# GAS PROCESSING

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```GAS PROCESSING
Jaouhar Ktari
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What are the various typical specs for gas dehydration per
service?
There are four methods that are used for gas dehydration: they vary in
efficiency and cost. The methods used for gas dehydration are:

Absorption


Membrane processes

Refrigeration
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Water Dew-point
The efficiency of the dehydration is measured on the water contents in
the dry gas. The dew-point temperature for the water in the gas is often a
more useful parameter than the total water contents. The dew-point
temperature must be below the minimum pipeline temperature, to avoid
liquid in the gas pipeline.
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A dew-point temperature of 6 to 11 °C (10 to 20 °F) below the desired
dew-point may be used to insure against non-ideal situations. The water
Dew-point may differ from the gas Dew-point.
The total gas dew-point may be influenced by other hydrocarbons in the
gas. This can result in condensation of hydro-carbons in the gas
pipeline. This is also undesirable but much less so than water
condensation.
Water content in natural gas
Based on typical gas composition :
 separate corrections for actual compositions acid gas content.
Takes into account non-idealities.
Take care if gas is specified as wet or dry basis.
( dry basis does not include the amount of water in the MMSCF).
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Wet Basis
XH2O
(NH2O/MH2O)/(NHC+NH2O)= YH2O/MH2O
Dry Basis
XH2O
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(NH2O/MH2O)/(NHC)= (YH2O/MH2O )/(1-yH2O)
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Water content on field
Equal fugacities for each component in each phase.
Between gas/water phases:
yi= xi*Ki
where
Ki = Фi,l/Фi,v
For a gas in contact with pure water:
Y H2O = (PH2OVap)/P
(xH2O =1)
Formation of the water phase will control the water content in the gas
phase :
•
Increasing water in the feed increases the amount of free water, not
the concentration of water in the gas.
•
Can decrease the gas water content by adding compounds that are
water soluble.
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What are hydrates?
Hydrates are a possibility in oil/gas exploration, production,
transportation, or processing, which involves water and molecules smaller
than n-pentane.
When small (< 9 Å) nonpolar molecules contact water at ambient
temperatures(typically < 100°F) and moderate pressures (typically > 180
psia), a water crystal form may appear a clathrate hydrate.
1 Å = 10^(-10) m
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What are the types of hydrates (Explain Type I and Type II
hydrates)?
Type I
Type II
Type H
Type I
Type I hydrates consist of 46 water molecules.
It is made from two types of cages:

Dodecahedron, a 12-sided polyhedron where each face is a regular
pentagon.

Tetrakaidecahedron, a 14-sided polyhedron with 12 pentagonal faces and
two hexagonal faces. The dodecahedral cages are smaller than the
tetrakaidecahedral cages.
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Type II
The Type II hydrate consists of 136 molecules of water.
The structure of the Type II hydrates is significantly more complicated
than that of the Type I. The Type II hydrates are also constructed from two
types of cages.

Dodecahedron, a 12-sided polyhedron where each face is a regular
pentagon.

Hexakaidecahedron, a 16-sided polyhedron with 12 pentagonal faces
and four hexagonal faces. The dodecahedral cages are smaller than the
hexakaidecahedron cages.
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What are the thermodynamic hydrate inhibitors?
A thermodynamic hydrate inhibitor (THI) is a chemical substance used to balance
the reactions between hydrocarbons and water that result in the formation of
crystalline compounds. Thermodynamic hydrate inhibitors do this by shifting the
crystalline equilibrium curve in a direction that lowers the reaction temperature to
a level that blocks compound formation. Crystalline build-up in pipelines is
reduced when a thermodynamic hydrate inhibitor is used as an additive.
Two main thermodynamic hydrate inhibitors are commonly used:
Methanol and monoethylene glycol (MEG)
A thermodynamic inhibitor is sensitive to changes in subsystem cooling.
Therefore, the rate that an inhibitor is injected into a system must correlate to
temperature changes within the system. In the case of methanol, ideal operating
conditions are about 0.5°C (33°F). A methanol injection of 40% by volume in an
aqueous phase is required to prevent hydrate crystalline formation.
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What are the LDHI (Low Dosage Hydrate Inhibitor)?
There are two types :

Kinetic Hydrate Inhibitors (KHI)

