Special Focus
Process Optimization
D. B. ENGEL, Nexo Solutions, Amine Optimization Division,
The Woodlands, Texas; and S. NORTHROP, ExxonMobil
Upstream Research, Spring, Texas
Managing process contaminants in amine
treating units—Part 1: Lean amine filtration
drocarbons). Fouling often takes place at high temperatures and/
Installation and operation of suitable contaminant removal
or low-velocity fluid locations, such as heat exchangers, columns
systems, such as filtration, coalescing and adsorption equipment,
with trays (less common) and packing (more common).
have become key components in amine units. These systems reFouling or deposits may have various formation mechamove or avoid contaminants that negatively affect the process and
nisms. However, it is generally accepted that they can originate
its equipment. They also enable the unit to operate with stability,
from polymerization reactions by light, heat, free radicals (e.g.,
reliability and low operational costs, while achieving design profrom oxygen), condensation of dissolved components produccessing capacity. Typical contaminant removal systems for amine
ing insoluble materials, or the settling of solids (or immiscible
units consist of inlet separators, gas demisters or knockout drums,
liquids) in suspension.
liquid filters, activated carbon beds and gas coalescers. Additional
Today, some types of fouling or deposition can be minitechnologies, such as liquid coalescers for rich amine streams to
mized by using chemical means, such as dispersants, oxygen
remove emulsified hydrocarbons, and amine recovery systems
scavengers, free radical inhibitors or condensation reaction infor treated streams, are increasingly used to protect and mainhibitors. Filtration and/or adsorption methods can be used to
tain amine unit performance and recover often expensive amine
minimize deposition mechanisms, such as precipitation and/or
solvents while protecting units downstream.
polymerization and condensation reactions. Both filtration and
Contaminant removal systems give amine units a greater toladsorption are effective, depending on the process conditions
erance to process upsets. Without these systems, well-designed
and the type of contaminant causing fouling or depositions.
and properly operated amine units can suffer from several inefBoth fouling and deposits can lead to detrimental situations in
ficiencies and problems, such as high operating costs, low efamine units, such as energy losses, inefficiency of heat exchangficiency of H2S and CO2 removal, amine solvent losses, amine
ers, column packing clogging and under-deposit corrosion.
degradation and excessive maintenance.
Fouling can significantly shorten the online life of filters and/
Amine units may experience a variety of challanges, but
or retention times in settling tanks, if they are not cleaned. FIG. 2
most of these issues come down to a few core problems. Design
limitations, contaminant removal efficiencies or incorrect operillustrates solids deposition in column packing.
ational parameters are usually the central
problems found in most amine units. The
Hydrocarbons
in acid gas
most common amine unit difficulties are
Amine carryover
Cooling
Acid gas
shown in FIG. 1.
Lean amine suspended solids
Treated
gas/liquid
Dissolved contaminants
Contaminant removal plays a significant
Heat exchanger fouling
role in amine unit operation and perforPoor temperature control
Cooling
mance. Filtration and separation technoloReflux
Treated feed gas or
Lean amine
accumulator
gies can considerably reduce or eliminate
liquid not meeting
specification
the variety of problems frequently found in
Foaming
Regenerator
amine units, as indicated in FIG. 1. Several
Surge
Contactor
Corrosion
tank
(absorber)
of the problems amine units experience
Fouling
Foaming
Lean/rich
Poor regeneration
throughout their lifetime can be addressed
Corrosion
exchanger
Fouling
with proper filtration and separation, as de- Feed gas/liquid
Poor contactor performance
Reboiler
scribed in the following sections.
Flash gas
Amine unit problems: Fouling and
deposition. Fouling is a process where
solids physically or chemically accumulate on the surfaces of process equipment,
and it is caused by material deposition or
precipitation (usually solids, salts or hy-
Solids, liquids and
surfactant contaminants
Flash tank
Lean amine
Rich amine
Liquid hydrocarbon
carry-under
Hydrocarbon
High energy usage
Reboiler corrosion
Rich amine suspended solids
Liquid hydrocarbon contaminants
FIG. 1. Amine unit diagram with common process difficulties.
