EPE_course_presentation_001.ppt

Eng.Said Elsayed
Elementary process engineering

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PRIVATE AND CONFIDENTIAL ©
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Elementary Process Engineering
Eng.Said Elsayed
Course Overview
1. Introduction
3. Basics of Oil Refining process
2. Fundamentals of gas processing
4. Towers internals
7. Tanks & Valves
8. Pumps
9. Heat Exchangers & Fired
Heaters
5. Conversion & Rearrangement
processes
6. Safety in refinery
10. Compressors

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Eng.Said Elsayed
Course Overview
1. Introduction
3. Basics of Oil Refining process
2. Fundamentals of gas processing
4. Towers internals
7. Tanks & Valves
8. Pumps
9. Heat Exchangers & Fired
Heaters
5. Conversion & Rearrangement
processes
6. Safety in refining
10. Compressors

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Eng.Said Elsayed
Session 1 : Introduction
Petroleum is composed of two
elements,
Hydrogen and Carbon
Joined together in compound called
hydrocarbons.
Two simple ways of looking at these
hydrocarbons is by:
Ratio. and
Weight.
Petroleum

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These impurities include:
 Sulfur (0- 3 lb),
 Nitrogen (0-1 lb),
 Oxygen (0- 0.5 lb),
 Chlorine,
 Nickel, Vanadium, Iron, Copper,
and other metals in traces so
small they are measured in parts
per million or parts per billion.

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Eng.Said Elsayed
Classification of Hydrocarbons
There are so many different hydrocarbon
compounds in crude oil.
Estimates range between 50,000 and
1,000,000.
It’s necessary to have systematic ways to
classify them into manageable groupings.
The two basic systems used are:
 by carbon number, and
 by molecular structure

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Eng.Said Elsayed
Carbon Numbers
• This is based on the number of
carbon atoms found in a given
hydrocarbon molecule.
For example, methane (CH4) has
one carbon atom per molecule
and is C1.
Ethane (C2H6) and Ethylene
(C2H4),

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The carbon number is important because it
indicates the physical state of the
compound.
Basically, the higher the carbon number,
 The higher the boiling point,
 The greater the viscosity (the rate
at which it will flow through a
small opening)
 The higher the density (weight per
volume)

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C1 (methane)
 Is used as a fuel in the
refinery.
 It can sold and transported
by liquefying it by lowering
its temperature to – 255ºF
(this reduces its volume by a
factor of 1000 and there by
simplifies transportation)

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Eng.Said Elsayed
C3 (propane and propylene)
 Are used in plastics
manufacture.
 Propane can also be liquefied
for sale as LPG (Liquefied
Petroleum Gas).

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C4 (Butane and Butylenes)
 The largest gas molecule at
room temperatures, can be
combined to from C8’S
(liquids) for use in gasoline.
 C4’S can also be added
directly to gasoline to increase
vapor pressure for better
starts on cold mornings.

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Materials from C5 to C12
 Are used directly in gasoline
manufacture.
Materials from C13 to C17
 Are used as fuels and
lubricants.

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Materials from C17 – C40
Are used for
 Heavy fuels and asphalts
 Charge stocks for refinery
(convergence) processes that break
them down into smaller compounds
with lower carbon numbers (the C5
to C12 liquids) for use in gasoline

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Eng.Said Elsayed
Molecular Structure
Is the more complicated way to
classify hydrocarbon compounds.
Is the actual arrangement of the
carbon and hydrogen atoms.

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Eng.Said Elsayed
Molecular Structure
Is the more complicated
way to classify hydrocarbon
compounds.
 Is the actual arrangement
of the carbon and hydrogen
atoms.

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Eng.Said Elsayed
CH4 C2H6 C3H8
H H H H H H
│ │ │ │ │ │
H–C–H H–C–C–H H–C–C–C–H
│ │ │ │ │ │
H H H H H H
In each case, every carbon atom is linked either to a hydrogen
atom or to another carbon atom, and the carbons are added
together in a row.

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Eng.Said Elsayed
Mol.
Wt.
Formula
Name
Mol.
Wt.
Formula
Name
86
C6H14
Hexane
16
CH4
Methane
100
C7H16
Heptane
30
C2H6
Ethane
114
C8H18
Octane
44
C3H8
Propane
128
C9H20
Nonane
58
C4H10
Butane
142
C10H22
Decane
72
C5H12
Pentane

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Eng.Said Elsayed
Paraffin isomers
When we get to C4 (butane) there are two ways to link the
carbon atoms in a row again, making normal butane, or with
one of the carbon atom connected in the middle, making
isobutene.
C4H10 C4H10

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Eng.Said Elsayed
The word “normal” before a paraffin
indicates the straight-chain structure.
While the prefix “iso” indicates paraffins
with the more complicated branched
structures.
Even though these two compounds:
 Consist of the same number of
carbon and hydrogen atoms
 Differ physically & chemically and
have different boiling points, densities,
and refractive indices

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Eng.Said Elsayed
As the carbon number increases, the number of possible
permutations (isoparaffins) increases astronomically.

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Eng.Said Elsayed
2.3 Olefins or Ethylene Series
(Basic formula: CnH2n)
Olefins are not found naturally in crude
oil, but are the product of the refining
process.
Hydrocarbons in this series combine
easily with other atoms like chlorine
and bromine, without the replacement
of a hydrogen atom.
Since they are so reactive, they are
called unsaturated hydrocarbons.

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C2 paraffin, ethane, was saturated
because it contained six hydrogen
atoms.
If we remove two of the hydrogen’s and
bend the two vacated carbon valence
bonds around to join with each other,
we create a double bond or
unsaturated bond, the most reactive
point in the molecule.
The resulting compound is ethylene,
the C2 olefin.

