LNG

1. Natural Gas Pretreatment
Senior Project 2012
Liquefied Natural Gas

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Gas treating involves reduction of the “acid gases”
carbon dioxide (CO2) and hydrogen sulfide (H2S),
along with other sulfur species, to sufficiently low
levels to meet contractual specifications or permit
additional processing in the plant without corrosion
and plugging problems. This chapter focuses on acid
gases because they are the most prevalent.
Contents
1.INTRODUCTION
2.GAS-SWEETENING
PROCESSES
3.SELECTION OF SWEETENING
PROCESS
5. PHYSICAL
ABSORPTIONPROCESS IN
NATURAL GAS SWEETENING
6.HYBRID PROCESSES
7. Troubleshooting of
absorption sweetening

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1.INTRODUCTION
ACID gases like CO2, H2S and other sulphuric components are usually to
some extent present in natural gas and industrial gases. They may have
to be removed (selectively) from these gas streams it would cause
problems with Reasons for acid gas removing
1. Health hazards. At 0.13 ppm, H2S can be sensed by smell. At 4.6
ppm, the smell is quite noticeable. As the concentration increases
beyond 200 ppm, the sense of smell fatigues, and the gas can no
longer be detected by odor. At 500 ppm, breathing problems are
observed and death can be expected in minutes. At 1000 ppm, death
occurs immediately.
2. Sales contracts. Specification for LNG plants shall not contain more
than 23 mg of H2S per m3 (16 ppmv), more than 115 mg of total
Sulphur per m3 and more than 2% by volume of CO2.Specification for
pipeline should be Less than 4 ppm by volume of H2S and Less than
2% by volume of CO2
3. Corrosion problems. If the partial pressure of CO2 exceeds 15 psia,
inhibitors usually can only be used to prevent corrosion. The partial
pressure of CO2 depends on the mole fraction of CO2 in the gas and
the natural gas pressure. Corrosion rates will also depend on
temperature. Special metallurgy should be used if CO2 partial
pressure exceeds 15 psia. The presence of H2S will cause metal
embrittlement due to the stresses formed around metal sulfides
formed.
2.GAS-SWEETENING PROCESSES
There are more than 30 processes for natural gas sweetening. The
most important of these processes can be classified as follows:
Sweetening
Process
Batch solid bed absorption
Membranes
Reactive solvents
Physical solvents.
Direct oxidation to sulfur

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Acid gas removal
Chemical absorption
Amine chemical
Physical
absorption
hybrid
Solid
adsorption
membrane
1. Batch solid bed adsorption. For complete removal of H2S at low
concentrations, the following materials can be used: iron sponge, molecular
sieve, and zinc oxide. If the reactants are discarded, then this method is
suitable for removing a small amount of sulfur when gas flow rate is low
and/or H2S concentration is also low.
2. Reactive chemical solvents. MEA (monoethanol amine), DEA (diethanol
amine), DGA (diglycol amine), DIPA (di-isopropanol amine), hot potassium
carbonate, and mixed solvents. These solutions are used to remove large
amounts of H2S and CO2 and the solvents are regenerated
3. Physical solvents. Selexol, Recitisol, Purisol, and Fluor solvent they are
mostly used to remove CO2 and are regenerated.
4. Hybrid. Stretford, Sulferox LOCAT, and Claus. These processes eliminate
H2S emissions.
5. Membranes. This is used for very high CO2 concentrations. AVIR, Air
Products, Cynara (Dow), DuPont, Grace, International Permeation, and
Monsanto are some of these processes.
3. SELECTION OF SWEETENING
PROCESS
There are many treating processes available however no single process is
ideal for all applications. The initial selection of a particular process may be
based on feed parameters such as composition, pressure, temperature, and
the nature of the impurities, as well as product specifications. The second
selection of a particular process may be based on acid/sour gas percent in
the feed, whether all CO2, all H2S, or mixed and in what proportion, if CO2 is
significant, whether selective process is preferred for the SRU/TGU feed,
and reduction of amine unit regeneration duty.
FIGURE 1 SWEETENING PROCESSES

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1. Type of impurities to be removed (H2S, mercaptans)
2. Inlet and outlet acid gas concentrations.
3. Gas flow rate, temperature, and pressure.
4. Feasibility of sulfur recovery.
5. Acid gas selectivity required.
6. Presence of heavy aromatic in the gas.
FIGURE 2SELECTION OF SWEETENING PROCESS
4. Chemical Absorption Process in Natural
Gas Sweetening
It refers to the transfer of a component of a gas phase to a liquid phase in
which it is soluble Stripping is exactly the reverse-the transfer of a component
from a liquid phase in which it is dissolved to a gas phase. Absorption is
undoubtedly the single most important operation of gas purification processes
and is used widely.

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Figure 3 typical Absorption Process
4.1 Amine Processes
The most widely used for sweetening of natural gas are aqueous solutions of
alkanolamines. They are generally used for bulk removal of CO2 and H2S.
Amines are compounds formed from ammonia (NH3) by replacing one or more
of the hydrogen atoms with another hydrocarbon group. Replacement of single
hydrogen produces a primary amine, replacement of two hydrogen atoms
produces a secondary amine, and replacement of all three of the hydrogen
atoms produces a tertiary amine. Primary amines are the most reactive,
followed by the secondary and tertiary amines. Sterically hindered amines are
compounds in which the reactive center (the nitrogen) is partially shielded by
neighboring groups so that larger molecules cannot easily approach and react
with the nitrogen. The amines are used in water solutions in concentrations
ranging from approximately 10 to 65 wt% amines,
Cooled
flue gas
from
furnace
Amine
absorbs
co2 from
Amine cooled
before use
Cleaned Exhaust

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4.1.1 Process chemistry
H2s+Amine (Amine) H+
+HS-
(1)
CO2+ H2O +AMINE (AMINE) COOH+
+ OH-
(2)
CO2+ H2O+ R2NCH3 R2NCH4
+
+HCO3
-
(3)
Structural formulas for the alkanolamine are presented in Figure each has at
least one hydroxyl group and one amino group. In general, it can be
considered that the hydroxyl group serves to reduce the vapor pressure and
increase the water solubility. While the amino group provides the necessary
alkalinity in water solutions to cause the absorption of acidic gases.
Figure 4 amine stuctural formulas
4.1.1.1 Monoethanolamine
MEA is generally used as a 10 to 20 weight % solution in water. Due to
corrosion problems, the acid gas loading is usually limited to 0.3 to 0.35
moles acid gas per mole of amine for carbon steel equipment. Loadings as
high as 0.7 to 0.9 mole/mole have been used in stainless steel equipment
with no corrosion problems. Although MEA itself is not considered to be
particularly corrosive, its degradation products are extremely corrosive.
MEA reacts with oxidizing agents such as COS, CS2, SO2, SO3, and oxygen
to form the soluble products which must be removed from the circulating
system to avoid serious corrosion problems.

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The advantages of MEA include:
 Low solvent cost,
 Good thermal stability,
 Partial removal of COS and CS2, which requires a reclaimer
 High reactivity due to its primary amine character, a ¼ grain H2S
specification can usually be achieved and CO2 removal to 100
ppmv for applications at low to moderate operating pressures.
Some of the disadvantages of MEA are
 High solvent vapor pressure which results in higher solvent
losses than the other alkanolamine,
 Higher corrosion potential than other alkanolamine
 High energy requirements due to the high heat of reaction with
H2S and CO2,
 Nonselective removal in a mixed acid gas system, and Formation
of irreversible degradation products with CO2, COS and
CS2,which requires continuous reclaiming
4.1.1.2 Diethanolamine
Probably the most widely employed gas treating solvent, DEA
being a secondary amine I generally less reactive than MEA.
Applications with appreciable amounts of COS and CS2 besides
H2S and CO2, such as refinery gas streams, can generally be
treated successfully.
Advantages of DEA are:
 Resistance to degradation from COS and CS2,
 Low solvent vapor pressure which results in potentially lower
solvent losses,
 Reduced corrosive nature when compared to MEA, and
 Low solvent cost.
Disadvantages of DEA:
 Lower reactivity compared to MEA and DGA Agent,
 Essentially nonselective removal in mixed acid gas systems due
to inability to slip an appreciable amount of CO2.
 Higher circulation requirements

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4.1.1.3 Diglycolamine
DGA is generally used as a 50 to 70 weight % solution in water. As with
MEA, the corrosion problems with DGA prevent solution loadings above
about 0.35 mole/mole. Sweetening of gas streams containing high acid gas
partial pressures can result in absorber bottoms temperatures in excess of
200o
F. DGA has a tendency to preferentially react with CO2 over H2S. It also
has a higher pH than MEA and thus can easily achieve quarter grain H2S
specification except in some cases where large amounts of CO2 are present
relative to H2S.
Advantages of DGA:
 Capital and operating cost savings due to lower circulation requirements
 Removal of COS and CS2,
 High reactivity, ¼ grain H2S specification can generally be obtained for
applications with low operating pressures and high operating temperatures
 Enhanced mercaptans removal in comparison to other alkanolamines,
 Excellent thermal stability.
Disadvantages of DGA:
 Nonselective removal in mixed acid gas systems,
 Absorbs aromatic compounds from inlet gas which potentially
Complicates the sulfur recovery unit design,
 Higher solvent cost relative to MEA and DEA.
4.1.1.4 Methyldiethanolamine
MDEA is commonly used in the 20 to 50 wt % range. Lower weight %
solutions are typically used in very low pressure, high selectivity
applications such as a SCOT tail gas cleanup unit. Due to considerably
reduced corrosion problems, acid gas loadings as high as 0.7 to 0.8
mole/mole are practical in carbon steel equipment. Higher loadings may
be possible with few problems.

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Advantages of MDEA and the formulated MDEA solvents
are:
 Selectivity of H2S over CO2 in mixed acid gas applications,
Essentially complete H2S removal while only a portion of
CO2 is removed enriching the acid gas feed to the sulfur
recovery unit (SRU).
 Low vapor pressure which results in potentially lower solvent
losses,
 Less corrosive,
 High resistance to degradation, and
 Efficient energy utilization (capital and operating cost savings).
The disadvantages of MDEA:
 Highest solvent cost relative to MEA, DEA and DGA Agent,
 Lower comparative reactivity,
 Non-reclaimable by conventional reclaiming techniques, and
 Minimal COS, CS2 removal
4.1.1.5 Mixed Amines:
Mixtures of amines are generally mixtures of MDEA and DEA or MEA and are
used to enhance CO2 removal by MDEA, as described by Polasek, Bullin, and
Iglesias-Silva (1992). Such mixtures are referred to as MDEA-based amines with
DEA or MEA as the secondary amine. The secondary amine generally comprises
less than 20% of the total amine on a molar basis .At lower concentrations of
MEA and DEA, the overall amine concentration can be as high as 55 wt %
without the implementation of exotic metal equipment.
The advantages of mixed Amines
 MDEA-based mixtures are normally used to increase the CO2 pickup
 Amine mixtures are particularly useful for lower pressure applications
since the MDEA becomes less capable of picking up sufficient CO2 to
meet pipeline specifications at lower pressures.
 At higher pressures, amine mixtures appear to have little or no
advantage over MDEA Mixed amines are also useful for cases Where
the CO2 content of the feed gas is increasing over time due to field aging.