Hydrocarbon Processing | JUNE 2018
57
Process Optimization
Corrosion. In amine units, corrosion is continuously caused
during the removal of H2S or CO2 if carbon steel is present in
the circuit. In some cases, corrosion can occur if the unit contains stainless steel. Passivation of metal surfaces by H2S is key
for amine units; this is one reason why amine units only used
for CO2 removal experience corrosion problems more often, as
passivation of metal surfaces does not take place. Alternatively,
deposition also generates corrosion. Typically, where there is
accumulation of solids on surfaces, the natural progression is to
find “under-deposit corrosion.” This is one of the most common
corrosion mechanisms, and is caused by localized high concentrations of chemical species, ions and corrosion initiators. Typically, if the deposition of suspended solids is minimized, then
corrosion rates are also reduced.
One example of deposition is the consequence of increased
corrosion rates in the regenerator of the amine unit. If the inlet temperature of the rich amine to the regenerator is lower
than recommended (caused by deposition on the rich/lean
amine heat exchanger, or by a temporary upset at the rich amine
stream), then regeneration takes place at the bottom of the tower or reboiler. This type of corrosion mechanism is frequently
encountered. FIG. 3 illustrates corrosion in stainless steel tubes
in an amine unit reboiler.
Heat-stable salts and amine decomposition products.
Thermally stable salts are components that do not decompose
or revert thermally in accordance with the normal conditions of
the amine regeneration unit; they are called “heat-stable salts.”
These salts typically require external treatments (such as ion exchange, electrodialysis or vacuum distillation) to remove them
from the amine unit. Evidence exists that many of these salts
cause accelerated rates of corrosion. Moreover, the surfaces of
suspended solids have high molecular activity, as well as being
rich in metals, such as iron. These solids may catalyze chemical
reactions that form stable salts, further increasing their concentration. They can also cause the decomposition of the amine itself, possibly creating capacity limitations. Therefore, the reduction of suspended solids in the amine solution can mitigate (but
not eliminate) the rate of forming stable salts and prolong the
life of the amine solution. In general, heat-stable salts are a more
common problem in amine units in refineries. In gas processing
plants, they are somewhat less common.
Foaming and emulsification. Foam is usually produced
when gas contacts liquids with low surface tension. Foams are
stabilized by surfactants or surfactant-like materials. Variation
of surface tension by the addition of solvents, such as methanol, hydrocarbons or BTEX (benzene, toluene, ethylbenzene
and xylene), may also contribute to foaming tendency and stability when surfactants are present. Solid surfactants may be
smaller than 10 microns (iron sulfide), and they may also exist
as liquid molecules (e.g., components in compressor lubricating oil or certain additives).
The removal of surfactants and hydrocarbons (including
BTEX) from the solvent will reduce the formation of foam
and the need for antifoam additives. Excessive frothing with
foaming invariably leads to loss of amine and reduced reaction
efficiency with H2S. In some cases, the absorption of CO2 under foaming conditions is greater, which is undesirable for selective H2S removal. FIG. 4 shows amine solvent samples with
high foaming tendency and stability.
Emulsification is a different phenomenon that is somewhat
related to foaming. It takes place when two liquid phases are
mixed in the presence of a stabilizing surfactant. Amine units
that process liquid hydrocarbons, such as liquified petroleum
gas (LPG), condensates or natural gas liquids (NGL), often
encounter emulsification events in the amine contactor. The
main reason for emulsion formation is surface-active contaminants present in the feed liquid hydrocarbon. In some
cases, however, the lean amine entering the liquid contactor
FIG. 2. Deposits by suspended solids in column pall ring packing.
FIG. 3. Corrosion in amine unit reboiler tubes.
58
JUNE 2018 | HydrocarbonProcessing.com
FIG. 4. Amine solvent sample with strong foaming tendency.
Process Optimization
(commonly referred to as a liquid treater) can be a root cause
of emulsification if amine degradation products are present.
Emulsification may cause amine carryover into the treated hydrocarbon outlet of the amine unit. It can reach downstream
units, such as caustic units and mercaptans removal units.
This phenomenon can take place in either amine-continuous
or hydrocarbon-continuous contactors.