Anti-Agglomerants (AA)
KHI
Interfere with hydrate crystal growth or nucleation by embedding
themselves into the lattice structure, delaying significant growth for
longer than the fluids residence time.
AA
Prevent the agglomeration of hydrate crystals into large masses by
dispersing water droplets within the condensate or oil phase.
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The main Glycols used for Gas Dehydration
Glycol is a common name for diols: with the two alcohols these substances
have a high affinity for water. In dehydration 1,2-ethandiol also known as
Monoethylen glycol (MEG) and the small polymers of MEG (diethylen
glycol (DEG), triethylen glycol (TEG) and tetraethylen glycol (TREG)) are
the most commonly used for absorbents. Higher polymers than TREG is
usually not used for dehydration because they become too viscous
compared to the smaller polymers.
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What are the main components of TEG dehydration unit?

Inlet cooler
An inlet cooler may be used because dehydration is more efficient at low
temperatures. An inlet cooler is used when the inlet gas temperature is higher
than the desired temperature in the contactor. It is also a helpful tool in
simulation if the temperature in the contactor needs to be optimized.

Inlet scrubber
The inlet scrubber removes free liquid and liquid droplets in the gas, both water
and hydrocarbons. Removing liquid water in the scrubber decreases the amount
of water that has to be removed in the contractor.

Contactor
The contactor is the absorption column where the gas is dried by the glycol.
The lean glycol enters at the top of the contactor while the rich glycol is
collected at the bottom of the contactor and sent to regeneration. The wet gas
enters the contactor at the bottom, while the dry gas leaves at the top.
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The glycol temperature into the contactor must be 3 to 11 °C (5 to 20 °F)
higher than the gas entering the contactor to minimize hydrocarbon
condensation into the glycol.
At contactor temperatures below 10 °C (50 °F) TEG becomes too viscous,
thus reducing the column efficiency. The contactor temperature may be as
high as 66 °C (150 °F), but glycol vaporization loss is often deemed
unacceptably high above 38 °C.
 Flash valve
After the contactor column the pressure is reduced to the regeneration
pressure by a flash valve. The pressure drop over this valve depends on the
pressure in the contactor and the pressure loss in the pipes and equipment
until the regeneration column.
 Flash separator
It is a good idea to install a separator after the flash valve. Because of the
decreased pressure hydrocarbons absorbed in the glycol will be released.
With a flash separator the hydrocarbon rich gas, can be used as process gas
in the plant.
The pressure in the flash separator must be above the pressure in the system
that the gas is vented too.
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
Filters
Filters are only necessary if there is a problem with solid particles or
liquid hydrocarbons in the glycol. Solid particles in the glycol
accumulate, increasing the wear on the equipment and can create plugs
in heat exchangers. Solid particles can easily be removed with sock
filters, which can be made of cloth fabrics, paper or fiberglass.
 Heat exchangers
The numbers of heat exchangers varies with the design of the process
plant. Because of the large temperature difference between the contactor
and regenerator column, rich glycol needs to be heated while lean glycol
must be cooled. With proper design of heat exchangers between the rich
and lean glycol most of the energy can be conserved.
 Regenerator
The regenerator is a distillation column, where glycol and water is
separated. The rich glycol is preheated in heat exchangers before it is
feed to the regenerator column.
The energy required to separate glycol and water is supplied by the
reboiler at the regenerator column.
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The pressure in the regeneration system is just above atmospheric
pressure, this is to insure that no air can enter the system from the
atmospheric vent.

Stripping column
Glycol purities up to 99.9 wt% can be achieved by using a stripping
column after the regenerator. The stripping gas from the top of the
stripping column is routed to the regenerator boiler, like when stripping
without the stripping column.
Cool stripping gas can be used in the stripping column, because the glycol
needs to be cooled after the regenerator. If on the other hand stripping gas
is added directly to the regenerator boiler it might be preferable to preheat
the gas, to keep a uniform temperature in the boiler.