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4.1.2 Different Amine configurations
4.1.2.1 Simple Flow System
Gas to be purified is passed upward through the absorber, countercurrent to
a stream of the solution. The rich solution from the bottom of the absorber is
heated by heat exchange with lean solution from the bottom of the stripping
column and is then fed to the stripping column at some point near the top. In
units treating sour hydrocarbon gases at high pressure; it is customary to
flash the rich solution in a flash drum maintained at an intermediate pressure
to remove dissolved and entrained hydrocarbons before acid gas stripping.
When heavy hydrocarbons condense from the gas stream in the absorber
the flash drum may be used to skim off liquid hydrocarbons as well as to
remove dissolved gases Lean solution from the stripper, after partial cooling
in the lean-to-rich solution heat exchanger, is further cooled by heat
exchange with wafer or air, and fed into the top of the absorber to complete
the cycle Acid gas that is removed from the solution in the stripping column
FIGURE 5BASIC FLOW SCHEME

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4.1.2.2 Split-Stream Cycles (Modification)
The rich solution from the bottom of the absorber is split into two streams, one
being fed to the top of the stripping column and one to the midpoint. The top
stream flows downward countercurrent to the stream of vapors rising from the
reboiler and is withdrawn at a point which is above the inlet of the second
portion of the rich solution. The liquid withdrawn from the upper portion of the
stripping column is not completely stripped and is recycled back to the
absorber to absorb the bulk of the acid gases in the lower portion of the
absorber column. The portion of solution, which is introduced near the
midpoint of the stripping column, flows through the reboiler and is very
thoroughly stripped of absorbed acid gases. This solution is returned to the top
of the absorber where it serves to reduce the acid gas content of the product
gas to the desired low level. In this system, the quantity of vapors rising
through the stripping column is somewhat less than that in a conventional
plant. However, the ratio of liquid to vapor is lower in both sections because
neither carries the total liquid stream.
A simplified form of the split-stream cycle consists of dividing the lean solution
before introduction into the absorber into two unequal streams. The larger
stream is fed to the middle of the absorber, while the smaller stream is
introduced at the top of the column
In cases where gases of high acid-gas concentration are treated, this
scheme may be more economical than the basic flow scheme, as the
diameter of the top section of the absorber may be appreciably smaller than
that of the bottom section Furthermore, the lean solution stream fed to the
middle of the absorber may not have to be cooled to as low a temperature
as the stream flowing to the top of the column, resulting in reduction of heat
exchange surface.

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FIGURE 6SPLIT-STREAM CYCLES
4.1.2.3 Cocurrent Absorption
With Cocurrent absorbers, the highest gas purity attainable is represented
by equilibrium between the product gas and the product (rich) solution.
When an irreversible reaction occurs in the liquid phase, the equilibrium
vapor pressure of acid gas over the solution is negligible and Cocurrent
contactors can yield high removal efficiencies
FIGURE 7 COCURRENT ABSORPTION

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4.1.3 Process Flow lines and equipments
Amine systems tend to be located in a central plant to service the entire sour
gas production for a field.
Inlet Separator
 Removal of liquids and/or solids
 Separator should be sized to handle surge capacity. Poor separator
design can cause problems in the treating facilities.
Contactor
 Sour gas enters the bottom of the tower and moves upward through the
trays
 H2S and CO2 in the gas react with the liquid amine solution and are
removed from the gas stream.
 The reaction is often assisted by placing fresh lean amine on various
trays down the tower. This ensures that the gas will contact lean amine a
few times as it moves up the tower.(This is not shown on the diagram).
 As the sweet gas leaves the tower, it is often contacted with water to
remove any amine that has vaporized and is travelling with the gas. The
top 2 or 3 trays may be used for this function. This is considered a ―water
wash‖ section of the tower.
Outlet Separator
 The sweetened gas is passed through a separator to remove any amine
solution (or liquid water) that may be travelling with the gas flow
 The gas is now saturated with water and must proceed through
dehydration facilities to lower the water dew point before sale.
Flash Drum
 From the contactor, the amine may enter a flash drum to allow any
hydrocarbon an opportunity to leave the amine solution.
Heat Exchanger (HTEX)
 The rich amine passes through a heat exchanger where it picks up heat
from the hotter lean amine on its way to the contactor.
 Since this service is clean, plate and frame exchangers can be used, but
often a more common shell and tube exchanger is put in service.

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Stripper
 The rich amine enters the stripper, where hot acid gas and steam heat
the rich amine, removing the H2S and CO2 that is bound into the
product.
Reboiler
 The amine at the bottom of the stripper tower is heated to 105oC –
140oC (depending on the type of amine being used).
 This causes the acid gas/amine reaction to reverse and the acid gas
vaporizes with steam from the amine solution.
 The acid gas/steam vapor re-enters the stripper and contacts new rich
amine on its way out the top. Amine carried with the acid gas/steam
vapor tends to reunite with the rich liquid amine thereby removing it from
the vapor flow.
Condenser
 After leaving the top of the stripper tower, the acid gas/steam vapor is
cooled to remove heat and condense out the water from the flow.
 The water is separated in a reflux drum and returned to the stripper
tower as a liquid.
 The acid gas vapor is sent downstream to a Sulphur Recovery Unit
(SRU).
 If the plant has a gas sulphur inlet rate of less than 1 tonne/day (this is a
very small amount), the acid gas may be incinerated. Burning the H2S
creates SO2 which is a monitored pollutant.
Reclaimer
 Amines react with CO2 and contaminants, including oxygen, to form
organic acids.
 These acids then react with the basic amine to form heat stable salts
(HSS). As their name implies, these salts are heat stable, accumulate in
the amine solution, and must be removed.
 For MEA and DGA solutions, the salts are removed through the use of a
reclaimer, which utilizes a semi continuous distillation process. The
reclaimer is filled with lean amine, and strong base, such as sodium
carbonate or sodium hydroxide, is added to the solution to neutralize the
heat stable salts.
 A slipstream of 1 to 3% of the circulating amines then continuously added
to the reclaimer while the mixture is heated. Water and amine vapor are
taken off the top, which leaves the contaminants in the liquid bottoms

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.Rich Amine
 The amine picks up H2S and CO2 in the contactor tower.
Lean Amine
 A lean amine stream from the bottom of the reboiler (or bottom of
the tower) is pumped back to the contactor.
 The lean amine is often passed through a charcoal filtration system
to remove entrained solids
 If anti-foam additives are added to the system, the charcoal filters
will remove them, so they should be taken off-line during addition.
 The lean amine must be cooled to approximately 6oC warmer than
the inlet gas temperature before it enters the contactor.
4.2 Chemical ALKALI SALTS Absorption
The hot potassium carbonate process for removing CO2 and H2S was
developed by the United States Bureau of Mines and is described by Benson
and coworkers in two papers (Benson et al., 1954, 1956). Although the process
was developed for the removal of CO2, it can also remove H2S if H2S is present
with CO2. Special designs are required for removing H2S to pipeline
specifications or to reduce CO2to low levels. The process is very similar in
concept to the amine process, in that after physical absorption into the liquid,
The CO2 and H2S react chemically with the solution. The chemistry is relatively
complex, but the overall reactions are rep-resented by
K2CO3 + CO2 + H2O ↔ 2KHCO3
K2CO3 + H2S ↔ KHS + KHCO3
In a typical application, the contactor will operate at approximately 300 psig (20
bar), with the lean carbonate solution entering near 225°F (110°C) and leaving
at 240°F (115°C). The rich carbonate pressure is reduced to approximately 5
psig(0.3 barg) as it enters the stripper. Approximately one third to two thirds of
the absorbed CO2 is released by the pressure reduction, reducing the amount
of steam required for stripping. The lean carbonate solution leaves the stripper
at the same temperature as it enters the contactor, and eliminates the need for
heat exchange between the rich and lean streams. The heat of solution for
absorption of CO2 in potassium carbonate is small, approximately 32 Btu/cu ft
ofCO2, and consequently the temperature rise in the contactor is small and less
energy is required for regeneration.

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FIGURE 8 ALKALI SAULTS PROCESS
5. PHYSICAL ABSORPTION PROCESS IN
NATURAL GAS SWEETENING
Selexol is a typical application of physical absorption and a number of
open literature articles describe the process. Consequently, it was
selected as an example to describe the absorption process. The handbook
of Kohl and Nielsen (1997) provides information on other absorption
processes
Selexol is a polyethylene glycol and has the general formula:
CH3—O—CH2—(CH2—O—CH2)N—CH2—O—CH3
varied and, consequently, no common
process flow diagrams are available. Sweeny (1980) presents flow
diagrams for nine different applications, and Epps (1994) discusses plants
for the dehydration of natural gas and hydrocarbon dew point control. One
plant discussed by Epps (1994), designated only as a European
distribution plant, is shown in. This plant was selected for discussion
because it is a modern application, and both inlet and outlet gas
compositions2 were reported) the plant pretreats the gas to reduce CO 2

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FIGURE 9:SOLUBILITY OF VARIOUS GASES IN SELEXOL SOLVENT AT 70°F (21°C) AS A FUNCTION
OF PARTIAL PRESSURE
FIGURE 10SELEXOL

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6. HYBRID PROCESSES
To take advantage of the strengths of each type of amine and physical
solvent, a number of hybrid processes commercially used, and under
development, combine physical solvents with amines.
Depending upon the solvent−amine combination, nearly complete removal
of H2S, CO2, and COS is possible. Other hybrid systems provide high H2S
and COS removal while slipping CO2. Sulfino currently is one of the more
commonly used processes. The process uses combination of a physical
solvent (sulfolane) with DIPA or MDEA
7. Troubleshooting of absorption sweetening
General operating problems in the amine system are centered
around the following five major areas:-
1. Amine loss from the system.
2. Amine foaming problem.
3. Corrosion problem.
4. Concentration of residual gas in lean amine solution.
5. Winterization.
7.1 Amine loss from the system
A certain amount of MDEA will be continuously lost from the
amine sweetening system due to the vapor pressure of the amine. The
largest amine losses are usually through the amine absorber as carry
over with the treated gas. Some amine is also lost through the amine
stripper, amine flash tank, pumps packing etc.
Here is some guidance to help in minimizing the amine solution losses
from the system:
 Maintain the top temperature of the amine absorber as low as
possible.
 Maintain proper amine solution concentration.
 Ensure good clean amine solution - good filtration, proper
reboiler control to avoid chemical breakdown of amine and avoid
all amine contamination.

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Figure 11 Amine loss places
7.2 Amine foaming
Foaming is a common problem that results in a decrease of treating
capacity of the plant and amine losses. It is usually detected by a sharp
rise in the pressure drop across the amine absorber.
Foaming can be prevented in the following ways:
 Do not overload the inlet separator in your plant.
 Avoid condensation of liquid hydrocarbons in the amine absorber by
keeping the temperature in the absorber above the hydrocarbon dew
point.
 Keep field corrosion inhibitors, soap based lubricants and lube oil out
of the amine system.
 Degradation of amine can cause foaming, so avoid it by preventing
oxidation and by proper reboiler control.
 Maintain the charcoal filter in good working condition, because this
filters which absorbs the liquid contaminants.
 If these remedies fail, try a de-foaming agent and evaluate the
results.
 Always keep in mind that the de-foamers are only a temporarily
answer for the foaming problem, and the best cure for the problem is
to avoid the main causes.