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Eng.Said Elsayed
ETHANE (C2 H6) ETHYLENE (C2 H4)
C2 Paraffin C2 Olefin

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Naphthenes
(Basic formula: CnH2n)
Naphthenes have the same ratio of two
hydrogen atoms per carbon atom as do
olefins.
But they are more like Paraffins because
they are saturated compounds.
This is possible because instead of being
like the straight or branched structures
we’ve seen so far, naphthenes exist in a
ring structure.

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Eng.Said Elsayed
Naphthenes may be found in most crude oils but are seldom
shown in routine analyses.
Cyclohexane is a common member of this series. Its structural
formula is (C6H12).

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Aromatics
(Basic formula: CnH2n-6)
Aromatics get their name from the
fact that the earliest known members
of this class had very strong smells.
Aromatic is the word used to describe
an unsaturated hydrocarbon molecule
where the carbon atoms form a ring, a
cyclic compound.
All aromatics are based on benzene
(C6H6) .

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Since the aromatics are unsaturated,
they:
 Oxidized to form organic acids.
 Promote foaming and other
operational problems in the
production and handling of crude
oil and natural gas.

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Eng.Said Elsayed
Volume
Is the amount of gas that will fill a
container with dimensions of 1x1x1
(feet or meter).
Gas volume are measured in units of
cubic feet,
Or in units of cubic meters, the metric
units of volume.

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 Actual Volume (acf):
Is the amount of space occupied by a given amount of gas
under actual conditions of pressure and temperature.
Standard Volume (scf):
Is the volume that a given amount of gas would occupy if it
were at standard (Base) conditions of pressure and
temperature.
standard conditions are:
 Temperature: 60ºF (15ºC)
 Pressure: Atmospheric pressure

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 Pressure
In English units, pressure is expressed
as pounds per square inch (psi).
In the new International Standards
System of units, pressure is defined as
Newton (units of force) per square
meter (unit area) and is expressed as a
Paschal.
• psi = 6.9 Kpa
• kg/cm2 = 100 Kpa

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Atmospheric Pressure
Gauge Pressure:
Is the positive pressure measured with
respect to atmospheric pressure.
Gauge pressure is the amount of
pressure in a container above
atmospheric pressure.
Gauge pressure + atmospheric
pressure = absolute pressure.

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Eng.Said Elsayed
Basic Gas Laws
The particular relationships between
gas temperature, pressure, and
volume have been formulated into
three laws;

 Boyle's Law,
 Charles' Law, and
 General Gas Law.
 Dalton’ Law

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Eng.Said Elsayed
Boyle's Law:
Boyle's Law deals with the relationship of pressure to a
volume of gas.

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Charles' Law states that:
At a given pressure, the temperature of a gas varies directly
with its volume.
V1 / T1 = V2 / T2

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The General Gas Law:
Ideal (Perfect) Gas Law
PV/T = Constant
The perfect gas law is written for a single set of conditions as:
P x V = n x R x T
Where:
P = Absolute pressure (psia)
V = Volume (cubic feet)
T = Absolute temperature (ºR = t + 460 ºF)
n = Number of lb-mols (wt. of gas in lb/ MW)
R = Gas constant (10.72 for units shown)

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Eng.Said Elsayed
Session 2 : Gas Processing
Physical Properties
Molecular Weiaght:
Critical Pressure and Temperature:
The critical temperature is that
temperature above which a fluid cannot
exist in the liquid state.
The critical temperature for ethane, for
example, is 90.09 ºF. The critical pressure
is the vapor pressure of the fluid at the
critical temperature.

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Eng.Said Elsayed
The critical pressure is the
vapor pressure of the fluid at
the critical temperature.
The critical pressure of ethane
is 707.8 psia.
These two values mean that
the vapor pressure at 90.09 ºF
for ethane is 707.8 psia.
If the ethane temperature is
greater than 90.09 ºF,
increasing the pressure above
707.8 psia will not liquefy the
ethane.

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Heating Value:
Heating value is expressed as:
 BTU’s per cubic foot for gases,
 BTU’s per gallon for liquids.
Heating value is the amount of heat
released when a known volume of a
given hydrocarbon is burned.

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Eng.Said Elsayed
The net heating value is the
amount of heat that is generated
by product of combustion; water
vapor is generated in the
combustion process.
If this water vapor is condensed to
a liquid state, the amount of heat
released in the condensation is
added to the net heating value to
give the gross heating value of the
hydrocarbon.

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Eng.Said Elsayed
Vapor Pressure:
Vapor pressure data is important in determining the
liquid content, both hydrocarbon and water; of a
natural gas streams.

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Water Dew Point:
Hydrocarbon dew point

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Mercaptans (Methyl [CH3SH,] or
Ethylene [C2H5SH,] Mercaptans):
These materials are:
Very foul smelling compounds,
Can be used as gas odorants in
very small quantities,
Make the gas offensive to
certain consuming areas in larger
quantities.

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Eng.Said Elsayed

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Eng.Said Elsayed
Definitions
It is desirable to define several of the
terms that will be used in the book.
The main ones are as follows:
Raw Gas (Natural Gas)
Untreated gas from / or in the
reservoir.

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Eng.Said Elsayed
Pipeline gas or Residue Gas:
• Has the quality to be used as
a domestic or industrial fuel.
• It meets the specifications
set by a pipeline transmission
company, and / or a
distributing company.

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Eng.Said Elsayed
Sour Gas:
Gas that contains more than 1
grain of H2S per 100 scf of gas (1
grain = 0.065 grams).
Sweet Gas:
Gas in which the H2S content is
less than 1 grain per 100 scf of
gas.

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Eng.Said Elsayed
g.p.m for a gas:
Gallons of liquid per 1000 scf of gas.
Rich Gas:
Gas containing a lot of compounds
heavier than ethane, about 0.7 US
gallons of C3 + per 1000 scf of feed to
a processing plant.
Lean Gas:
Gas containing very little propane
and heavier-or the effluent gas from
a processing plant.

