Chapter 7 Natural Gas Processing

8/9/2019 Chapter 7 Natural Gas Processing

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NATURAL GAS ENGINEERING

CHAPTER 7 NATURAL GAS PROCESSING

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CONTENTS

1 Introduction

2 Dehydration

3 Sweetening

4 LNG,CNG,LPG

2



INTRODUCTION

Gas contracts usually contain the following basic considerations:

• Minimum, maximum delivery pressure

• Minimum heating value

• Composition

• Water content

• Maximum condensable hydrocarbon content or hydrocarbon

dew point• Contaminants such as H2S, CO2, mercury etc.

3



PROCESSING

Field processing of Natural Gas consists of 4 basic processes

1. Separation of gas from free liquids such as crude oil,condensate, water and entrained solids

2. Processing the gas to remove condensable and

recoverable hydrocarbon vapour

3. Processing the gas to remove water vapour whichmight cause hydrate formation

4. Processing the gas to remove H2S and CO2

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WATER CONTENT

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• Water and hydrocarbons are natural companions.

Hydrocarbons are formed in a water environment and are in

equilibrium with water at reservoir condition

• If both liquid water and hydrocarbons are present in a

system there will be two liquid phases.

• The water content of a gas is a function of

- pressure,

- temperature,- composition, and the

- salt content of the free water.



SEPARATION

Separators are used for separation process at following

locations:

1. Well head production batteries

2. Gasoline plant

3. Upstream and downstream of compressors

4. Liquid traps in gas transmission lines

5. Gas sweetening units

6. Inlet scrubbers to dehydration units

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• A properly designed separator perform the followingfunctions:

1. Primary separation of liquid from gas2. Removing liquid mist from the gas

3. Removing entrained gas from liquid

4. Discharge separated gas and liquid from the vessel

SEPARATION

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TYPES OF SEPARATORS

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• Mainly 3 types of separator

1. Vertical separator

2. Horizontal separator

-horizontal single tube-horizontal double tube

3. Spherical separator



Vertical SEPARATOR

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Horizontal SEPARATOR

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Horizontal Dual Tube SEPARATOR

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Factors Affecting Separation

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1. Separator operating Pressure

2. Separator Operating Temperature

3. Fluid Composition

Changes in any one of these factors will

change the amount of gas and liquid leaving theseparator.



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DEHYDRATION

Gas producing of a reservoir contains more water vapor than

oil producing reservoir.Water vapor is undesirable impurity found in untreated

natural gas.

Reasons for removing of water vapor from natural gas for

long distance transmission include the following:

1. Liquid water and natural gas can form solids, ice-like

hydrates that can plug pipeline and equipment.

2. Natural gas containing liquid water is corrosive.

3. Water vapor decreases the heating value of natural gas



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Typical Oil and Gas Reservoir



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Water Vapor Content

All natural gases contain water vapor to some

degree.

Solubility of water increases as temperature increases.

Solubility of water decreases as pressure increases.

Water content is expressed as lbm of water per million

standard cubic feet (lbm/MMSCFD).

Typical values of water content forReservoir Gas(5000psia/250 F)=500 lbm/MMSCF

Trap Gas(500psia/125F)=400 lbm/MMSCF

Pipeline Gas=6-8 lbm/MMSCF



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DEHYDRATION

The term Dehydration means removal of watervapor.

Water content of natural gas is indirectly indicated

by Dew Point.

Dew point is defined as the temperature at which

natural gas is saturated with water vapor at a given

pressure.

QUIZZ 5



QUIZZ 5

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• Water Vapor Content

of Natural Gas



HYDRATE FORMATION

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• Natural Gas Hydrates are solid crystalline compounds

formed by the chemical combination of natural gas and water

under pressure and temperature considerably above thefreezing point of water.

• In the presence of free water, hydrates will form when the

temperature is below a certain degree ( hydrate temperature).