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7.3 Corrosion problem
Corrosion problem is commonly encountered in the amine system and
generally occurs in the amine regenerator, heat exchanger, amine stripper
and amine pumps etc. Most corrosion occurs in areas where the acid
gases are actually released from the solution i.e. in the reboiler, stripper
tower and its overhead systems.
Corrosion problems can be minimized by the following practices:
o Keep the amine solution clean. Do not over load the inlet
separator, which prevents solids entering in the system. Other
solids that contribute to corrosion are removed by amine filters.
So, it's very important to maintain a good amine filtration system.
o The presence of air will cause the amine to degrade into heat
stable salts, so there should be a gas blanket on all the amine
storage tanks to exclude air.
o Maintain acid-gas loading within the proper ranges.
o Corrosion problems become severe at high temperatures with
the rich amine solutions, so keep the amine solution concentration
up to the recommended value.
o Amine reboiler temperature should be kept at the recommended
range to avoid any amine decomposition or any extra water losses
which will affect the amine solution concentration.
7.4 Concentration of residual gas in lean amine
solution
The Concentration of residual gas in the lean amine solution should be
controlled at a specified level for the plant. This is the gas which remains
in the MDEA solution at all times.
 The amount of residual acid gas in the solution depends upon the
heat used in the stripper reboiler. Increasing the heat reduces the
residual acid gas and vice versa.
 If the concentration of residual gas is low then more acid gas can
be absorbed by the lean amine solution in the absorber. This will
also, allow a reduction in the circulation rate of the amine solution.
 If the inlet sours gas rate changes, the amine solution flow rate
and the reboiler heat should be changed in same proportion to
match the sour gas changes.

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8. Thermal effects in absorption
Considerable heat is released by the absorption and subsequent reaction of the
acid gases in the amine solution. A small amount of heat may also be released
(or absorbed) by the condensation (or evaporation) of water vapour. To avoid
hydrocarbon condensation the lean solution is usually fed into the top of the
absorber at a slightly higher temperature than that of the sour gas, which is fed
into the bottom. As a result, heat would be transferred from the liquid to the gas
even in the absence of acid gas absorption. The heat of reaction is generated in
the liquid phase, which raises the liquid temperature and causes further heat
transfer to the gas.
However, the bulk of the absorption (and therefore heat generation) normally
occurs near the bottom of the column, so the gas is first heated by the liquid
near the column bottom, and then cooled by the incoming lean solution near the
top.
When gas streams containing relatively large proportions of acid gases (over
about 5%) are purified, the quantity of solution required is normally so large that
the purified gas at the top of the column is cooled to within a few degrees of the
temperature of the lean solution.
In such cases essentially all of the heat of reaction is taken up by the rich
solution, which leaves the column at an elevated temperature. This temperature
can be calculated by a simple heat balance around the absorber.
A typical temperature profiles for an absorber (Glycol-amine system, similar
profile observed for MEA & DGA plants also) of this type is shown in Figure 12.
The temperature ―bulge‖ is a result of the cool inlet gas absorbing heat from the
rich solution at the bottom of the column ,and then later losing this heat to the
cooler solution near the upper part of the column. The size, shape, and location
of the temperature bulge depend upon where in the column the bulk of the acid
gas is absorbed, the heat of reaction, and the relative amounts of liquid and gas
flowing through the column. In general, for CO2 absorption, the bulge is sharper
and lower in the column for primary amines, broader for secondary amines, and
very broad for tertiary amines, which absorb CO2 quite slowly and also have a
low heat of solution.

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FIGURE 12: TEMPERATURE PROFILE FOR ABSORBER

25. 93
9. Adsorption Process of Natural Gas
Sweetening
Acid gases, as well as water, can be effectively removed by physical
adsorption on synthetic zeolites. Applications are limited because water
displaces acid gases on the adsorbent bed. Molecular sieve can reduce H2S
levels to the 0.25 gr/100 scf (6 mg/m3) specification. However, this reduction
requires regeneration of the bed at 600°F (315°C) for extended time
9.1 Zinc Oxide
Zinc oxide can be used instead of iron oxide for the removal of H2S, COS,CS2,
and mercaptans. However, this material is a better sorbent and the exit H2S
concentration can be as low as 1 ppm at a temperature of about 300 C. The
zinc oxide reacts with H2S to form water and zinc sulfide:
A major drawback of zinc oxide is that it is not possible to regenerate it to Zinc
oxide on site, because active surface diminishes appreciably b sintering. Much
of the mechanical strength of the solid bed is lost due to fines formation,
resulting in a high-pressure-drop operation. The process has been decreasing
in use due to the above problems and the difficulty of disposing of zinc sulfide;
Zn is considered heavy metal.
Solid
Bed
#
3
Solid
Bed
#
2
Solid
Bed
#
1

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9.2 Iron Sponge
Iron sponge fixed-bed chemical absorption is the most widely used batch
process. This process is applied to sour gases with low H2S concentrations
(300 ppm) operating at low to moderate pressures (50–500 psig). Carbon
dioxide is not removed by this treatment. The inlet gas is fed at the top of
the fixed-bed reactor filled with hydrated iron oxide and wood chips. The
basic reaction is the formation of ferric sulfide when H2S reacts with ferric
oxide:
The reaction requires an alkalinity pH level 8–10 with controlled injection of
water. The bed is regenerated by controlled oxidation as
9.3 Molecular Sieves
Molecular sieves (MSs) are crystalline sodium alumina silicates and have
very large surface areas and a very narrow range of pore sizes. Molecular
sieve processes can be used for removal of sulfur compounds from gas
streams removal of sulfur compounds from gas streams Hydrogen sulfide
can be selectively removed to meet 5.7 mg/m3 specification. The sieve bed
can be designed to dehydrate and sweeten simultaneously. In addition,
molecular sieve processes can be used for CO2 removal.
In general, the concentrations of acid gas are such that cycle times are in
the order of 6-8 hours. To operate properly the sieves must be regenerated
at a temperature close to 315°C for a long enough period of time to remove
all adsorbed materials, usually one hour or more. Exact arrangement of the
regeneration cycle depends upon process conditions.
Regeneration of a molecular sieve bed concentrates the H2S into a small
regeneration stream which must be treated or disposed of. During the
regeneration cycle, the H2S will exhibit a peak concentration in the
regeneration gas. The peak is approximately 30 times the concentration of
the H2S in the inlet stream. Knowing the concentration of this stream is
essential for the design of a gas treated for the regeneration gas. For small
units, peak flare regeneration is used. In the operation, the peak sulfur
conce ntration is flared while the rest of the regeneration stream is recycled
to the feed stream.

27. 95
10. New Acid Gas Removal Technologies
10.1Membrane Process
Gas treating membrane systems provide a safe and efficient option for
carbon dioxide and water vapor removal from natural gas, especially in
remote locations. Membrane systems are extremely adaptable to
various gas volumes, CO2 concentrations, and/or product-gas
specifications. A spiral wound cellulose acetate membrane unit offers
the greatest efficiency per Mcf of product removed compared to any
other competing CO2 removal system.
Membrane chosen for other advantages;
1. zero emissions is added benefit
2. 65% less capital cost than amine unit
3. About 10% operating cost (compared to amine)
4. 1/3 footprint of amine unit
5. About 10% operator man hours (compared to amine
6. Less noise
7. Less process upsets
8. Less additional infrastructure construction.

28. 96
10.2 Membrane Technology Applications
• Operating pressures over 450 psig
• High concentrations of CO2
• Limited power availability
• Space and weight restrictions (i.e. offshore
• Transitional treating applications

29. 97
11. ACID GAS DISPOSAL
What becomes of the CO2 and H2S after their separation from the natural
gas? The answer depends to a large extent on the quantity of the acid
gases.
For CO2, if the quantities are large, it is sometimes used as an injection fluid
in EOR (enhanced oil recovery) projects. Several gas plants exist to support
CO2 flooding projects; the natural gas and NGL are valuable byproducts. If
this option is unavailable, then the gas can be vented, provided it satisfies
environmental regulations for impurities.
In the case of H2S, four disposal options are available:
1. Incineration and venting, if environmental regulations regarding
2. sulfur dioxide emissions can be satisfied
3. Reaction with H2S scavengers, such as iron sponge
4. Conversion to elemental sulfur by use of the Claus or similar process
5. Disposal by injection into a suitable underground formation.
FIGURE 13:CLAUS PROCESS FOR SULFUR RECOVERY

30. 98
Reference
1. Baker, R.W., Future directions of membrane gas separation
technology, Ind. Eng. Chem. Res. 41, 1391, 2002.
2. Baker, R.W., Wijmans, J.G., and Kaschemekat, J.H., The
design of vapor-gas separation
3. systems, J. Membrane Sci. 151, 55, 1998. Benson, H.E., Field,
J.H., and Jimeson, R.M., CO2 absorption employing hot
potassium
4. carbonate solutions, Chem. Eng. Progress, 50, 356, 1954.
Benson, H.E., Field, J.H., and Haynes, W.P., Improved
process for CO2 absorption uses hot carbonate solutions,
Chem. Eng. Progress, 52, 433, 1956.
5. Chi, C. W. and Lee, H., Natural gas purification by 5A
molecular sieves and its design method, AIChESymp. Ser.,
69, 95, 1973.
6. Tennyson, R.N. and Schaaf, R.P., Guidelines can help choose
proper process for gastreating plants, Oil Gas J., 75 (2) 78,
1977.
7. Veroba, R. and Stewart, E., Fundamentals of Gas Sweetening,
Proceedings of the Laurance

31. 99
The water content of natural gas is an important
parameter in the design of facilities for the
production, transmission, and processing of natural
gas. It is important for natural gas engineers to
accurately predict aqueous dew points.
The removal of water, or dehydration, is done to
prevent hydrate formation (and potential plugging)
or corrosion in the gas gathering, transmission
system, or processing plant. This chapter introduces
the concepts of different gas dehydration methods. Contents
1. INTRODUCTION
2. GAS HYDRATES
3. Dehydration methods
4. Troubleshooting of Glycol
Dehydration Unit

32. 100
1. INTRODUCTION
Natural gas dehydration is the process of removing water vapor
from the gas stream to lower the dew point of that gas. Water is the
most common contaminant of hydrocarbons. It is always present in
the gas–oil mixtures produced from wells. The dew point is defined
as the temperature at which water vapor condenses from the gas
stream. The sale contracts of natural gas specify either its dew point
or the maximum amount of water vapor present. Sales gas often has
to meet the maximum water content of 7 lb (H2O) per MMscf / 1.12 x
10-4
kg/m3
or 112 ppm(w/v). There are three basic reasons for the
dehydration of natural gas streams:
1. To prevent hydrate formation. Hydrates are solids formed by
the physical combination of water and other small molecules of
hydrocarbons. They are icy hydrocarbon compounds of about 10%
hydrocarbons and 90% water. Hydrates grow as crystals and can
build up in orifice plates, valves, and other areas not subjected to full
flow. Thus, hydrates can plug lines and retard the flow of gaseous
hydrocarbon streams. The primary conditions promoting hydration
formation are the following:
 Gas must be at or below its water (dew) point with ‗‗free‘‘ water
present.
 Low temperature.
 High pressure.
2. To avoid corrosion problems. Corrosion often occurs when liquid
water is present along with acidic gases, which tend to dissolve and
disassociate in the water phase, forming acidic solutions. The acidic
solutions can be extremely corrosive, especially for carbon steel, which is
typically used in the construction of most hydrocarbon processing facilities.
3. Downstream processing requirements. In most commercial
hydrocarbon processes, the presence of water may cause side reactions,
foaming, or catalyst deactivation consequently; purchasers typically
require that gas and liquid petroleum gas (LPG) feedstock's meet certain
specifications for maximum water content. This ensures that water-based
problems will not hamper downstream operations. In addition to that the
water can condense in the pipeline causing slug flow. in general, water
vapor increase the gas volume and decrease the heating value.