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Principle of gas processing

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From oil Facilities
Feed Gas Inlet Separator Main Compression Area
4 Units, Max. Capacity 220 MMSCFD
2 Delaval comp./Thomassen Turbines
2 Creusot Loire Comp./ MAN Turbines
Drying & Sweetening Area
6 Molecular Sieves beds, Type 5A
Diethanolamine Unit
Chilling Area
Gas/Gas Heat Exchangers
Gas/Liquid Heat Exchangers
Turbo-Expanders
4 Units, Atlas Copco
Booster & Sales Gas Compressors
6 Units, Max Capacity 210 MMSCFD
2 Delaval comp./MAN Turbines
3 Creusot Loire comp./MAN Turbines
1 Delaval Comp./Ruston Turbines
Fractionation Area
2 De-propanizers
2 De-butanizers
Condensates Tanks
2 Floating Roof Tanks
Capacity 38,000 bbl
LPG Spheres
5 Spheres, 6,000 ton Capacity
Utilities
Propane Ref. Package Air Compressors Nitrogen Unit Heaters Water Makers
DCS
Power House Fire Fighting Pumps Cooling Water pumps Flare System
Sales Gas to GASCO

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 Well Production

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Separators
A separator is a pressure vessel
designed to divide a combined
liquid–gas system into individual
components that are relatively
free of each other for subsequent
disposition or processing.

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Why we should use it?
Downstream equipment cannot handle gas–liquid mixtures .
• Pumps require gas-free liquid
•Compressor and dehydration equipment require liquid-free gas
• Product specification set limits on impurities
•Measurement devices for gases or liquids are highly inaccurate
when another phase is present.

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METHODS USED TO REMOVE OIL FROM GAS IN
SEPARATORS
1- Density Difference (Gravity Separation)
2-pressure reduction Flash drum
3- cooling
4-heating

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The difference of density will determine the gas flow rate that
allow the liquid drops to settle out
 For example the liquid drops will settle out from the gas stream
at 750 psig when the gas speed not more than 1 ft / sec ( pipe line
usually design at 15 to 60 ft /sec).

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The flow of the gas through the separator is slow enough (no
turbulence) which will keep the gas stream stirred up so
that the liquid has chance to drop out.

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2-Pressure reduction Flash drum
Refers to a conventional oil and gas
separator operated at low pressure .
With the liquid from a higher-pressure
separator being "flashed" into it.
3- cooling
The first-stage separator vessel on a
low-temperature or cold separation unit
(LTS).

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Eng.Said Elsayed
The basic equipment for separation
liquid from vapor uses:
Gravitational force is used by reducing
velocity so the liquid can settle out in the
space provide.
Centrifugal force is used by changing the
direction of flow.
True separator depends on the
gravitational force and retention time
that allow vapor and liquid
disengagement.

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Definitions
• When the gas stream carry some liquid it
called carryover
• When the liquid stream carry some gases
it called carry under

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Factors Affecting Separation
1.gas and liquid flow rates (minimum,
average, and peak)
2.operating and design pressures and
temperatures
3.physical properties of the fluids such
as density
4.presence of impurities (paraffin, sand,
scale, etc.)

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•Separators should be sized to handle the maximum flow rate
expected during the predicted life of the separator.
•Separators must also be capable of handling sudden slugs of
liquid.

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Effect of factor
Separation factor
Separation is easier when weight
difference is greater.
Separation is better with more time.
Separation is better with more area.
Separation is better at higher
velocity.
Makes separation more difficult.
1.Difference in weight of
fluid.
2. Residence time in
separator.
3.Coalescing surface area .
4.Centrifugal action
5.Presense of solids.
Effect of factors that cause separation

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Separators Classification
Geometry Function Pressure

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Classification by Function
Two-phase , (vapor-liquid) .
 Three-phase (gas-oil-water) .

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Classification by Operating
Pressure
 Low-pressure separators usually operate at
pressures ranging from 10 to 20 up to 180 to
225 psi.
 Medium-pressure separators usually
operate at pressures ranging from 230 to 250
up to 600 to 700 psi.
 High-pressure separators generally operate
in the wide pressure range from 750 to 1,500
psi.

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Eng.Said Elsayed
Test Separator
A test separator is used to separate and to
meter the well fluids.
They can be permanently installed or portable
(skid or trailer mounted).
Production Separator
A production separator is used to separate the
produced well fluid from a well, group of wells
Low-Temperature Separator.
The temperature reduction is obtained by the
Joule-Thompson
Classification by Application

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Eng.Said Elsayed
Classification by Geometrical
Vertical
Horizontal double-barrel
Horizontal
Spherical

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Horizontal Separators
Advantage of Horizontal Gas Separators
Horizontal separators are favored for large liquid volumes
or if the liquid-to-gas ratio is high.
Installations where vertical height limitations indicate
the use of a horizontal vessel.

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Separating foaming crude oil where
the larger liquid/gas contact area of the
horizontal vessel
The larger surface area provides better
degassing and more stable liquid level
They are also generally preferred for
three-phase separation applications.
Easy to hook-up, controls and easy to
reach safely.

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Disadvantages
1. Limited liquid surge capacity.
2. Liquid level control is more critical than with a vertical
type.
3. Area limitation
4. High expensive
5. Solid particles removing problems

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Separator two Phase

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Three Phase Separator

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Slug catcher

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Vertical Separators
This type is capable of handling
large slugs of liquid without
carryover to the gas outlet.
Is best suited for well streams with
low liquid content and high gas
volume and is usually
recommended, when the gas-oil
ratio is high

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Advantages
1. Liquid level and control not as critical as for
horizontal;
2. Easier and cheaper to design for surge capacity;
3. With certain designs, more extraneous material (for
example, sand, mud, and corrosion products) can be
handled; and
4. Usually easier to clean.

