 6.05

General Expenses

Administrative Cost a 2-5%OPEX 5 2.25

Distribution & Marketing a 2-20%OPEX 2 0.90

R&D cost a 1-5%OPEX 1 0.45

Utilities

Steam b 4.40$/1000

kg

4.25

Electricity b

0.0245$/KW

.hr

0.69

Total Operating Cost (OPEX) 45.27

Tab. 5-3 Typical Overview of Annual Expenditure on the Benfield High Pure Process

58

Tab. 5.4 Cost of some project equipment

№ of Pressure

quantity (PSI) € $

1 Heat Exchanger 2 Shell/tube, fixed/U, large Carbon steel 300 249,981 217,484

2 Compressor 1

Centrifugal,

1334(KW) Carbon steel 1000 249,981 217,484

3 Filter 1 Cartrige

Alluminium

56.205(m2) 249,981 217,484

4 Cooling and Refrigeration 2 Cooling pond Carbon steel 4930(kW/hr) 249,981 217,484

5 Centrifugal pump 1 Horizontal1 stag hor. Spilt (Packing)Cast iron ; API610 249,981 217,484

6 Separator 1 Cyclone, wet, NiHard lined, medium0.3(m) Carbon steel 249,981 217,484

Total Equipment Cost 1,499,886 1,304,904

Cost Equepment Type Material

59

References:

[1] Membrane Technology: A method of gas separation by Skylar Addicks

[2] Kaaeid A.Lokhandwala and Marc L.Jacobs,Membrane Technology &

Research,Inc.,USA,discuss the use of membrane technology for conditioning fuel gas

for use in gas engines and turbines in the natural gas industry.

[3] Alvarado, Dean, and Douglas E. Gottschlich. "Membrane Matrimony." Hydrocarbon

[4] Wines T H (2000 January) ‘Improve liquid/gas coalescer performance’, Hydrocarbon

processing p.89-96.

[5] Bloch H P (2000 August) ‘Solve your hydrocracker compressor problems’,

Hydrocarbon Processing p.39-42.

[6] Coulson & Richardson's Chemical Engineering. Vol. 6, Chemical Engineering Design,

4th Ed.

[7] Chemical Engineering, Volume 1, Fluid Flow, Heat Transfer and Mass Transfer

(Coulson & Richardson)01

[8] Perry R H and Green D W (1997) Perry’s Chemical Engineers’ Handbook, Seventh

Edition, Chapter 14, p.95-98, McGraw-Hill Book Company, New York.

[9] Phillips H W (2000 September) ‘Select the Proper Gas Cleaning Equipment’, Chemical

Engineering Progress p.19-38.

[10] Ludwig E E (1995) Applied Process Design for Chemical and Petrochemical Plants,

Gulf Publishing Company, Houston.Volume 1, Chapter 4, ‘Mechanical Separations’.

[11] Brown R L and Wines T H (1993 December) ‘Improve suspended water removal from

fuels’, Hydrocarbon Processing p.95-100.

[12] Katona A, Darde T and Wines T H (2001 August) ‘Improve haze removal for FCC

gasoline’, Hydrocarbon Processing p.103-108.

[13] Snow R H and Allen T (1992 May) ‘Effectively Measure Particle-Size-Classifier

Performance’, Chemical Engineering Progress p.29-33.

60

.[14] Klumpar I V (1992 April) ‘Control and Scale-up Air Classifiers’, Chemical

Engineering Progress p.50-55.

[15] Hixon L (1992 July) ‘Sizing Up Air Classifiers’, Chemical Engineering Progress p.59-

62.

[16] Crawley G, Malcolmson A, Crosley I and McLeish A (2002 April) ‘Particle

Classification: Making the Grade’, Chemical Engineering p.54-60.

[17] Phillips H W (2000 September) ‘Select the Proper Gas Cleaning Equipment’,

Chemical Engineering Progress p.19-38.

[18] Christian J B (1994 July) ‘Improve Clarifier and Thickener Design and Operation’,

Chemical Engineering Progress p.50-56.

[19] Belhateche D H (1995 August) ‘Choose Appropriate Wastewater Treatment

Technologies’, Chemical Engineering Progress p.32-49.

[20] Zinkus G A, Byers W D and Doerr W W (1998 May) ‘Identify Appropriate Water

Reclamation Technologies’, Chemical Engineering Progress p.19-31.

[21] Hairston D (2002 May) ‘Combing Oil from T.Sands, Ch. Eng p.27- 31.

[22] Gomez J V (1992 April) ‘Correlations Ease Hydrocyclone Selection Part 1’,

Chemical Eng ineering p.167-8; (1992 May) p.161-163.

[23] Salcudean M, Gartshore I and Statie E C (2003 April) ‘Test Hydrocyclones Before

They Are Built’, Chemical Engineering p.66-71.

[24] Engineering (2005): n. pag. Membrane Technology and Research Inc. Web.

[25] MTR_Brochure_FGC

[26] Membranes for fuel gas conditioning

[27] www.IFSolutions.com

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