33. 101
2 . Water content of natural gas streams
Solubility of water increases with temperature and decreases with
pressure. Salt's presence in the liquid water reduces the water content
of the gas. Water content of untreated natural gases is normally in the
magnitude of a few hundred pounds of water per million standard cubic
foot of gas (lbm/MMscf); while gas pipelines normally require water
content to be in the range of 6-8 lbm/MMscf and even lower for
pipelines in deep water. The water content of natural gas is indirectly
indicated by the dew point, defined as the temperature at which the
natural gas is saturated with water vapor at a given pressure. At the
dew point, natural gas is in equilibrium with liquid water; any decrease
in temperature or increase in pressure will cause the water vapor to
begin condensing. The difference between the dew point temperature
of a water saturatedgas stream and the same stream after it has been
dehydrated is called dew-point depression.
2.1 Determination the water content of saturated
natural gas:
The water content of natural gas depends on:-
1. Temperature. 2. Pressure. 3. Composition.

34. 102
FIGURE 14: WATER CONTENT OF HYDROCARBON GASES AS A FUNCTION OF TEMPERATURE AND

35. 103
3. GAS HYDRATES
A hydrate is a physical combination of water and other small molecules
to produce a solid which has an ―ice-like‖ appearance but possesses a
different structure than ice. Their formation in gas and/or NGL systems
can plug pipelines, equipment, and instruments, restricting or interrupting
flow.
The presence of H2S in natural gas mixtures results in a substantially
warmer hydrate formation temperature at a given pressure. CO2, in
general, has a much smaller impact and often reduces the hydrate
formation temperature at fixed pressure for a hydrocarbon gas mixture.
The conditions which affect hydrate formation are:
Primary Considerations
 Gas or liquid must be at or below its water dew point or saturation
condition (NOTE: liquid water does not have to be present for
hydrates to form)
 Temperature
 Pressure
 Composition
Secondary Considerations
 Mixing
 Kinetics
 Salinity
In general, hydrate formation will occur as pressure increases and/or
temperature decreases to the formation condition.
3.1 Hydrate properties
Gas hydrates are a class of solid, nonstoichiometric compounds called
clathrates. They form when a host material, water for hydrates through
hydrogen bonding, forms a caged structure that contains guest
molecules, such as methane.

36. 104
FIGURE 15 HYDRATE FORMATION CONDITIONS FOR PURE METHANE, ETHANE, AND PROPANE
FIGURE 16 PRESSURE-TEMPERATURE CURVES FOR HYDROCARBON

37. 105
4. Dehydration Methods
The most common dehydration methods used for natural gas processing are as
follows:
4.1. ABSORPTION (GLYCOL DEHYDRATION
PROCESS)
The basic principles of relevance to the absorption process are as
follows:
1. In this process, a hygroscopic liquid is used to contact the wet gas to
remove water vapor from it. Triethylene glycol (TEG) is the most common
solvent used.
2. Absorption, which is defined as the transfer of a component from the gas
phase to the liquid phase, is more favorable at a lower temperature and
higher pressure.
3. If temperature decreases the water vapor concentration in the gas
decreases, allowing more absorption of water in the liquid phase.
FIGURE 17:DEHYDRATION METHODS
Using Liquid solvent of (TEG, DEG,
TEG)
Using Solid bed of:
Alumina, Molecular sieves, silica Gel, CaCl
Turbo Expansion, External cooling
or Refrigeration
Using Chemical of (Methanol, Glycol)

38. 106
4. Two means are provided to accomplish the task of absorption with a
countercurrent flow of the feed natural gas and liquid (solvent or
glycol):
 Tray column, or stage wise operation (equilibrium concept)
 Packed column or continuous-contact operation (rate concept)
5. This countercurrent system allows for the ‗‗wet‘‘ gas to enter the
bottom of the column and contact the rich glycol (high water content)
at its exit point. On the other hand, as the gas works its way up the
column, it encounters the leanest glycol (lowest water content) before
the gas leaves the column.
The wet natural gas enters the absorption column (glycol contactor)
near its bottom and flows upward through the bottom tray to the top
tray and out at the top of the column. Usually six to eight trays are
used. Lean (dry) glycol is fed at the top of the column and it flows
down from tray to tray, absorbing water vapor from the natural gas.
The rich (wet) glycol leaves from the bottom of the column to the
glycol regeneration unit. The dry natural gas passes through mist
mesh to the sales line.
The glycol regeneration unit is composed of a reboiler where steam
is generated from the water in the glycol. The steam is circulated
through the packed section to strip the water from glycol. Stripped
water and any lost hydrocarbons are vented at the top of the
stripping column. An emissions separator removes dissolved gases
from the warm rich glycol (about 90% of the methane and 10 to 40%
of the VOCs entrained in the glycol) and reduces VOC emissions
from the still The hydrocarbon losses are usually benzene, toluene,
xylene, and ethyl benzene (BTXE) and it is important to minimize
these emissions. The rich glycol is preheated in heat exchangers,
using the hot lean glycol, before it enters the still column of the glycol
reboiler. This cools down the lean glycol to the desired temperature
and saves the energy required for heating the rich glycol in the
reboiler.

39. 107
FIGURE 18 : TYPICAL GLYCOL DEHYDRATION PFD
Detailed Description of the process
 Wet gas goes through the separator to remove contaminants and
then enters the bottom of an absorption tower.
Contaminant Problems
Free Water Increases glycol recirculation, reboiler heat duty, and fuel costs. If
the dehydration system becomes overloaded with water,
glycol can carry over from the contactor and/or still .Sales
gas specification may not be achieved
Hydrocarbons Reduce the drying capacity of the glycol With water present, can
cause foaming, Un dissolved oils can Plug absorber trays,
Foul heat transfer surfaces in the reboiler, Increase the
viscosity of the glycol and Light hydrocarbons can flash in
the stripping column and cause loss of glycol and/or damage
to the packing
Brine Dissolves into glycol , Corrodes steel, especially stainless steel.
Deposits on reboiler fire tubes, causing hot spots and
firetube burnout
Downhole
Additives
Cause foaming, corrosion, and, if they deposit on fire tubes, hot
spots
Solids Promote foaming , Erode valves and pumps , eventually plug trays
and packing
TABLE 1: PROBLEMS OF CONTAMINENTS

40. 108
 Lean glycol is pumped into the top of the absorption tower. Inside the
tower, the glycol cascades down a series of levels (trays). The wet gas
rises and bubbles up through each level (tray) of flowing glycol. Bubble
caps on each level allow the gas to pass upward without allowing the
glycol to pass through. The glycol drains down through tubes called down
comers
 The gas (now dry) flows out the top of the contactor for further treatment.
 The glycol, now a water-rich solution, is dumped from the bottom.
 The water-rich glycol is pumped through the glycol surge tank/heat
exchanger.
 The surge tank helps to regulate the glycol level in the reboiler to minimize
fire tube damage due to a low glycol level.
 The surge tank also contains preheat coils. These coils are used to begin
the process of heating the glycol.
 From the surge tank, the glycol is dumped through a wet–glycol filter.
 The filter removes particulates and other impurities from the glycol.
NOTE: The purpose of this system component is to remove the major portion
of gas/condensate trapped in the glycol before the glycol enters the reboiler.
 From the gas/glycol/condensate separator, the wet glycol flows into the
reboiler.
 A burner fires a gas flame into the fire tube in the bottom of the vessel.
 A wire mesh protective barrier called a flame arrestor allows air to flow into
the fire tube while confining the flame within the tube.
 The wet glycol is heated until the water content boils and turns into steam.
NOTE: Water boils at around 212 °F and glycol does not boil until it reaches
549 °F. If the wet glycol is heated to an appropriate temperature, the water
separates from the glycol in the form of vapor while the glycol remains a
liquid.
 The water vapor is vented upward through a column on the top of the
reboiler called the stripper

41. 109
 Inside the stripper, the rising vapor is stripped of any glycol content with
the help of a coil called a reflux condenser. This process of removing any
glycol from the vapor is called fractionation.
 The vapor, now almost pure water, is vented out the top.
 The glycol, now dry, is drained from the bottom of the reboiler.
 During the reboiling process, glycol picks up bits of scale and other
particulates and must be subsequently pumped through a strainer before
reentering the absorption tower.
 The glycol entering the top of the absorption tower is still hot from the
reboiler.
FIGURE 19 : TYPICAL GLYCOL DEHYDRATION UNIT
4.1.1 Glycols Used in Dehydration
In practice, the glycols, ethylene glycol (EG), diethylene glycol (DEG),
triethylene glycol (TEG), tetraethylene glycol (TREG) and propylene glycol
are the most commonly used absorbents; triethylene glycol is the glycol of
choice in most instances. For operations in which frequent brine carryover
into the contactor occurs, operators use EG because it can hold more salt
than the other glycols. The solubility of sodium chloride in EG water mixtures
is around 20 wt, whereas it is only around 5 wt% in TEG.

42. 110
TABLE 2 COMPARISON BETWEEN DEG & TEG
Diethylene Glycol Triethylene Glycol
– Lower Cost – Higher Cost
– 328° Thermal
Decomposition
– 404° Thermal
Decomposition
– 474° Boiling Point – 550° Boiling Point
– 92% - 94% Regeneration – 928% - 99.5% Regeneration
– Higher Operating Cost – Lower Operating Cost
– Higher Capital Cost – Lower Capital Cost
4.1.2 Troubleshooting of Glycol Dehydration Unit
4.1.2.1 Glycol Loss
Glycol loss constitutes one of the most important operating problems of
dehydration units. Most of this loss occurs as carry-over of solution with
the product gas, although a small amount of glycol is lost by vaporization
into the gas stream. An additional small amount is always lost through
mechanical leakage, and some may be lost with the vapors leaving the
regenerator. By careful plant operation, total glycol losses can be
maintained below 0.5 lb/MMscf of gas treated; however, a loss of 1
1blMMscf is sometimes considered acceptable.
Since the major glycol loss is by entrainment, any design or operating
action which reduces this item can result in a considerable improvement
in plant economics.
4.1.2.2 Foaming
Excessive entrainment can usually be traced to foaming in the contactor.
It has been found that foaming can result from contamination of the
glycol with hydrocarbons, finely divided solids, or salt water brought in
with the feed gas. It is important, therefore, that the incoming gas be
passed through an efficient separator before it contacts the glycol and
that the circulating stream of glycol be maintained in a clean condition.