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Disadvantages
1. More expensive,
2. Does not adapt to skid-
mounted assemblies as well as
do horizontals in most cases,
and
3. Requires a larger diameter for
the same gas capacity.

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Filter (gas filter or filter/separator), dust Scrubber, or
Coalescer.

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Spherical Oil and gas Separators applications
• Well fluids with high GOR's,
constant flow rate and no liquid
slugging or heading.
• Installations where both vertical
and horizontal space and height
limitations exist.
• Downstream of process units —
such as glycol dehydrators and gas
sweeteners — to scrub expensive
process fluids, such as glycol .
• Installations where economics
favors the spherical separator.

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Separator internals
• Separators usually includes some
mechanical parts that improve the
separation efficiency ,each part is
designed for a given functions and
based on a given physical properties
of the separated
phases.
• The internals are divided into
three categories
–Inlet devices
–Intermediate devices
–Outlet devices

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Inlet devices
• The main objective of the inlet devices is a rapid
change in flow direction and velocity.
 Change in velocity will cause the separation of both gas
and liquid due to the difference of energy level , different
kinetic energy.
Change in direction will cause the gas to goes around
the deflector plates where the liquid will strike the
diverter and fall down.

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HHLL
HLL
D
LLL
FEED NOZZLE
OUTLET
150 mm
MIN
0.85 D
- 150 mm
600 mm MIN
FEED NOZZLE
600 mm
1 MIN
1 MIN
1 MIN
300 mm MIN
600 mm (DRY DRUM)
600 mm MIN
0.6 D
1200 mm MAX
DRY DRUM
Vortex Breaker if Continuous Flow
to Pump or Control Valve
Separators internals
Wire mesh
Vortex Breaker

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Operation of separator
• Pressure control
–The main point is the pressure control is done via regulating
the gas flow rate outlet from the separator.
• Level control
–In horizontal separator the level control is very important
where this level will determine the residence time for gas
bubbles to break out from the liquid.
–In vertical separator the level has no significant effect as
horizontal separator where the vapor space in vertical
separator usually some meters so the few inches will not effect.

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Important notes:-
• To evaluate if the residence time is enough to break out all
the gas or not we can notice the oil at the storage tank is
more gas flashed out , this indicate that the time is not
enough.
• If the level is over than what is required this will appears
in the down stream process via the carry over of liquid
with the outlet gas stream, this may be a load on
compressors scrubbers.
• The problem of get some gas with outlet oil is not critical
as carry over of liquid with gas so finally it is
recommended to set the level lower a little better than
over a little.

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Separators Control

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Separators concepts

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• The desired end product
dictates the processes required
• Dehydration of gas to reduce
corrosion and to prevent gas
hydrate formation

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 Prevent formation of hydrates and
condensation of free water in
processing and transportation
facilities
 Meet a water content specification
 prevent corrosion
 Product dehydration, Both gas and
liquid products have specifications
on water content
 Sales gas that leaves a plant is
usually dry if cryogenic hydrocarbon
liquid recovery is used

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Eng.Said Elsayed
Water in Natural Gas
All gases have the capacity to hold
water in the vapor state.
This is true for:
 Air,
 Natural gas (Hydrocarbon
mixture),
 Nitrogen,
 Carbon dioxide,
 Hydrogen sulfide, and
 Hydrogen.

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This capacity to hold water is a
function of:
 Gas composition itself,
 Pressure, and
 Temperature of the gas.

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•Liquid water and natural gas can form
solid , ice- like hydrates which plug
equipment
•Natural gas containing CO2 or H2S (acid
gas)
•Water vapor in natural gas may condense
in pipeline which potentially causes
slugging flow conditions
•Water vapor increases the volume and
decreases the heating value of natural
gas which leads to reduced line capacity

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Solubility of Water in Natural Gas
The solubility of water:
 Increases with increasing temperature, and
 Decreases as increasing pressure.
Consequently , equilibrium is established when
The partial pressure of water in the gas phase is equal to the vapor
pressure of water at the temperature of the system.
The dew point of water will therefore be different from the
hydrocarbon dew point..

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80 oF
0.0155
LB W /100LB
propane
Solubility of
Water in Liquid
Hydrocarbons

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150 oF
220
LB/MMSCF
WATER CONTENT
OF GASES
3%
0.93
26
0.98
At 150°F and 1,000 psia.
W = 220 lb/MMscf
IF SP. GR. IS 0 .6
At 26 mw gas (SP GR 0.9) ,
Cg = 0.98
W = (0.98)(220)
= 216 lb/MMscf
For 3% brine,
Cs = 0.93
W = (0.93)(220)
= 205 lb/MMscf

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•If the pressure is increased and the
temperature decreased :
– the capacity of the gas to hold water will
decrease and some water vapor will
condense and drop out
•This point is known as the water dew point
which may be defined as the temperature at
which the natural gas is saturated with
water vapor at a given pressure
Water Dew Point

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Dew Point Depression
Is the difference between the dew point temperature of
Water in saturated gas stream and
The gas stream after it has been dehydrated
Dehydration Unit
Raw Gas Sales Gas
P =500 psia
T = 60 degree F
Water content =
30 Ib w / MM scf g
P =500 psia
T =20 degree F
Water content =
7 Ib w / MM scf g
Free water removed
23 Ib w / MM scf g
DPD = 60 – 20 = 40 Degree F

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1. Hydrates
•Solid components that form as
crystals and resemble snow in
appearance
•Created by a reaction of natural
gas with water
•Contain about 10%
hydrocarbon and 90% water
Hydrates Control in Natural Gas System

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Hydrates form when free water combines with the following
gases
•Butane (C4)
•Carbon dioxide (CO2)
•Ethane (C2)
•Hydrogen sulfide (H2S)
•Methane (C1)
•Nitrogen (N2)
•Propane (C3)

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Composition
• Hydrocarbons with five or more
carbon atoms (C5+) do not fit into
these lattice vacancies
• Hydrates float on water, but sink in
hydrocarbon liquids
Water
Hydrate
Hydrocarbon

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Factors Promoting Hydrate Formation
Primary
•Free water (Gas is at or below its
dew point.)
•High pressure
•Low temperature

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Secondary
•High velocities.
•Physical sites where crystals might form
such as pipe elbows, orifices, or line scale.
•Pressure pulsations.
•Small crystals of hydrates that may act as
seed crystals.
•Turbulence in gas streams (promotes crystal
growth by agitating supercooled solutions).