Filtration in amine units. In general, filtration and separation
schemes in amine units are divided into three main areas:
1. Systems designed for the feed streams—e.g., gas streams,
such as natural gas and vent gas, or liquid hydrocarbons,
such as LPG and NGL
2. Systems for the circulating amine solution (lean and
rich amine)
3. Systems to remove contaminants from the treated stream
upstream of the next unit, or from the acid gas prior to
final disposal or processing, or from the acid gases.
It is important to also mention that lean and rich amine
filtration and separation processes serve different purposes
and protect different parts of the amine unit. Treated streams
egressing from the amine unit contactor can impact downstream fuel gas systems in refineries and dehydration units in
gas processing plants. In addition, acid gases from the amine
unit regenerator can carry contaminants, such as hydrocarbons or amine solvent, that not only can affect downstream
units, such as the sulfur recovery unit (SRU) process and the
catalyst, in addition to burning or incineration, and acid gas
reinjection into the ground, among others.
The main filtration and separation areas indicated previously
have different goals, functions and technologies. Therefore, they
must be implemented correctly for the intended function. Each of
the three filtration and separation methods (filtration, coalescing
and adsorption) should operate in combination and synchronicity to enable effective performance of the amine unit, ensuring
favorable, stable results in the process of removing H2S and CO2.
Filtration of the full flow of the lean amine stream is always
recommended. Particularly in cases where the contactor tower
has packing, as opposed to trays, it is almost mandatory to have
a full flow amine filter. Filtration may minimize solids deposits
and fouling of the tower internals. After the full flow lean amine
filtration, a percentage (typically 20%–25% minimum) of the
flow should be routed to the activated carbon bed. A post-filter
sized according to the flow entering the activated carbon bed
should also be used. It is best to avoid high-temperature amine
filtration, such as filtration systems placed directly at the outlet
of the regenerator. High-temperature filtration results in limited
FIG. 5. Corroded and collapsed central metal core of a cartridge filter
that was installed in a lean amine stream directly out of a regenerator
atPumpAd_3_5x4_625_f.qxp_Layout
121°C (250°F).
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Lean amine solvent filtration. Proper purification of the lean
amine stream is accomplished by using two filtration stages and
one adsorption stage. Lean solvent mechanical filtration is designed to protect the activated carbon bed, as well as the amine
unit contactor. Lean amine filtration is complementary to adsorption, which is intended for soluble contaminant removal.
Lean amine filtration and adsorption are normally composed
of three different stages. Each stage has a specific function. All
steps are necessary and cannot be replaced or eliminated. The
core of the process is the activated carbon bed. The activated
carbon bed is not truly a “filter,” as it is often called. The proper
definition of filtration is the separation of solid particles from a
liquid using a porous or fibrous medium. Activated carbon beds
should not act as filters and should function only as a physical
adsorption bed for dissolved contaminants.
Contaminants are adsorbed with weak interactions within the
surface pores of the activated carbon grains. Therefore, it is necessary to keep the activated carbon surface free of solids. For this to
happen, the activated carbon beds must always be protected with
an effective pre-filter; otherwise, particulates will collect in the
bed and cause high differential pressure. This could necessitate
backflushing of the bed, or other removal of those particulates.
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Process Optimization
thermal and chemical compatibility of materials for many filters.
When using filtration out of the regenerator, careful materials
screening is necessary. Media such as flame-resistant polymers
and cellulose can be used, in addition to metal media. Lowertemperature filtration allows for additional media materials,
such as polypropylene and epoxy-coated fiberglass, to be used.
At present, the best filtering devices for amine units are disposable cartridge filters, which are also the most effective for filtration of deformable particles, especially when hydrocarbons
are present. Automatic (back-washable) filters with metal media materials are unsuitable for amine units because contaminants tend to have strong adhesion to metal surfaces. The strong
interactions of metal filter elements with suspended solids often
render backwash or automatic filter cleaning ineffective.
Other devices, such as centrifuges, have been used with success in certain facilities, although maintenance of rotating equipment must be considered. Technical hurdles, such as flow and
pressure limitations, as well as reliability, must be overcome for
this technology to be used in amine plants. Filters with filter aids
and precoatings have also been used, but these are less common
due to difficult waste disposal, complex maintenance procedures
and operational issues. However, some of these devices have been
used in large amine units with large amine solvent flows.