43. 111
4.1.2.3 Corrosion
Corrosion can be a serious problem in the operation of glycol dehydration
plants. Since the pure glycol solutions are themselves essentially non-corrosive
to carbon steel, it is generally believed that the corrosion is accelerated by the
presence of other compounds that may come from the oxidation or thermal
decomposition of the glycol, or enter the system with the gas stream. The rate
of corrosion will, of course, be influenced by the temperature of the solution,
velocity of the fluid, and other factors. In general, the principles that have been
employed in combating corrosion are.
 The use of corrosion-resistant alloys
 The use of corrosion inhibitors
 The prevention of solution contamination
 The use of process-design modifications to minimize
temperatures and velocity.
4.1.2.4 Filtration
In addition to causing corrosion, contamination of the glycol solution can
result in fouling of heat-exchanger surfaces and loss in operating efficiency.
The solution may become contaminated with oxidation products as
previously described, by corrosion products (usually iron oxide or iron
sulfide), and by solid or liquid particles brought in with the gas stream. Solid
contaminants are objectionable in that they settle out in tanks, contactor and
still trays, heat exchangers, and other vessels. They may also be a factor in
accelerating corrosion (or erosion).
The use of some means for removing suspended particles is therefore
usually justified. Filters of the common waste-pack or cartridge-type have
proved quite successful and are usually located in the line carrying the rich
glycol solution from the contactor. Activated carbon is also employed to
remove impurities from glycol solutions. It is particularly effective for
removing non-filterable heavy hydrocarbons.
4.1.2.5 Salt removal
Contamination of the glycol with sodium chloride and or calcium chloride
is a common problem. The best solution is an efficient separator in the
gas feed line.
Salt that deposit on heat exchange surfaces can be removed
continuously by the use of scraped surface heat exchangers in
conjunction with centrifuges to remove scrapings from the product liquid

44. 112
4.3. ADSORPTION PROCESS (SOILD DISCANT)
Adsorption is a physical phenomenon that occurs when molecules of gas
are brought into contact with a solid surface and some of them adhere on
the surface. There are several solid desiccants which possess the physical
characteristic to adsorb water from natural gas. These desiccants generally
are used in dehydration systems consisting of two or more towers and
associated regeneration equipment. One tower is on stream adsorbing
water from the gas while the other tower is being regenerated and cooled.
Hot gas is used to drive off the adsorbed water from the desiccant, after
which the tower is cooled with an unheated gas stream.
FIGURE 20 SOILD DISCANT ADSORBTION PROCESS
The towers are switched before the on-stream tower becomes water
saturated. In this configuration, part of the dried gas is used for regeneration
and cooling, and is recycled to the inlet separator.
Other streams may be used if they are dry enough, such as part of the
residue gas. Solid desiccant units generally cost more to buy and operate
than glycol units. Therefore, their use is typically limited to applications
such as high H2S content gases, very low water dew point requirements,
simultaneous control of water and hydrocarbon dew points, and special
cases such as oxygen containing gases, etc. In processes where
cryogenic temperatures are encountered, solid desiccant dehydration
usually is preferred over conventional methanol injection to prevent
hydrate and ice formation. Solid desiccants are also often used for the
drying and sweetening of NGL liquids.
The towers are switched before the on-stream tower becomes water
saturated. In this configuration, part of the dried gas is used for
regeneration and cooling, and is recycled to the inlet separator.

45. 113
Other streams may be used if they are dry enough, such as part of the residue
gas. Solid desiccant units generally cost more to buy and operate than glycol
units. Therefore, their use is typically limited to applications such as high H2S
content gases, very low water dew point requirements, simultaneous control of
water and hydrocarbon dew points, and special cases such as oxygen
containing gases, etc. In processes where cryogenic temperatures are
encountered, solid desiccant dehydration usually is preferred over conventional
methanol injection to prevent hydrate and ice formation. Solid desiccants are
also often used for the drying and sweetening of NGL liquids.
Figure 21 soild Discant adsorption

46. 114
Silica Gel is a generic name for a gel manufactured from sulfuric acid and
sodium silicate. It is essentially pure silicon dioxide, SiO2. It is used for gas
and liquid dehydration and hydrocarbon (iC5+) recovery from natural gas.
When used for hydrocarbon removal, the units are often called HRUs
(Hydrocarbon Recovery Units) or SCUs (Short Cycle Units). When used for
dehydration, silica gel will give outlet dew points of approximately –60°F.
Alumina is a hydrated form of alumina oxide (Al2O3). It is used for gas and
liquid dehydration and will give outlet dew points of about–90°F. Less heat is
required to regenerate alumina and silica gel than for molecular sieve, and the
regeneration temperature is lower. Molecular sieves give lower outlet water
dew points.
Molecular sieves are a class of alumina silicates. They produce the lowest
water dewpoints, and can be used to simultaneously sweeten and dry gases
and liquids. Their equilibrium water capacity is much less dependent on
adsorption temperature and relative humidity. They are usually more
expensive.
Molecular sieve dehydrators are commonly used ahead of NGL recovery
plants designed to recover ethane. These plants operate at very cold
temperatures and require very dry feed gas to prevent formation of hydrates.
Dehydration to a –150°F dewpoint is possible with molecular sieves. Water
dewpoints less than –150°F can be accomplished with special design and
strict operating parameters.
Three types of commercial adsorbents are in common use in gas processing
plants:
FIGURE 22: TYPES OF ADSORBENTS

47. 115
The continuous process requires two (or more) vessels with one on-line
removing water while the other is being regenerated. Generally a bed is
designed to be on-line in adsorption for 8 to 24 hours. When the bed is
taken off-line, the water is removed by heating to 375°F-600°F, depending
on the desiccant used and the performance specification (i.e., 375°F for
silica gel and up to 600°FFor molecular sieve, with alumina gel and
activated alumina falling in between). The regeneration gas used to heat the
bed is usually
 High pressure end fuel gas compressor.
 In the event that the End Flash Gas Compressor is unavailable, dried
process gas from directly downstream of the Dried Gas Filters is used
instead. This slipstream of gas is usually about 5 to 10% of gas
throughput.
 Sales gas is sometimes used instead of a slip stream. The sales gas
stream has the advantage of being free of heavier hydrocarbons that
can cause coking.
The regeneration gas is returned to the process after it has been cooled
and the free water removed. Any heat source can be used including
waste heat from engines and turbines. This is an important design
consideration since heat is often a major operating cost.
FIGURE 23: ADSORPTION PROCESS

48. 116
4.3.1 General Comments
The regeneration cycle frequently includes depressuring/ repressuring to
match the regeneration gas pressure and/or to maximize the
regeneration gas volume to meet the velocity criterion. In these
applications, the rate of depressuring or depressuring should not exceed
50 psi/minute. Some applications, termed pressure swing adsorption,
regenerate the bed only with depressurization and sweeping the bed with
gas just above atmospheric pressure.
It is preferable precool the gas cooler at the inlet of the drying unit in
order to:
 Get early dehydration of the wet gas (70% of liquid water)
 Decrease the load on the dehydration system
 Improve the efficiency of adsorption since the gas at low pressure
has a high stability (less movement) and in turns cause less
stresses and vibrations on the bed.
 Decrease the gas volume and consequently reduce the size of the
adsorbent bed and the cost.
4.3.2. ADSORPTION OPERATION
 The Molecular Sieve Driers are configured as a three-bed system with
two beds operating in adsorption mode while the third bed is operating in
regeneration mode.
 Each bed cycles through adsorption, depressurization, heating, cooling
and Repressurisation under control of a sequence control system. The
following cycle times are quoted by the molecular sieve vendor:

49. 117
Cycle step Time (mins)
Adsorption 960
Depressurization 15
Heating 375
Cooling 75
Repressurisation 15
Total Cycle Time 1440
 During adsorption, the flow through the molecular sieves is from top to
bottom to avoid bed fluidization and during regeneration from bottom to
top (countercurrent to flow during adsorption) to ensure that the lower
part of the bed is the driest and that any contaminants trapped in the
upper section of the bed stay out of the lower section
.
 Regeneration involves heating the bed, removing the water, and
cooling. The regeneration gas is heated to about 600°F (315°C) to both
heat the bed and remove adsorbed water from the adsorbent.
 A combination of 4A and 3A molecular sieve is installed in each vessel.
 Bed life shall be a minimum of three years.
 The maximum pressure drop across the Molecular Sieve Driers,
including vessel nozzles and all internals shall not exceed 0.8 bar after
3 years of operation.
 The Molecular Sieve Driers will be externally insulated.
 A moisture analyzer will be installed downstream of the Sieve Driers,
capable of sampling the flow from individual beds and the combined
stream.

50. 118
FIGURE 24:OPERATION CYCLES
4.3.3. CHARACTERISTICS OF SOLID DESICCANTS
DISADVANTAGES
ADVANTAGES
SOLID
DESICCANTS
Does not adsorb selectively
Adsorbs twice as much water as
molecular sieves for saturated gases.
Costs about half as much as silica gel
and molecular sieves.
Resists physical damage best.
Activated
Alumna
Not used where free water
present (free
Water destroys silica).
Does not adsorb selectively.
Gel Adsorbs twice as much water as
molecular sieves for saturated gases
Regenerates at much lower
temperatures
Silica Gel
Most expensive solid desiccant.
More easily contaminated by
carryover of amine, glycol, or
methanol from upstream.
Average 3-year life in industry.
Require more heat to
regenerate.
Possesses high water capacity at low
relative humilities.
Produces lowest dew points.
Simultaneously sweetens and dries.
Does not co adsorb heavy
hydrocarbons.
Molecular
Sieve

51. 119
4.3.4 TROUBLESHOOTING SOLID DESICCANT DEHYDRATION
To optimize the regeneration of solid desiccants, inspect a temperature
trace from the dehydrator.
 From the temperature trace, determine whether the outlet
temperature of the regeneration gas peaks before or after the
heating cycle ends.
 From moisture analyzer data, determine if the dried product gas
meets or exceeds product specifications. (If the product gas does
not meet specifications, the dehydrator requires troubleshooting.)
1. Adsorbed bed overloads during drying cycle.
 POSSIBLE CAUSES
 Increases in feed rate.
 Increases in amount of component(s) whichco-adsorb on
desiccant.
 Increase in feed water content.
 CORRECTIVE ACTIONS
 Shorten drying cycles.
 Reduce feed rate.
 Determine adsorbed size based on new load; increase amount of
desiccant or tower size, if necessary.
2. Obstruction of adsorbed bed.
 POSSIBLE CAUSES
 Fines in process stream plugged the bed.
 Glycol, methanol, or heavy hydrocarbons in process stream caked
the bed.
 Salt water in process stream caked the bed.
 CORRECTIVE ACTIONS
 Measure DP across tower.
 Compare measured and calculated DP.
 If measured DP is too high, replace of remove and clean
adsorbent as necessary.