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•The smaller natural gas molecules,
methane (C1) and ethane (C2), form
stable structure I hydrates.
•However, even small concentrations of
propane (C3) or ethane strongly promote
the formation of hydrates in gas streams.
•Presence of H2S or CO2 is conclusive to
hydrate formation since these acid gases
are more soluble in water than
hydrocarbons

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Hydrate Structures:
A hydrate is a water lattice with a
series of open space in the
interstices.
It can only be a stable solid if enough
of these spaces are filled by the gas
molecules.
These spaces are of two sizes:
1. Smaller molecules (CH4 , C2H6 ,
H2S and CO2) form body
centered cubic structure
2. Larger molecules (C3H8 , iC4H10)
form diamond lattice structure with
17 molecules H2O per gas molecule

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The characteristics of hydrate crystalline structures.
STRUCTURE II
STRUCTURE I
16 small and 6 large voids
2 small and 8 large voids
Generally formed by C3H8, i-C4H10,
CH2Cl2, CHCl3
Generally formed by CH4, C2H6, H2S,
CO2
17 water molecules per gas molecule
MAX
5 3/4 water molecules per gas
molecule MAX

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Using Graphical Techniques to Predict Hydrate-
Formation Conditions

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Determining the Hydrate-Formation using (Gravity
Graphic Method)
•Calculate the approximate temperature at which the gas
stream entering a chill down train at a Gas Plant forms
hydrates.
•The left column of Figure 17 lists the composition of the gas
stream and the right column is provided to help organize the
calculations.
•Given:
Pressure = 424 psig
Temperature from dehydrator = 80°F

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1. Calculate the weight of component per mole of gas mixture
2. Calculate the total molecular weight of the gas mixture.
lb/Mole OF
MIXTURE
MOLECULAR
WEIGHT
MOLE
FRACTION
COMPONENT
0.185
28.0
0.0066
N2
0.0132
44.0
0.0003
CO2
0.00
34.3
0.0
H2S
10.1
16.0
0.6317
C1
6.35
30.1
0.2111
C2
4.80
44.1
0.1088
C3
0.453
58.1
0.0078
i-C4
1.41
58.1
0.0242
n-C4
0.224
72.2
0.0031
i-C5
0.346
72.2
0.0048
n-C5
0.121
86.2
0.0014
n-C6
0.020
100.2
0.0002
C7+
24.0
--
1.00
TOTAL GAS STREAM

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3 - The use of Eqn. 2 to calculate the specific gravity (relative to air) of
the gas mixture results in the following:
sp. gr. = = = 0.828
MWgas
MWair
[ ] 24.0 lb / mole
29.0 lb / mole
[ ]

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4. From Figure 16, the hydrate-formation temperature of the
gas stream at 424 psig (439 psia) is determined to be 57°F.
439
57
Answer:
Hydrates can form in this gas stream at approximately 57°F.

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The hydrate formation can be prevented by:
• Heating-the cold unprocessed well stream
• Inhibitor injections like ammonias, brines, glycol and
methanol have been used to lower the freezing point of
water vapor
• Methanol and glycol are the most inhibitors widely used.
Usually methanol and glycol are used when hydrate problems
arise so rarely that the installation of heater or dehydration
equipment is not economically feasible

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Indirect Heater

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Indirect Heaters advantages:
•Minimal maintenance or attention required
•Very low chemical requirements
Indirect Heaters disadvantages :
•Difficulty of supplying clean and reliable
fuel to remote locations
•Large operating (fuel) costs if cheap fuel is
not available
•Potentially large capital costs
•Significant plot space required
•Special safety equipment needed because
of fire hazard

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Eng.Said Elsayed
Currently, methanol and monoethylene glycol (MEG) are the two
chemicals most commonly injected into gas streams to inhibit
hydrate formation. Consider the use of chemical injection to
inhibit hydrate formation for the following:
•Gas pipelines in which hydrates form at localized points
•Gas streams operating a few degrees above their hydrate
formation temperature
•Gas-gathering systems in pressure-declining fields
•Situations where hydrate problems are of short duration
Chemical Injection

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Methanol works well as a hydrate inhibitor
because of the following reasons:
•It can attack or dissolve hydrates already
formed.
•It does not react chemically with any
natural gas constituents.
•It is not corrosive.
•It is reasonable in cost.
•It is soluble in water at all
concentrations.
Methanol

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Method of Injecting Methanol :
The injection of methanol considerably upstream of a hydrate-
forming location allows the methanol to distribute and
vaporize completely.
Because of methanol’s high volatility, nozzle placement and
design are not as critical as they are for glycol injection.
Methanol injection nozzles should be located as follows:
•Upstream of front-end exchangers
•At the inlets of turboexpanders
•At any refrigerated condensers in downstream fractionation

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Eng.Said Elsayed
MeOH
Temp.
Controller
Power gas
Gas stream
methanol
pump
Injection
point
Choke
Methanol

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Eng.Said Elsayed
One way of assuring mixing at the
point of injection is to add the
inhibitor upstream of:
A choke or Pressure control valve
as shown.
As the gas flows through the
control value, its pressure is
reduced and violent agitation
occurs within the control value.
The inhibitor and gas will
thoroughly mix in the valve.

