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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
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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.
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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.
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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
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Vertical SEPARATOR
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Horizontal SEPARATOR
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Horizontal 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
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QUIZZ 5
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• Water Vapor Content
of Natural Gas
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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
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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
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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
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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
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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
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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
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