52. 120
3. Inadequate regeneration.
 POSSIBLE CAUSES
 Temperature of hot regeneration gas is too low.
 Flow rate of regeneration gas is too low.
 Duration of heating cycle is too short.
 Regeneration gas contains oxygen.
 Steam leak from regeneration water.
 CORRECTIVE ACTIONS
 Increase temperature of regeneration gas.
 Raise flow rate of regeneration gas.
 Increase heating cycle time.
 Measure oxygen content.
 Determine the impact and adjust dehydrator
regeneration parameters as required.
4. Leaking switching valves.
 POSSIBLE CAUSES
 Mechanical damage.
 Valves not closing completely.
 CORRECTIVE ACTIONS
 Inspect valves and, if necessary, repair or replace valves.
 Inspect and adjust valve and actuator and, if necessary, repair or
replace.
4.3.5THE DYNAMICS OF ADSORPTION BED
Figure 25 illustrates the basic behavior of an adsorbent bed in gas
dehydration service. During normal operation in the drying (adsorbing)
cycle, three separate zones exist in the bed:

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1) Equilibrium zone
In the equilibrium zone, the desiccant is saturated with water; it has
reached its equilibrium water capacity based on inlet gas conditions
and has no further capacity to adsorb water.
2) Mass transfer zone (MTZ)
Virtually all of the mass transfer takes place in the MTZ, a
concentration gradient exists across the MTZ.
3) Active zone
In the active zone the desiccant has its full capacity for water vapor
removal and contains only that amount of residual water left from
the regeneration cycle. When the leading edge of the MTZ reaches
the end of the bed, breakthrough occurs
FIGURE 25: THREE ZONES OF ADSORPTION
The primary effect of inlet velocity is on the rate of movement of mass
transfer zone (MTZ). The movement of MTZ is directly related to inlet
flow velocity.

54. 122
4.4 HYDRATE INHIBITION
Three ways exist to avoid hydrate formation in natural gas streams:
1. Raising the system temperature and/or lowering the system
Pressure (temperature/pressure control)
2. Injecting a chemical such as methanol or glycol to depress the
freezing point of liquid water (Chemical injection)
3. Removing water vapor from the gas liquid–water drop out that is
depressing the dew point (dehydration).
3.2.1 Methanol vs. Ethylene Glycol
 Methanol is the most commonly used non recoverable hydrate inhibitor. It
has the following properties:
1. It is non-corrosive.
2. It is chemically inert; no reaction with the hydrocarbons.
3. It is soluble in all proportions with water.
4. It is volatile under pipeline conditions, and its vapor pressure is
greater than that of water.
5. It is not expensive.
Methanol is soluble in liquid hydrocarbons (about 0.5% by
weight).Therefore, if the gas stream has high condensate contents, a
significant additional volume of methanol will be required. This makes this
method of hydrate inhibition unattractive economically because methanol
is non-recoverable.
In such a situation, it will be necessary to first separate the condensate
from the gas. Some methanol would also vaporize and goes into the gas.
The amount of methanol that goes into the gas phase depends on the
operating pressure and temperature.
In many applications, it is recommended to inject methanol some distance
upstream of the point to be protected by inhibition, in order to allow time
for the methanol to vaporize before reaching that point.
 Glycol Injection functions in the same way as methanol; however, glycol
has a lower vapor pressure and does not evaporate into the vapor phase
as readily as methanol. It is also less soluble in liquid hydrocarbons than
methanol. This, together with the fact that glycol could be recovered and
reused forth treatment, reduces the operating costs as compared to the
methanol injection. Through glycol injection low water dew point of the
dehydrated gas (down to -65°С) can be obtained.

55. 123
Three types of glycols can be used: ethylene glycol (EG),
diethyleneglycol (DEG), and triethylene glycol (TEG).
The following specific applications are recommended:
1. For natural gas transmission lines, where hydrate protection is
importance, EG is the best choice. It provides the highest hydrate
depression, although this will be at the expense of its recover because of
its high vapor pressure.
2. Again, EG is used to protect vessels or equipment handling
hydrocarbon compounds, because of its low solubility in multi component
hydrocarbons.
3. For situations where vaporization losses are appreciable,DEG or TEG
should be used, because of their lower vapor pressure.
FIGURE 26: METHANOL INJECTION
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:
1. Upstream of front-end exchangers
2. At the inlets of turboexpanders
3. At any refrigerated condensers in downstream fractionation

56. 124
4.4Special kinds of dehydration system
Membranes offer an attractive option for cases in which drying is
required to meet pipeline specifications. Their modular nature, light
weight, large turndown ratio, and low maintenance make them
competitive with glycol units in some situations.
Units operate at pressures up to 700 to 1,000 psig (50 – 70 barg) with
feed gases containing 500 to 2,000 ppmv of water. They produce a
product gas stream of 20 to 100 ppmv and 700 to 990 psig (48 to 68
barg). The low-pressure (7 to 60psig [0.5 to 4 barg]) permeate gas
volume is about 3 to 5% of the feed gas volume.
This gas must be recompressed or used in a low-pressure system such
as fuel gas. Membrane is competing against molecular sieve desiccant
type PSA (pressure swing adsorption) systems and liquid glycol
absorption systems which are used frequently but are complex and have
high capital, operating, and installation costs, a relatively high fuel cost
and potential environmental issues. Advantages of the Membrane
Systems over both competitive types are:
 No moving parts, and designed for remote unmanned operation
 efficient packaging minimizes space and weight (ideal for
offshore applications)
 Optimized process design to maximize total hydrocarbon recovery
 CO2 content can be adjusted to desired specifications
 Easy installation: skidded system can be installed in hours.
In a typical membrane system for CO2 or H2S removal the feed gas is
filtered to remove particles and liquid condensate. The feed gas is then
heated to an optimum operation temperature and ready to enter the
membrane modules. CO2 gas permeates preferred through the membrane
walls. The non-permeated gas remains at pressure and is the high heating
value product. The ―faster‖ permeating gases, e.g. CO2 , H2O, H2S, are
collected in the permeate.

57. 125
FIGURE 27: MEMEBRANE SYSTEM
4.5 Refrigeration process
Three relatively new processes are worth mentioning. The first process
is refrigeration process that mixes methanol with the gas and cools the
gas to very low temperatures. The water−methanol mixture drops out
and the methanol is recovered in a stripper column. The process has
several major advantages:
• It can obtain dew points in the −100 to −150°F (−70 to –100°C)
range.
• It requires no heat input other than to the methanol regenerator.
• It requires no venting of hydrocarbon-containing vapors.
4.6 COMPARISON OF DEHYDRATION
PROCESSES
A number of factors should be considered in the evaluation of a
dehydration process or combination of processes. If the gas must be
dried for cryogenic liquids recovery, molecular sieve is the only long-
term, proven technology available. It has the added advantage that it
can remove CO2 at the same time. If CO2 is being simultaneously
removed, because water displaces CO2, the bed must be switched
before the CO2 breaks through, which is before any water breakthrough.
Enhanced TEG regeneration systems may begin to compete with
molecular sieve.

58. 126
High inlet water-vapor concentrations make molecular sieve dehydration
expensive because of the energy consumption in regeneration. Two
approaches are used to reduce the amount of water going to the molecular
sieve bed. First, another dehydration process, (e.g., glycol dehydration) is put
in front of the molecular sieve bed. The second option is to have combined
beds with silica gel or activated alumina in front of the molecular sieve. The
bulk of the water is removed with the first adsorbent, and the molecular sieve
removes the remaining water. This configuration reduces the overall energy
required for regeneration.
If dehydration is required only to avoid free-water formation or hydrate
formation or to meet the pipeline specification of 4 to 7 lb/MMscf (60 to
110mg/Sm3
), any of the above-mentioned processes may be viable
traditionally, glycol dehydration has been the process of choice. System
constraints dictate which technology is the best to use
However, it requires external refrigeration to cool the gas, and minima
methanol losses occur in the stripper
The second process is the Twister technology, It has been considered
attractive in offshore applications for dehydration because of its simplicity (no
moving parts) along with its small size and weight.Some offshore field
pressures are greater than 2,000 psi (140 bar), so recompression is not
needed with the unit where overall pressure drop is 20 to 30%.
The third process is the vortex tube technology. It also has no moving parts.
According to vendor information, it isused in Europe in conjunction with TEG
addition to remove water from gas stored underground.

59. 127
Reference
1. Engineering Data Book, 12th ed., Sec. 2, Product Specifications, Gas
Processors SupplyAssociation, Tulsa, OK, 2004a.
2. Engineering Data Book, 12th ed., Sec. 20, Dehydration, Gas Processors
Supply Assocition,Tulsa, OK, 2004b.
3. Kohl, A. and Nielsen, R., Gas Purification, 5th ed., Gulf Publishing,
Houston, TX, 1997.
4. Lukchis, G.M. Adsorption systems, Part 1: Design by Mass-Transfer Zone
concept, PartII, Equipment Design, and Part III Adsorption Regeneration.
UOP BrochureXF04A.
5. Malino, H.M., Fundamentals of Adsorptive Dehydration, Proceedings of the
Laurance
6. Reid Gas Conditioning Conference, Norman OK, 2004, 61.Masaoudi, R.,
Tohidi, B., Anderson, R., Burgass, R.W., and Yang, J., Experimental
measurementsand thermodynamic modeling of clathrate hydrate equilibria
and salt solubilityin aqueous ethylene glycol and electrolyte solutions, Fluid
Phase Equil., 31, 219, 2004.
7. Parrish, W.R., Won, K.W., and Baltatu, M.E., Phase Behavior of the
Triethylene Glycol- Water System and Dehydration/Regeneration Design
for Extremely Low Dew Point Requirements, Proceedings of the Sixty-Fifth
Annual Conversion Gas Processors Association, Tulsa, OK, 1986, 202.

60. 128
Almost all hydrocarbons contain mercury. In the case
of natural gas and natural gas liquids it is likely to be
present as elemental mercury. In the case of crude oil
it may also be present as organo-metallic and ionic
mercury. The concentration of mercury in natural gas
varies widely from 450 to 5000 μg/Nm3 in some
fields.
Mercury can result in catastrophic equipment failure.
So, It has to be removed If it was present in the
natural gas stream. This section represents the
different methods used to remove mercury.
Contents
1. Why Mercury Removal?
2. Mercury Species
3. Mercury Problems
occurrence
4. Mercury-induced corrosion
5. How is Mercury
Measured??
6. Mercury Removal Methods
in Gas Plants
7. LOCATIONOF REMOVAL
FACILITIES

61. 129
1. Why Mercury Removal?
 Corrosion of process equipment.
 Exposure of workers to high levels of mercury during
maintenance operations.
 Difficulty in disposal of mercury contaminated equipment.
 Emissions to the environment.
 Potential liabilities resulting from mercury contaminated product
streams.
 Currently, most operators reducing the mercury to less than
0.01 g/Nm3, which corresponds to about 1 ppt by volume.
These can cause serious financial losses for the plant operator.
1.1 Health and safety issues:
Mercury is a toxic metal and has a relatively high vapor pressure.
Consequently, on opening mercury contaminated equipment, workers
will be exposed to mercury vapor levels well in excess of the Threshold
Limiting Value (TLV) and the Maximum Allowable Concentration (MAC).
Suitable personal protective equipment is required during maintenance
work. The European Union Scientific Committee on Occupational
Exposure Limits proposes 0.02 mg/m3 as an 8-hour time-weighted
average and 0.01 mg/l in blood as biological limit values.
Atmospheric measurements carried out during maintenance on the gas
fields in northeast Netherlands have found localized levels of mercury
as high as 1500 μg/Nm3 when cleaning tanks and filters
1.2 Disposal of mercury contaminated pipe
work:
Because of the ease with which mercury bonds to metal surfaces, pipe
work used to carry mercury containing gas becomes coated with
mercury. In extreme cases a ―mirror‖ surface is formed. This makes it
harder to dispose of scrap steel. Tests have shown that mercury can
penetrate up to 1mm and many smelters set a limit of 2 mg/kg for scrap
steel to avoid damage to the off-gas clean-up filters.