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Dehydration Systems
Dehydration systems used in the natural gas industry fall into
four categories in principle:
(1) Direct cooling
(2) Compression followed by cooling
(3) Adsorption
(4) Absorption

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Dehydration by Cooling
• The ability of natural gas to contain
water vapor decreases as the
temperature is lowered at constant
pressure
• During the cooling process, the excess
water in the vapor state becomes
liquid and is removed from the system
• The gas dehydrated by cooling is still at
its water dew point unless the
temperature is raised again or the
pressure is decreased

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Dehydration by Cooling
• Cooling for the purpose of gas
dehydrationis sometimeseconomical
if the gas temperature is unusually
high
• Gas compressors can be used
partially as dehydrators

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• Dehydration by Adsorption

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• Dehydration by Absorption

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Solid desiccant Beds:

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•Adsorption :
the ability of a substance to hold
gases or liquids on its surface
•The water vapor from the gas is
concentrated and held at the surface
of the solid desiccant by forces
caused by residual valiancy
•Solid desiccants have very large
surface areas per unit weight to take
advantage of these surface forces

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Solid Desiccant Dehydration
Desiccants in common commercial use fall into
one of three categories:
• Alumina - Regenerable aluminum oxide
base desiccant.
• Silica Gel - Regenerable silicon oxide
adsorbent.
• Molecular Sieves - Regenerable solid
desiccants composed of crystalline metal
aluminosilicates (zeolites).

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Desiccant Choice
•Aluminas are the cheapest but require larger
towers for a given water load, which increases
capital cost and heat load
•Molecular sieves are the most versatile but
they are many times more expensive than gel
or aluminas
•
•Silica gel is a very suitable desiccant for use
with low percentages of sulfur compounds

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Eng.Said Elsayed
The materials which meet the above requirements may be
divided into several general categories
• Bauxite - naturally
• Alumina - a purer, manufactured version of bauxite
• Gels - composed largely of Si02 or alumina gel,Manufactured
by chemical reaction
• Molecular Sieves - a calcium-sodium alunvno-silicate
(zeolite)
• Carbon (charcoal) a carbon product treated and activated to
have adsorptive capacity

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• The polarity of the water molecule
also plays an important part
• Molecular sieves have electric charges
on the inner surfaces of the crystal
cavities, which are attracted to similar
charges on polar molecules

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Adsorption start

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• Mol sieve are crystalline metal Alum
silicate with three dimensional
interconnecting network structure of
silica and alumna tetrahedra.
• It is represented by the following formula:
Na12 ((AlO2)12(SiO2)12). XH2O …………. Type A
Na86 (( AlO2)86 (SIO2)106).XH2O …………TypeX
Molecular Sieve

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Molecular Sieve
• It is called M.S because of
their property of screening
molecules at the molecular
scale.
• Other adsorbent have very
wide pore distribution.

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Pressure Loss
•It is in the piping manifold,
switching valves and across
controls
•A higher pressure drop
enables the designer to
reduce the size of these
components

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Eng.Said Elsayed

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Mechanism of Adsorption
• Mass Transfer Zone Concept
MTZ
MTZ
MTZ
MTZ
MTZ
Co
Cs
Fresh
Adsorbent
Saturated
Adsorbent

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 Top zone is called saturation zone which
this zone in equilibrium with the wet inlet
gas.
 The middle zone is called mass transfer
zone (MTZ) where the water content of
the gas is reduced from saturation.
 Bottom Zone is unused sieve or fresh
sieve

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Eng.Said Elsayed
•Most large dry desiccant units for natural
gas drying contain more than two towers to
optimize the economics
•The operating sequence of the towers on
stream is
• Tower#1 with tower#2 ,Tower#2 with
tower #3,Tower#1 with Tower# 3 and
tower #1 with tower#2 and so on

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Eng.Said Elsayed
The Nature of Adsorbent
1. Equilibrium zone
2. Mass transfer zone (MTZ)
3. Active zone

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Eng.Said Elsayed
Different three-tower systems with different regeneration
& cooling systems

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Process Flow of Solid Desiccant Dehydrators

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•An inlet gas stream separator/liquid coalescer.
•Two or more adsorption towers (contactors) filled with solid
desiccant.
•A high-temperature heater that provides hot regeneration gas
to reactivate the desiccant in the towers.
•A regeneration gas cooler that condenses water from the hot
regeneration gas.
•A regeneration gas separator (knockout) that removes the
condensed water from the regeneration gas.
•Piping manifolds, switching valves, and controls that direct and
control the flow of gases according to the process
requirements.
Function of Major Components of Solid Desiccant
Dehydrators

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Factors which affect the length of the MTZ
• Gas velocity - increasing velocity increases
length
• Contaminants , slow the mass transfer
process (lengthen MTZ)
• Water content and relative saturation of
the inlet gas

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Eng.Said Elsayed
Regeneration can done by two ways:
1. Temperature Swing Adsorption
(T.S.A) which increasing temp for
regeneration (Most widely used)
2. Pressure Swing Adsorption (P.S.A.)
which decrease in pressure
• In most cases the regeneration
temperature for molecular sieve is
carried out at 200-300 °C
20" Manhole
10" Adsorb. in
Regen gas out
10" Adsorb. out
Regen gas in
16" Fill hole
3.5" thick.
Supporting screen
1/8" ceramic ball
1/4 " ceramic ball
1/16" mol.
sieve (h=9')
12'
4"
4"
7' I.D.

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Mol sieve Ageing
•Mol sieve age during first year
operation 15-20 %.
The expected change out time of mol
sieve after 9000 – 10000 regen.
cycles.

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Eng.Said Elsayed
Troubleshooting – Key Observations
Low Adsorption Capacity -
Short Cycles.
High Water Dew point of Sales
Gas.
Increase in Bed Pressure Drop.
Dust build up in Product Gas
Filters.