Glycol storage tank
This is an optional instalment that ensures a constant glycol flow to the
contactor column. Because there will be a loss of glycol in the dehydration
system, a storage tank can act a buffer to prevent insufficient glycol flow,
and also be used to measure the glycol contents in the system.
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
Glycol circulation pump
Because of the pressure difference between the regenerator and the
contactor, the glycol pressure needs to be increased. This is done with
the glycol regeneration pump. The glycol is cooled below 80 °C before
pumping to protect the pump.
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How does the TEG Dehydration unit work?
The gas flows through a separator to remove condensed liquids or any solids that might
be in the gas. Some absorbers incorporate the separator in a bottom section of the
vessel, in which case the gas then flows upward through a chimney tray into the glycol
absorber portion of the vessel. The glycol contactor or absorber can contain:

Trays

Random packing

Structured packing
If it is a trayed vessel, it will contain several bubble-cap trays. Lean glycol is pumped
into the upper portion of the contactor, above the top tray but below the mist eliminator.
The trays are flooded with glycol that flows down from tray to tray in down comer
sections. The gas rises through the bubble caps and is dispersed as bubbles through the
glycol on the trays. This provides the intimate contact between the gas and the glycol.
The glycol is highly hygroscopic, and most of the water vapor in the gas is absorbed by
the glycol. The rich glycol, containing the absorbed water, is withdrawn from the
contactor near the bottom of the vessel above the chimney tray through a liquid level
control valve and passes to the regeneration section. The treated gas leaves the
contactor at the top through a mist eliminator and usually meets the specified water
content.
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The rich glycol can be routed through a heat exchange coil in the top of
the reboiler column called the still. The heat exchange generates some
reflux for the separation of the water from the glycol in the top of the
still and also heats the rich glycol somewhat. In some installations, the
rich solution passes to a flash tank operating at about 15 to 50 psig,
which allows absorbed hydrocarbon gas to separate from the glycol.
The glycol then flows into the still through a filter and a heat exchanger,
exchanging heat with the regenerated glycol. It drops through a packed
section in the still into the glycol reboiler vessel, where it is heated to
the necessary high regeneration temperature at near atmospheric
pressure. At the high temperature, the glycol loses its ability to hold
water: the water is vaporized and leaves through the top of the still. The
regenerated glycol flows to the surge tank, from which it is routed
through the lean/rich heat exchanger to the glycol pump. The pump
boosts the pressure of the lean glycol to the contactor pressure. Prior to
entering the contactor, it exchanges heat with the dry gas leaving the
contactor or some other heat exchange medium.
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What is the typical temperature difference at dehydration
column inlet between gas and glycol? Who is hotter?
TEG to gas contactor is limited from 10°F to 15°F above the inlet gas
temperature. If hotter, some TEG will vaporize with gas. If colder, gas
condensation of the hydrocarbons may cause foam and glycol loss.
The glycol temperature into the contactor must higher than the gas.
What is the regeneration temperature for TEG/DEG/MEG?
TEG: (204.4°C) or (400°F)
DEG: (177°C) or ( 350,6°F)
MEG: (163°C) or (325,4°F)
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What is the freezing temperature of TEG/DEG/MEG?
TEG: (-7°C) or (19°F)
DEG: (-10,5°C) or (13,1°F)
MEG: (-12,9°C) or (8,78°F)
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What is DRIZO Process?
DRIZO regenerates the glycol by solvent stripping instead of the conventional
gas stripping. Solvent stripping allows to obtain much higher glycol purities than
gas stripping (up to 99.998 wt% instead of the typical 99.95 wt%) and
consequently allows to get much larger water dew point depressions up to 100°C
(180°F) and even higher in some cases. The solvent required by the DRIZO
process is usually obtained from the BTEX present in the natural gas itself and in
most cases, the process will even produce some liquid hydrocarbons.
Glycol solvent stripping by condensates (instead of conventional gas stripping)
allows:

Higher glycol purities down to < 1 ppmv H2O in treated gas

Reduced BTEX / CO2 emissions

Possible recovery of liquid aromatics

DRIZO solvent is not a solvent, it is a hydrocarbon recovered from feed gas
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The Drizo regeneration system utilizes a recoverable solvent as the
stripping medium. The patent operates with iso-octant solvent, but the
typical composition of the stripping medium is about 60 wt% aromatic
hydrocarbons, 30 wt% naphthenes and 10 wt% paraffins. The threephase solvent water separator is crucial for this method.
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What is COLDFINGER Process?
TEG regeneration by Coldfinger technology has been recognized as one
of the promising processes for dehydrating natural gas.
The Coldfinger regeneration system employs a cooling coil (the
coldfinger) in the vapor space of the surge tank. The cooling that takes
place there causes condensation of a high amount of vapors. The
condensate is a water-rich TEG mixture, which is led to a further
separation process .
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The principle of the Cold Finger instrument is an inverted pipeline. The
cooled metal finger replicates the inner wall of a pipeline. The heated
and moved oil flows around it. When the finger’s temperature falls
below the Wax Appearance Temperature (WAT), wax starts to deposit on
its surface.
We use the cold finger test to calculate the efficiency of wax inhibitors.
As the piece of equipment replicates a pipeline environment, the results
we obtain are transferable to how our products would work in field
conditions. Our wax inhibitors are crude oil specific. They work via a
lock and key mechanism whereby a specific paraffin inhibitor combines
with a specific crude oil to prevent wax formation.
The test involves the immersion of a series of tubes in molten crude oil.
The temperature of the tubes is set colder than the oil, such that waxes
from the oil can deposit on the cool surfaces. The wax deposits are then
weighed. With the addition of an effective paraffin inhibitor, the weight
of the deposits should decrease and is presented as a percentage of wax
inhibition.
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How to simulate a complete glycol dehydration unit using
HYSYS?
The dehydration unit of a plant that processes natural gas uses triethylene
glycol (TEG) as an absorbent to remove water from the gas to prevent
blockages in pipes due to the formation of hydrates. Although TEG is
recyclable, it is usually lost in the system due to vaporization and
carryover, which results in economic issues.
Therefore, it is necessary to optimize the dehydration process to achieve
the allowable water concentration in the gas, to minimize the use of
energy, and to minimize the loss of TEG. We use ASPEN HYSYS to
construct and simulate the dehydration process.
The chosen affecting parameters to the process were:
- Lean glycol circulation rate.
- The temperature of the reboiler
- The number of trays in the contactor column.
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Whereas, the response parameters included:
-
The amount of glycol that was lost.
-
The reboiler duty.
-
The concentration of water in the dry gas.
-
The temperature at which the hydrate formed.
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How does KIMRAY Glycol Pumps work?
The pump does two things at the same time:

Moves wet (or rich) glycol from the contactor to the reboiler

Moves dry (or lean) glycol from the reboiler to the contactor
The pump uses energy from the wet glycol and a small quantity of gas at
contactor pressure to stroke the piston inside the pump.
High-pressure wet glycol from the contactor enters the top of the pump. It is
then diverted to the end of the piston. This causes the piston to stroke.
As the piston strokes, three additional processes occur:

the pump sends high-pressure dry glycol on the inside of the pump
cylinder out the top of one end of the pump to the contactor

the pump pulls low-pressure dry glycol from the reboiler into the cylinder
through the back of the pump

the pump sends low-pressure wet glycol from the other end of the pump to
the reboiler
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As the piston reaches the end of its stroke, a series of check valves and
d-slides switch to redirect the high-pressure wet glycol to the other end
of the piston.
This continual back-and-forth movement of the piston is what pumps
the glycol in and out of the pump to the different components of the
dehydration system.
The glycol pump does not require a power source outside of the
dehydration system.
Kimray’s Energy Exchange Glycol Pump is a durable, low-maintenance
solution for recirculation of glycol in your dehydration system
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Troubles related KIMRAY Pumps