62. 130
1.3 Emissions to the environment:
Most of the operational concerns about mercury are focused on the
problems it causes for the hydrocarbon product streams. However, the
surprisingly high volatility of mercury means that it is released to the
atmosphere during the processing stages. Thus, up to half of the
mercury present in the raw gas is likely to be removed on the acid gas
removal and drying stages. Acid gas removal stripper gas is released
to the atmosphere either directly or via an incinerator. Molecular sieve
regeneration gas is usually added to the fuel gas.
1.4 Mercury in product streams:
There are increasing concerns about the presence of mercury in the
feed stocks supplied to petrochemical plants (LPG and naphtha). Here
the worries are not only for corrosion of cryogenic equipment but also
the poisoning of precious metal catalysts. Many users are setting limits
of < 1ppb. A further complication is the risk of contamination during
shipment. This can easily happen if the same vessel is used for
shipments of clean and mercury containing product. Mercury is only
slowly removed from contaminated pipe work.
2. Mercury Species
Mercury is present predominantly as
 Elemental mercury in the natural gas.
 Ionic mercury in water
However, in theory, the mercury could be present in other forms:
 inorganic (such as HgCl2),
 organic (such as CH3HgCH3, C2H5HgC2H5) and
 organo-ionic (such as ClHgCH3) compounds.
FIGURE 28: SKIKIDA PLANT FAILURE

63. 131
3.Mercury Problems occurrence
Trace quantities of metallic substances are known to exist in natural
gases including arsenic, selenium, mercury and uranium, More recently,
failures occurred at the LNG plant at Skikda, Algeria, from tube
corrosion in the spiral wound exchangers. Corroded tubes contained
white deposits: aluminum oxide, aluminum hydroxide and aluminum
carbonates, with traces of elemental mercury. It was generally assumed
that the mercury might have been accidentally introduced. Later, traces
of mercury, up to 12 micrograms per cubic meter, were found in the gas
feed since mercury-induced corrosion occurs only in the presence of
liquid water, the temperature at which the corrosion occurs must be
between approximately 0 C and the highest temperatures at which a
water dew point can occur. There is onlyone condition of operation in
which this temperature can occur: when the Plant is allowed to warm
above 0 C, either for deriming, or through shut-down for any other
reason. Therefore, warming cryogenic exchangers should be prevented
whenever possible.
4. Mercury-induced corrosion
Attacks by mercury can take place in a number of ways. Amalgam
corrosion occurs when mercury and water are in contact with an
aluminum metal surface. Amalgamation occurs when high levels of
mercury come into contact with aluminum; this causes the metal to form
a liquid solution, leading to surface etching and severe pitting. The
process is self-propagating and will continue as long as free water and
mercury are present together. The more common methods of attack are
liquid metal embrittlement (LME) and intergranular metal embrittlement
(IGME), and are more serious because they result in cracking and
hence rapid failure.
Two major types of mercury corrosion can be observed. These
are
1. Amalgam corrosion
2. Liquid Metal Embrittlement (LME).

64. 132
2.1 Amalgam induced corrosion:
Amalgam induced corrosion is shown by any metal capable of forming
an amalgam with mercury. Most metals owe protection from corrosion to
the presence of an oxide layer. If this protective layer is damaged in the
presence of liquid mercury, the metal can show its full reactivity and
attack by air or water is rapid. The amalgamation of mercury and
aluminum causes weak spots which will fail and cause leak.
It is difficult to continue the process of making LNG when this occurs. To
prevent this mercury guard system have been established which remove
mercury according to the reaction.
2.2 Liquid Metal Embrittlement
LME involves the diffusion of mercury into the grain boundaries and
results in cracks developing along the grain boundary. This type of attack
does not involve air or water and once initiated progresses rapidly. This
type of corrosion affects a broad range of materials (aluminum alloys,
copper based alloys e.g. Monel 400 and some types of steel e.g. 316 L).
The figure is a photomicrograph showing mercury embrittlement on a
failed heat exchanger.
FIGURE 29: LIQUID METAL EMBRITTLEMENT FAILURE ON BRAZED ALUMINUM HEAT EXCHANGER.
Attacks by mercury will occur only when liquid mercury is present i.e. at
temperatures above its melting point of -39°C and if the protective
metal oxide film has been damaged. Therefore, attacks are most likely
to start when the equipment is offline. Furthermore, the localized nature
of the attack and the complex structure of the equipment make
detection prior to failure extremely difficult.Corrosion is a particular
concern for LNG plants and for this reason a mercury limit of < 0.01
μg/Nm3 is set on the feed.

65. 133
5. How is Mercury Measured??
A number of analyzers are available that claim capability at these low
concentrations. The mercury detection mechanism may involve such
means as electron fluorescence, cold vapor atomic absorbance, atomic
emissions spectra, or electrical resistance. None of these analyzers can
directly measure the low levels of mercury present in natural gas, not even
the levels of mercury present in the plant inlet gas. All of these analyzers
rely on the principle of taking some gas from the process line, passing a
sample gas stream through an analytical trap, and then desorbing the
mercury from the trap as a concentrated pulse into the analyzer. Some of
these analytical traps may consist of gold or silver gauze, or gold-coated
inert particles such as silica or sand. The trap is desorbed by heat.
Numerous analyzers are on the market utilizing the above-mentioned
detectors. They will all work well if used properly. The criticality is to get a
representative sample from inside the process line to the analytical
detector. This task is not easy because of the extremely low concentrations
and because mercury can be present in ambient air. Well-designed gas
sampling points on the process lines, proper in-plant sampling techniques,
and careful laboratory sample handling techniques are essential for
accurate determination of the plant mercury levels.
6. Mercury Removal Methods in Gas Plants
All of the current methods for removing mercury from natural gas and
hydrocarbon liquids use fixed beds of mercury removal materials. The
gas, or liquid, flows through the fixed bed. The mercury reacts with the
reactive reagent in the mercury removal material and stays in the vessel,
while the effluent gas or liquid hydrocarbon is mercury-free.
Characteristics required of any mercury removal system
should include:
 A very active mercury removal agent; preferably one that
bonds to the mercury, so it cannot be released again to the
treated stream.
 A removal agent that will remain active; with a high
resistance to blinding by components in the stream being
treated.
 A removal agent that will not harm natural gas or
downstream components.

66. 134
Desirable characteristics should include:
 A system that provides ready separation of the mercury from liquid
hydrocarbons (propanes, butanes and pentanes plus) for use with
the cycle gas stream or makeup.
 A removal agent that is inexpensive, readily available, or easily
regenerated.
 A removal agent that will hold mercury in a solid form or in a liquid
form from which it can be precipitated readily for filtration and
disposal.
There are two types of mercury removal materials:
1. Non-regenerative mercury adsorbents, and
2. Regenerative mercury adsorbents.
6.1 Non-Regenerative Mercury Removal
In non-regenerative mercury removal, the process fluid flows continuously
through the bed of mercury sorbent for a number of years. When mercury
is detected in the effluent, or when the pressure drop becomes excessive,
the sorbent needs to be replaced. A number of different mercury removal
sorbents are available with various tolerances to operating temperature,
liquid hydrocarbons, and liquid mercury once sorbed stays on the sorbent
and does not leave the adsorber.
However, this method requires additional adsorption vessels and it adds to
the pressure drop on the process stream. Also, the eventual disposal of the
used sorbent can be expensive since the sorbent not only picks up the
mercury, but it will often contain other hazardous material such as benzene
and other hydrocarbons and may even accumulate some other trace
hazardous materials that are not detected by feed gas analyses.
Types of Non-Regenerative Mercury Sorbents:
1. Elemental sulfur dispersed within a porous carrier such as
activated carbon granules or pellets.
2. Metal sulfide or mixed sulfides dispersed within a solid carrier
such as activated carbon or alumina.
 Halide-impregnated activated carbon particles.
 Ion-exchanged resins.

67. 135
6.1.1 Elemental sulfur dispersed within a porous carrier
such as activated carbon granules or pellets:
The elemental mercury reacts with the sulfur to form mercuric sulfide which
stays in the sorbent. This type of product was the very first mercury removal
product to be used in the natural gas industry when the Badak LNG plant
started in the late 70's.
( )
The mercury removal bed was installed downstream of the molecular sieve gas
dehydrator. Currently, a number of manufacturers offer this type of product. The
performance of the product depends on the quality of the activated carbon
support and on the technique used to disperse the sulfur within the activated
carbon particle. The activated carbon support has to have a high internal pore
surface and the sulfur must be properly dispersed without causing any internal
pore blockage. This maximizes the sulfur surface available to the mercury and
retains the sulfur on the activated carbon, especially if the operating
temperature is above ambient.
If the sulfur is not properly dispersed, all of it will not be available to the
mercury, resulting in poor mercury removal. Also, sulfur that is not properly
dispersed will not be held tightly by the activated carbon. This sulfur will be
stripped by the hydrocarbon gas, especially at higher temperatures. Loss of
sulfur will decrease the mercury removal performance and may contaminate
downstream process equipment and recovered LPG.
These products can be used in both water-containing and dry natural gas
streams. Because elemental sulfur is highly soluble in liquid hydrocarbon, this
product can be used only for gas. Also, great care must be taken to prevent any
liquid hydrocarbons from contacting the adsorbent during upset conditions.
Liquid hydrocarbons will wash off the elemental sulfur and reduce the sorbent‘s
capacity for mercury.
FIGURE 30: MERCURY REMOVAL UNIT

68. 136
6.1.2 Metal sulfide or mixed sulfides dispersed within a solid
carrier such as activated carbon or alumina:
The mercury reacts with the sulfide and stays on the sorbent. Metal
sulfides and polysulfides were found to be effective in removing
elemental mercury. Copper and zinc are the predominant metals
used as well as other proprietary metals. In some cases where
trace H2S removal is required, the metal oxide version is used to
remove the H2S that converts the oxide into the sulfide, which then
removes the mercury. A number of different products are being
offered by various manufacturers. Most are available in the pellet
form. The particle sizes generally vary from 0.9 to 4mm pellets. The
smaller particles offer better mercury removal efficiency, but give a
higher pressure drop, while the reverse is true for the larger ones.
These products can be used in both gas and liquid hydrocarbon
service and they are also not damaged by contact with liquid water.
6.1.2.1 Halide-impregnated activated carbon particles:
These particles are used to remove mercury from liquid
hydrocarbons. The mercury reacts with the halide, such as iodide,
to form HgI2 that stays on the sorbent. The product cannot be used
where there is the danger of liquid water contacting the sorbent
since liquid water will wash off the halide and may cause vessel
corrosion. Some other products are available that contain
proprietary ingredients and which are claimed to offer improved
performance in treating natural gas liquids and which are not
damaged by liquid water.
6.1.2.2 Ion-exchanged resins:
These resins remove mercury from liquid naphtha feeds to
petrochemical plants with mixed results.
6.2 Regenerative Mercury Removal
The regenerative mercury removal works the same way as does
other thermally regenerated adsorption processes. Usually it is
practiced simultaneously with dehydration or some other
contaminant removal process. Since nearly all cryogenic plants use
molecular sieve dehydrators, the mercury removal function can be
easily added to the dehydrator performance by replacing some of
the molecular sieve with a mercury removal adsorbent.