• The chemical formula for natural gas hydrates are:

• Methane(C1) = CH4.7H2O

• Ethane(C2) = C2H6.8H2O

• Propane(C3) = C3H8.18H2O

• Carbon Dioxide = CO2.7H2O

HYDRATE FORMATION



HYDRATE FORMATION

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The conditions that tend to promote the formation of

natural gas hydrates are:

1. Natural is at below dew point temperature

2. High operating pressures

3. High velocity of gas flow through piping or equipment

4. Presence of H2S or CO2 is conducive to hydrateformation since these acid gas are more soluble in water than

hydrocarbons



Pressure Temperature Curves for predicting Hydrate Formation

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PREVENTING HYDRATE FORMATION

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To prevent hydrates from forming, the following methods can

be used:

1. Keep the gas above the hydrate temperature.

2. Remove the water from the gas so that free water will notcondense out.

3. Add chemicals to the gas to combine with the water. The

chemicals mostly used are methanol, glycols and sometimesammonia. Glycols are generally used for continuous processes

while methanol is used for emergencies.



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Gas sweetening

G S



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•

Hydrogen sulfide, carbon dioxide, mercaptans andother contaminants are often found in natural gas

streams.

• H2S is a highly toxic gas that is corrosive to carbon

steels.• CO2 is also corrosive to equipment and reduces the

Btu value of gas.

•

Gas sweetening processes remove thesecontaminants so the gas is marketable and suitable

for transportation

Gas Sweetening

G S i



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• Heating Value increased

• Avoid corrosion in transportation and distribution

• Avoid air pollution caused by SO2 as a result of H2S

combustion

Gas Sweetening

G S t i



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Processes:

– Amine Process

– Carbonate Process

– Cryogenic Distillation

– Membrane Process

Gas Sweetening

G S t i



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• Amine treating is a proven technology that

removes H2S and CO2 from natural gas and

hydrocarbon liquid streams through absorption and

chemical reaction.

• Amine treating is one of the most widely used and

cost-effective methods of removing hydrogen sulfide

and carbon dioxide from hydrocarbon streams.

Gas Sweetening



T i l ti f LNG



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LNG is simply natural gas that has been cooled to its liquid

state at atmospheric pressure: - 162.2°C and 14.7 psia

LNG is transported at ambient pressures.

Liquefying natural gas, which reduces the gas into a practical

size for transportation and storage, reduces the volume that

the gas occupies more than 600 times

Typical properties of LNG

T i l ti f LNG



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LNG is considered a flammable liquid

LNG vapor is colorless, odorless, and non-toxic

LNG vapor typically appears as a visible white cloud, because

its cold temperature condenses water vapor present in theatmosphere.

The lower and upper flammability limits of methane are 5.5%

and 14% by volume at a temperature of 25°C

Typical properties of LNG



H ti V l



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Heating Values

LNG P S h



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LNG Process Scheme

C G



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COMPRESSED

NATURAL GAS

CNG

CNG

CNG



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CNG

CNG is made by compressing natural gas (which is mainlycomposed of methane [CH4]), to less than 1% of the volume it

occupies at standard atmospheric pressure.

It is stored and distributed in hard containers at a pressureof (2900 –3600 psi), usually in cylindrical or spherical shapes.

T h i l A t i



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Technical Aspect comparison

.

1. Compressed Natural Gas(CNG):

1. Pressurized gas

2. 900-3600 psig

3. Temperature -30°C to 45°C

2. Liquefied Natural Gas(LNG):

1. Cryogenic liquid

2. 18.325 psig3. -160°C



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Liquefied Petroleum Gas(LPG)

LPG



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. LPG is composed primarily of propane (C3H8) and butane

(C4H10), while natural gas is composed of methane (CH4)

and ethane (C2H6).

LPG is a flammable mixture of hydrocarbon gas used as a

fuel in heating appliances and vehicles.

LPG is used for cooking in many countries for economic

reasons as well as for convenience.

Volume ratio of LPG to gas is typically 250:1.

LPG

LPG



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. The pressure at which LPG becomes liquid, calledits vapor pressure, likewise varies depending on

composition and temperature;

For example, it is approximately 32 psi for pure

butane at 68 °F, and approximately 320 psi for pure

propane at 131 °F.

LPG is heavier than air unlike natural gas.

LPG



THANK YOU

Chapter 7 Natural Gas Processing

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