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Low Adsorption Capacity
 Poor Initial Adsorbent quality –
Damaged in storage or on loading – e.g exposed to
rain or physical damage on handling
 Wrong grade of Mol sieve loaded .
 Operating conditions do not match design case –
most notably higher temperature operation
Possible Reasons for Operating Problems

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A. Advantages
1. Lower dew point
2. Higher contact temperatures
3. Higher tolerance to sudden load changes, especially on
startup
4. Quick startup after a shutdown
5. High adaptability for recovery of certain liquid
hydrocarbons
6. Environmentally cleaner than a TEG unit
7. Reliable

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B. Disadvantages
1. Relatively high cost
2. Will achieve a far lower water
dew point than is necessary

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Liquid Desiccant:
Is liquid that possess the ability to absorb
(attract) water from gas.
Liquid Desiccant Has the following criteria
(specifications):
1. Highly hygroscopic,
2. Do not solidify in a concentrated solution,
3. Non corrosive,
4. Do not form precipitates with gas
constituents,
5. Easily regenerated to a high concentration,

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6. Can be separated easily,
7. Essentially non soluble in liquid hydrocarbons, and
8. Relatively stable in the presence of sulfur compounds and
carbon dioxide under normal operating conditions.

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Absorption:
Is the removal of water vapor by
bubbling (mixing) the gas
counter-currently through
certain liquids that have a
special affinity (attraction) for
water.

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Eng.Said Elsayed
The more common liquids in use for
gas dehydrating are Monoethylene
glycol, diethylene glycol, triethylene
glycol and tetraethylene glycol.
Monoethylene and Diethylene glycol
usually used in glycol injection
system.
Most glycol dehydrators use
triethylene glycol, which can be
heated to about 400 °F.

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DEG (Diethylene) is somewhat cheaper
(is used for this reason)
But, by the time it is handled and added to the units there is no
real saving.
Compared to TEG, DEG has:
C A larger carryover loss,
Offers less dewpoint depression and
Regeneration to high concentrations is more difficult
For these reasons, it is difficult to justify a DEG unit, although a
few units are built each year.

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Triethylene )TEG) is preferred for use
in dehydration units because:
1. It is more easily regenerated due to its
high boiling point and other physical
properties.
2. It has a high decomposition temperature
of 404ºF (207ºC).
3. It has lower vaporization losses than
other glycols.
4. It has lower capital and operating costs
than other glycol systems.
5. TEG dew point depressions range from
40 – 150o F

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Tetraethylene (TREG) is:
 more viscous, and
 more expensive.
The only real advantage is its lower
vapor pressure which reduces absorber
carryover loss.
It may be used in those relatively rare
cases where glycol dehydration will be
efficient to treat gas whose
temperature exceeds about 50ºC
)122ºF).

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Distillation:
Where : water is separated and removed
from glycol by boiling:
 Glycol boils at approximately 435º F
(224 ºC).
 Water boils at 212 ºF (I00ºC).
Distillation of water from glycol involves
heating the glycol-water mixture to a
temperature between:
212º F (100º C) and 400 ºF (204ºC)

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TEG
Triethylene glycol (TEG) is a member of a
homologous series of di-hydroxy alcohols.
It is a colorless, odorless ,stable liquid
with low.
viscosities and high boiling points.
Properties:
Molecular formula C6H14O4
Molar mass 150.17 g mol−1
liquid Density 1.119 kg/lit
Boiling point 285 C
pour point -58 C

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Eng.Said Elsayed
Most process units using absorption for
dehydration employ triethylene glycol
(TEG) as the absorbent.
Other glycols and glycol mixture are used,
but the relative number of such units is
small
However, with normal field equipment,
DEG can be concentrated to only 95%
purity, whereas TEG concentrations can
reach 98 to 98.5% without special
equipment.

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Process Flow and Components
A typical glycol dehydration system consists of the following
components:
 Contactor column,
 Reboiler,
 Glycol filters,
 Pump,
 Surge tank,
 Gas-condensate-glycol separator, and
 Heat exchangers.

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Contactor Column:
The function of the contactor
column (absorber) is to contact
natural gas with the glycol, so that
the glycol can remove water
vapor from the natural Gas.
These vessels are designed to
accommodate a certain gas
volume and pressure ,exceeding
design specifications will increase
glycol losses and outlet gas dew
point.

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Eng.Said Elsayed
For large volumes of gas, the
contactor is usually a tray column
containing 4 to 12 trays.
The number of trays in the
contactor will affect the amount
of moisture removed from the
gas by the glycol; more trays
mean more moisture removal.
Rarely does the number of trays
exceed ten.

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Inlet scrubber is an essential part of
the glycol:-
• Free water will increase glycol flow rate,
increase re-boiler heat duty, overload the unit.
• Heavy hydrocarbons tends to form emulsion
with glycol, it can plug the absorber trays, it
may Coked on the heat transfer surfaces which
decrease the heat transfer efficiency.
• At the well pore down hole additives,
corrosion inhibitor ,acidizing, fluids could cause
foaming.
• Solids enhance the foaming formation.

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Eng.Said Elsayed
In smaller capacity units (18 inches or less)
random packing may be used instead of
trays.
The packing is:
Metal,
Plastic,
Ceramic.
Packed columns are less expensive; however,
 The glycol tends to channel
easier, and
 Have poorer flow distribution

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Eng.Said Elsayed
Before lean glycol enters the contactor, two
things happen:
1. The glycol is pumped up to contactor
pressure, and
2. The glycol temperature is l0º-15ºF (5-
7ºC) above the inlet gas temperature.
This is done by passing the lean glycol
through a heat exchanger where it is
cooled by the dry gas leaving the
contactor.