69. 137
The mercury is sorbed during the dehydration step, and then regenerated
off the adsorbent and the mercury leaves the vessel with the spent
regeneration gas. Depending on the amount of mercury present in the
feed fluid, and on the process conditions in the spent regeneration gas
knockout separator, much, and potentially all, of the mercury can be
collected and recovered as liquid mercury.
The benefit of this method is that there is no need for additional adsorption
vessels. Also, mercury protection can be quickly added simply by
replacing some of the existing molecular sieve without compromising the
drying performance. Another benefit is that there is no additional pressure
drop introduced on the process stream. This avoids the 5 to 10 psi or
higher pressure drop that is commonly experienced when using non-
regenerated mercury removal sorbents. Since the mercury does not
accumulate on the adsorbent, it presents no spent adsorbent disposal
issues. The trade-off is that there will be mercury left in the gas from the
spent regeneration gas separator.
Figure 31: A flow scheme for treating wet gas up-stream of process equipment using
advanced adsorbent
6.2.1HgSIV Adsorbents:
This is a regenerative mercury removal product developed, manufactured,
and marketed by UOP. It has greatly enhanced mercury removal
properties. This is a molecular sieve product that has been modified with
silver. HgSIV adsorbents retain their full properties for removing water and
other conventional adsorbents. Silver has been deposited only on the
surface of the molecular sieve. Mercury from the gas, or from a liquid
stream, contacts the silver and amalgamates with it.

70. 138
By having the silver on the surface and readily available to the mercury, the
mercury atom does not have to diffuse through the pore structure, which would
greatly slow the rate of mercury removal.
When the adsorbent is heated to the normal dehydrator regeneration
temperature, the mercury is released from the silver and it leaves with the
spent regeneration gas. Because these surface mercury removal sites are
regenerated each cycle, the product retains a high rate of mercury removal.
Normally, only a fraction of the dehydrator adsorbent bed volume must be
replaced with HgSIV adsorbent to achieve the desired level of mercury
removal. This product is usually located at the bottom of the drier. The life of
HgSIV adsorbent often exceeds the life of the dehydration grade sieve and
can be reused. Currently, there are over 30 units containing HgSIV adsorbent
in gas and liquid service in LNG plants, cryogenic hydrocarbon recovery
plants, and petrochemical plants.
FIGURE 32: A FLOW SCHEME FOR REMOVAL OF MERCURY USING REGENERABLE SILVER- PROMOTED MOLECULAR
SEIVES.
To ensure the removal of mercury from sales gas and to protect plant
cryogenic equipment, some gas plant operates have taken mercury removal
with silver-promoted molecular sieves one step further. By installing a vessel
of advanced non-regenerable mercury absorbent on the regeneration stream
from the molecular sieve drying unit, mercury is effectively removed and
captured. Figure 33 represents a combined approach toward mercury removal
using both advanced molecular sieve and adsorbent technologies.

71. 139
FIGURE 33: REPRESENTS A COMBINED APPROACH TOWARD MERCURY REMOVAL USING BOTH ADVANCED
MOLECULAR SIEVE AND ADSORBENT TECHNOLOGIES
7. LOCATION OF REMOVAL
FACILITIES
FIGURE 34: DIFFERENT MERCURY REMOVAL POSITIONS

72. 140
There are three possible locations for the MRU. These are shown in Figure
32 and are after the molecular sieve driers (C), before the molecular sieve
driers (B) and before the acid gas removal (A).
Undoubtedly the easiest duty is after the molecular sieve driers as the gas
is cleanest and the rate lowest. However, there are concerns about this
location. Mercury will have contaminated all of the upstream plant
equipment and mercury will be released to the atmosphere.
Plant measurements have found up to 30,000 ng/m3 in the acid gas
removal stripper gas. In the case of molecular sieves, mercury is released
throughout the regeneration cycle with peaks of up to 60,000 ng/m3. Acid
gas removal stripper gas is likely to be vented locally. Molecular sieve
regeneration gas will enter the fuel gas system but the water removed
together with entrained mercury will go to drain. Flash gas and stripper gas
from MEG and TEG dryers is likely to be vented locally.
It is possible to use small mercury removal units to treat some of the
emissions. Location upstream of the driers will reduce some of the mercury
emissions and avoids any delays to start up. However, this location will carry
the risk of fouling by carryover.

73. 141
Reference
1. Abbott, J. and Oppenshaw, P., Mercury Removal Technology and
Its Applications, Proceedings of the Eighty-First Annual Convention
of the Gas Processors Association, Tulsa, OK, 2002.
2. Environmental Protection Agency, Mercury in Petroleum and
Natural Gas: Estimation of Emissions from Production, Processing,
and Combustion, EPA/600/R-01/066, September 2001,
www.epa.gov/ORD/NRMRL/pubs/600r01066/600r01066.htm,
Retrieved July 2005.
3. Bourke, M.J. and Mazzoni, A.F., The Roles of Activated Carbon in
Gas Conditioning, Proceedings of the Laurance Reid Gas
Conditioning Conference, Norman, OK, 1989, 137.

74. 142
The nitrogen rejection unit (NRU)
must be designed to accommodate
changing inlet feed concentrations.
This chapter briefly covers the
number and types of plants used in
the processing, and they summarize
some of the economics. Contents
1.Why removing
Nitrogen from
LNG?
2.NITROGEN
REJECTION
FOR GAS
UPGRADING

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1.Why removing Nitrogen from LNG?
 To maintain the sales contract specification of the LNG.
 To avoid the crystalline formation of nitrogen in cryogenic process.
 Nitrogen increases the gas volume and decrease it is heating value.
2.NITROGEN REJECTION FOR GAS
UPGRADING
Three basic methods are used for removal of nitrogen from
natural gas:
1. Cryogenic distillation
2. Adsorption
3. Membrane separation
FIGURE 35: METHODS FOR REMOVAL OF NITROGEN
Cryogenic methods are the most economical and can provide higher
nitrogen rejection at high gas throughput. At low gas volumes, membranes
and pressure swing adsorption (PSA) by use of molecular sieves are
economically feasible. The tabulated flow ranges are guidelines only. In
regard to hydrocarbon recovery, only PSA has heavier hydrocarbons (all
C4+ and part of propane) going with the nitrogen stream. This situation is
caused by adsorption in the sieve binder, as the components are too large
to enter the sieve pores. The binder also adsorbs water and CO2. The loss
of hydrocarbons may or may not be beneficial.

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2.1 CRYOGENIC DISTILLATION
The most common method of removing nitrogen from natural gas is
cryogenic distillation. That for feed concentrations below 20% N2, a
single-column design can be used. For higher concentrations, a dual-
column is better. With the addition of a recycle compressor, it can be
used at lower N2 contents. Figure 8.1 shows a flow diagram for a two-
column NRU receiving feed that contains 15% N2 from a demethanizer
in a conventional Turbo expander plant. Gas from the demethanizer
overhead is cooled by heat exchange and pressure reduction and fed
to a distillation column operating at 200 psig (14 barg) . The bottoms
product from this high-pressure column is reduced in pressure to cool
the stream to −240°F (−151°C). This stream, combined with the
bottoms product from the second low-pressure column, is fed to a heat
exchanger in the top of the high-pressure column to provide the
necessary reflux.
The overhead from the high-pressure column flows through three heat
exchangers, is reduced in pressure to approximately 15 psig (1 barg),
and enters the low pressure column at −300°F (−184°C). The overhead
from this column is 98% N2, and the bottoms product is approximately
98% CH4. The Hannibal Gas Plant of British Gas Tunisia (Jones et al.,
1999) uses cryogenic distillation to reduce the N2 content of the feed
gas from 16.9% N2 to the sales-gas specification of 6.5%.
FIGURE 36: CRYOGENIC DISTILLATION

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2.2 PRESSURE SWING ADSORPTION
After cryogenic distillation, pressure swing adsorption (PSA) is probably
the most widely used process. At this point, we should briefly discuss the
significant differences between the adsorption process used for
dehydration (thermal swing adsorption, or TSA) and that used for nitrogen
rejection (pressure swing adsorption, or PSA).
The amount adsorbed depends on four factors:
1. The adsorbent itself.
2. The species being adsorbed (adsorbate).
3. The temperature.
4. The partial pressure of the adsorbate.
Once the adsorbent and adsorbates are selected, the temperature and
partial pressure become the governing variables. All industrial
regenerative adsorption separations involve two steps: adsorption to
separate the species, followed by desorption and removal of the
adsorbate (regeneration) to prepare the dsorbent for further use.
In natural gas systems, if adsorption is used to remove a relatively small
amount of material to a very low level, or if the heat of adsorption is very
high, TSA is generally used, as discussed in Chapter 6. An example is
natural gas dehydration, which meets both criteria. For bulk removal of
one component from another (e.g., upgrading natural gas to pipeline
specifications by removal of CO2 or N2), PSA may be the choice because
concentrations of the adsorbate are high and the heat of adsorption is low.
We briefly discuss the fundamentals of this process.
Very simplified two-bed PSA system (actual plants may have four beds) to
separate a binary mixture of compounds A and B. Assume A is strongly
adsorbed relative to B. The feed enters the adsorbing bed at ambient
temperature and a high pressure with the partial pressure of A = p1.
Because A is more strongly adsorbed than B, the adsorbed phase
(adsorbate) is enriched in A, and the A content of the gas leaving the bed
is reduced. When the outlet concentration of A begins to increase because
of bed breakthrough, it is switched to the regeneration mode, and the feed
is switched to the previously regenerated bed to continue the cycle.
Regeneration is accomplished by dropping bed pressure, which causes
the gas to desorbed, and purging the bed to remove the desorbed gas.

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FIGURE 37: PRESSURE SWING ADSORPTION
The adsorption isotherm in Figure 38 (the plot of weight fraction A, XA,
adsorbed versus partial pressure) indicates that the final concentration of A
on the regenerated bed drops to what will be in equilibrium with the purge
gas A at a partial pressure of p2. Thus, all of the A cannot be removed from
the bed.
The residual A that loads when the bed is put back into adsorption service
is at equilibrium with p2. This condition means the gas that leaves the bed
during the adsorption mode has a partial pressure of p2. If the purge gas
contains no A, then its partial pressure is reduced to zero, and most of the
adsorbed A will be desorbed and purged. Consequently, the bed is capable
of reducing the level of A in the product to a very low level. A PSA unit
that uses a specially treated carbon molecular sieve (CMS) for nitrogen
rejection.
FIGURE 38:THE PLOT OF WEIGHT FRACTION A, XA, ADSORBED VERSUS PARTIAL PRESSURE