Symptoms
-
The pump will not operate
-
The pump will start and run until the glycol returns from the
absorber. The pump then stops or slows appreciably and will not
run at its rated speed.
-
The pump operates until the system temperature is normal then the
pump speeds up and cavities.
-
The pump lopes and pumps on one side only.
-
Pumps stops and leaks excessive gas from wet glycol discharge.
-
Erratic pump speed. Pump changes speed every few minutes.
-
Broken pilot piston.
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
Causes
-
One or more of the flow lines to the pump are completely blocked
or the system pressure is too low for standard pumps (below 300
psig).
-
The wet glycol discharge line to the reboiler is restricted. A pressure
gauge installed on the line will show the restriction immediately.
-
The suction line is too small and increase in temperature and
pumping rate cavities the pump.
-
Traps in the wet glycol power piping sends alternate slugs of glycol
and gas to the pump.
-
Insufficient glycol to the main piston D-slides port. Elevate the
control valve end of the pump to correct.
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How to protect KIMRAY Pumps?
A new pump or new dehydrator should be put into operation by first
bringing the glycol circulation and operating temperature to an
equilibrium conditions by using 300 to 400 psig absorber pressure. This
can be done with or without gas flow.
The maximum operating temperature of the pump is limited by the
moving “O” ring seals. A maximum of 200 °C is recommended. Packing
life will be extended considerably at 150°C.
If a pump has been deactivated for several months, the check valves
should be removed and inspected before attempting to operate the pump.
The pump start up should be similar to that of a new pump by first
bringing the system to equilibrium.
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What are the periodic laboratory analysis we can do
on Glycol? Why?
pH: Most inhibited glycols provide a pH between 8 and 10.5. The pH
of the glycol is measured to determine if the glycol has broken down
into corrosive acids.
- Specific conductance: it will vary from a low range of 1500 µmhos
to a high range of 4500 µmhos. The higher the percent of inhibited
glycol, the higher the conductivity. Pure uninhibited glycol may have
a very low specific conductance under 100 µmhos.
- Total Iron: should be below 2 ppm. The level of total iron is tested to
determine if corrosion of mild steel or iron pipe is a concern.
- Copper: should be below 0.2 ppm. Coppers levels are also tested to
determine if corrosion of cooper pipe is a concern.
-
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Molybdenum: Molybdenum or molybdate is also used as a basic
mild steel corrosion inhibitor to provide extra protection to the
system metals. Molybdate levels may vary from a very low level of
15 ppm to a very high level of 100 ppm.
- Glycol Percent by Volume: the percent by volume should be in the
range of 20% to 40% for best protection. Levels below 20% have an
increased chance for microbiological growth causing the glycol to
break down.
- Freeze Point °F: Most freeze points are between 10°F and -10°F. A
40% solution of propylene glycol provides a -8°F freeze point
whereas a 40% solution of ethylene glycol provides a -13°F freeze
point.
- Reserve Alkalinity: A reserve alkalinity of 10 to 12 is generally
adequate. This test is designed to check the level of the buffering
agent and metal passivators that are included in the inhibited glycol
formulation.
-
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-
Orthophosphate as PO4 ppm: Ranges are typically 1000 ppm
to 5000 ppm. The inhibitor package that is included in the
inhibited glycol is dipotassium phosphate. This test, like the
reserve Alkalinity, gives the level of this inhibitor.
-
Sodium Nitrite: levels may vary from a low of 500 ppm and to
a high of 1500 ppm. Sodium nitrite is a basic mild steel
corrosion inhibitor that is used to provide extra corrosion
inhibition.
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What are the main reasons for Glycol foaming?
Excessive turbulence and high liquid-to-vapor contacting velocities can
also cause the glycol to foam. This condition may point to underlying
mechanical or chemical issues. Other causes of foam that may be present
in the process fluid include field corrosion inhibitors, salt, or finelydivided suspended solids.
How to detect Glycol foaming?
One of the most common ways glycol is lost is through foaming. Glycol
foaming happens when entrained hydrocarbons from production enter the
glycol fluid.
As the entrained glycol is processed through the contactor tower (or
absorber), it will carry over the top of the tower with the sales gas when
stable foam builds up on the trays.
Foaming also causes poor contact between the gas and the glycol,
significantly reducing the drying of the gas.
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How to prevent Glycol foaming?
To dehydrate natural gas properly, your system needs clean glycol that is free
from hydrocarbons and any other impurities. If you encounter foaming, your
first step is to lower pressure.
How to remedy Glycol foaming?
We use an anti-foaming agent to temporarily reduce the foam and continue
processing gas.
A defoamer or an anti-foaming agent is a chemical additive that reduces and
hinders the formation of foam in industrial process liquids.
-
Oil based defoamers
-
Water based defoamers
-
Poweder defoamers
-
Silicone based defoamers
-
EO/PO based defoamers
-
Alkyl polyacrylates
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What type of corrosion you might have on Glycol Units?
Why?
Corrosion problems in glycol systems are most commonly caused by
formation of organic acids which depress the glycol pH and lead to
corrosion. Apart from monitoring the pH a regular sample should be
drawn for visual inspection. Dirty amine with high suspended solids
content is an indication of filter and corrosion problems. The odour is
also a good guide to the condition of the glycol, with an aromatic odour
Another major problem with glycol systems is the build-up of salt in the
glycol. Salt dissolves in glycol which makes it corrosive. The presence of
salt is particularly damaging if stainless steels are used as materials of
construction as chloride pitting and stress corrosion cracking can occur.
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How to prevent corrosion on the Glycol units?
The feed gas coming to the dehydration system is high in hydrogen sulfide
and carbon dioxide.
At the temperatures in the lean/rich exchanger, the presence of hydrogen
sulfide and carbon dioxide can be expected to significantly increase the
corrosion rates of mild steel. The recommendation in this case was to