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Incorrect glycol temperatures
entering the contactor indicate
an imbalance in the glycol to gas
flow rate, a problem in:
 The heat exchanger, or
 The reboiler temperature
is out of adjustment.

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Carryover can result from:
 Foam buildup caused by glycol
contamination, and
 High gas rate.
It will happen continuously
when the gas rate is high
enough to agitate the liquid
on the top tray so that a foam
forms that is too thick for
the mist eliminator to handle.
When this happens, the
gas rate must be reduced to eliminate carryover.

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Level control on the contactor is important in stabilizing
operation.
The level controller should be adjusted to hold a uniform flow
rate of glycol out of the contactor.
Flow rate surges will cause the reboiler to operate inefficiently
and may overload it.

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Eng.Said Elsayed
Gas-Condensate-Glycol Separator
This separator is also known as the
flash tank or glycol-gas separator.
It is used to recover:
Gas which dissolved
in the glycol solution
in the contactor,
Any liquid hydrocarbons
(condensate) carried out of the
contactor by the glycol solution.

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Separating liquid hydrocarbons from glycol
before they enter the reboiler:
 Reduces the load on the carbon filter,
and
 Helps prevent carbon from building up
on the reboiler fire tube.
Problems caused by hydrocarbons entering
the still column are:
 Flooding,
 Glycol loss, and
 Possible damage to the still
column.

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Eng.Said Elsayed
Glycol must be heated before enter the flash
drum to reduce the glycol viscosity and
improve the separation.

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Eng.Said Elsayed
Filters:
Are installed in the glycol stream to remove:
 Solids, and
 Other dissolved contaminants.
(Hydrocarbons)
which may cause plugging and foaming.
There are two types of filters commonly used in
gas dehydration systems:
 One for solids removal and
 The other for dissolved contaminants
removal.

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Eng.Said Elsayed
Solids Removal:
Solid particles can cause:
Erosion of pump pistons,
valve seals and discs,
Plugging of equipment, and
Foaming.
The filters may be:
 Fine screen,
 Sock type or
 Cartridge filters

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Eng.Said Elsayed
Dissolved Contaminants Removal:
Activated carbon filters are
recommended for the removal of
dissolved contaminants.
They work well until their adsorption
capacity is reached.
In cases where the glycol contains
appreciable quantities of light
hydrocarbons, they must be changed
or reactivated frequently.

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Regenerator and Still Column
• Is a combination of the glycol
reboiler and the still column
• Regenerate the rich glycol,
making it lean again and ready
for use in the contactor column
• The temperature of Tri-Ethylene
Glycol should not exceed 400 ºF
(204 ºC)

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The reboiler:
Is the vessel which supplies heat to
separate glycol and water by simple
distillation.
Glycol is heated to a temperature
between:
380ºF and 400ºF (193ºC and 204ºC)
to remove enough water vapor to
regenerate the glycol to 98.5-99%
The temperature of TEG should not
exceed 400ºF (204ºC) because TEG will
begin to break down at higher
temperatures (degradation).

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Regenerator and Still Column
• Excess glycol spills over the weir
and flows downward into the
surge tank by gravity.
• The still column, sometimes
called a stripper
• Still column are normally packed
column and have finned
condenser
• Still temperature should be set at
the boiling point of pure water

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Eng.Said Elsayed
Glycol level in the reboiler is maintained by an overflow weir.
Excess glycol spills over the weir and flows downward into the
surge tank by gravity.
When glycol level is
low in the surge tank,
fresh glycol is added
to the reboiler, so that
it can be dried before
going to the surge tank.

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Eng.Said Elsayed

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Eng.Said Elsayed
The still column (stripper):
Is the vessel located on top of the reboiler where distillation of
glycol and water actually takes place.
Still column are normally
packed column have
finned condenser
(or reflux coil) in the top
to cool water vapor
leaving the column and
to recover entrained
Glycol.

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Eng.Said Elsayed
The amount of glycol lost with the
water vapor leaving the still
column is controlled by:
The temperature of the water
vapor (still column overhead
temperature)
This temperature should be set at
the boiling point of pure water
(100 ºC) at the pressure in the top
of the still column (Atmospheric).

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If the still overhead temperature is
above the boiling point of pure water:
 Glycol carryover will occur, and
 Losses will be higher than normal.
If the still overhead temperature is
below the boiling point of pure water:
 Too much water will be
condensed, and
 The reboiler heat requirements
and fuel usage will increase.

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Eng.Said Elsayed
Surge Tank:
Is used to store regenerated glycol for
pump suction.
It is commonly positioned under the
reboiler in the glycol dehydration system.
The surge tank should be vented and the
vent line kept unplugged.
Vapors, which are trapped in
the surge tank, could cause the
circulation pump to vapor lock.
The vent line should be piped away from
process equipment.

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Eng.Said Elsayed
F. Pumps
• Small dehydration units use a fluid driven pump
• Larger units generally use an electrically driven reciprocating
pump
• Before entering the pump, rich glycol passes through a
strainer to remove large particles

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Eng.Said Elsayed
Heat Exchangers
There are two types of heat
exchangers used in a glycol
dehydration unit:
 Glycol to gas heat
exchanger, and
 Glycol to glycol heat
exchanger (s).

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Eng.Said Elsayed
Heat Exchangers
1.Glycol/Gas-Heat Exchanger:
• Dry gas leaving the contactor
•Passesthroughthisheatexchanger
•The temperature of the gas is
raised slightly as it cools the
incoming lean glycol

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Eng.Said Elsayed
2. Glycol/Glycol Heat Exchanger:
•Hot, lean glycol leaves the
surge tank
• Passes through a glycol/glycol
heatexchanger
• glycol is cooled by the rich
glycol stream leaving the
filters downstream of the G-
C-G separator

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Eng.Said Elsayed

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Eng.Said Elsayed

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Eng.Said Elsayed

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