Regarding cartridge filtration, numerous media materials are
used in amine service. Examples of the most common materials
are cotton, polymer-impregnated cellulose, polypropylene and
polymer-impregnated fiberglass. Care must be taken to use only
filter media that are compatible with the amine solvent and do
not cause foam formation by reacting with the material or extraction of components. Foam caused by filters may originate
due to the material used in the filter (epoxy adhesives, filter
media, release agents used during manufacture or the endcap
material), or by incompatibilities of contaminants in the amine
solvent with the filter (e.g., BTEX).
Filter media with polypropylene fibers should be used carefully because of the low softening-point temperature. Hightemperature excursions could cause the filter materials to melt.
Also, filters with polyester materials should not be used in amine
units because they undergo basic hydrolysis or aminolysis reactions with the amine solvent, degrading and dissolving the material. In both cases, thermal and chemical incompatibility of
the filter material can lead to foam formation or contamination
of equipment surfaces, requiring total cleaning of the unit.
Finally, it is important to mention that when cellulose filter
media are used, tests should be conducted to ensure that foam
TABLE 1. Different amine unit filter types and key properties
Filter type/
details
Cost
Loading
capacity
Flow
Bypass
Bag
Low
Low/medium In-out
Melt-blown
Low/medium
Low
Out-in
More often
Resin-bonded Low/medium
Low
Out-in
More often
More often
String-wound
Low
Low
Out-in
More often
High-flow
High
High
In-out
Less often
Pleated
cartridge
Medium/high
High
Out-in
Less often
Notes: S = surface filtration, D = depth filtration
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JUNE 2018 | HydrocarbonProcessing.com
formation is not a consequence of the cellulose material. Some
cellulose filter media materials are actually incompatible with
amine solvents and should not be used. It is advised to always
test both chemical and thermal compatibilities with the amine
solvent before any filter is used. This is especially true for the
lean amine circuit directly out of the regenerator, where high temperatures are prevalent. FIG. 5 shows the central metal core of a
cartridge filter installed in a lean amine side, directly out of the
unit regenerator. The high temperatures 121°C (250°F), coupled
with the aggressive conditions of a formulated amine solvent, corroded and weakened the filter metal core to the point of collapse.
The degree of filtration and efficiency is discussed in more detail in the next section. However, any initial filtration efficiency
and media pore size or micron rating selection is only a starting
point. Filtration optimization and efficiency selection for the
amine solvent is best when the amine unit is operational and
online gravimetric analysis of a slipstream is conducted. Online
gravimetric analysis at the inlet and outlet of a filter will accurately
determine the efficiency of the filter media used in the system;
only afterward is it possible to adjust the efficiency and achieve
best results, acceptable filtration costs and proper filtration levels.
From a filter design standpoint, it is necessary to ensure a
maximum flux inflow of 0.5 gal/min/ft2 of filter media surface
area. However, lower fluxes will produce not only better filtration, but they will also reduce operational costs, operator exposure and waste generation. The drawbacks of low-flux filtration
are higher capital expenses (marginal compared to the cost of an
amine unit) and larger system footprints.
Lean amine solutions with high solids content are less likely
to produce efficient stripping of H2S and CO2. This inefficiency
is caused by the formation of a multi-layer solid interface between the acid gases (or liquids) and the amine solvent, essentially reducing mass transfer. A high concentration of suspended
solids in amine solvents is usually an indication of a detrimental
situation, such as high corrosion, taking place in the unit. Such
issues should be investigated promptly.
In general, amine units with high-quality amine solutions have
minimal suspended solids (1 ppmw or less), resulting in better
performance and a more stable process. In essence, filters avoid
equipment damage and protect the unit internals and amine solvent. Filters also reduce unit maintenance costs and energy use.
Whereas cartridge filtration is a good avenue for amine filtration, it fails to perform when “shoe-polish” material is present in
the amine unit. This shoe-polish material is usually more common in refineries and gas processing plants with amine solvents
with high heat-stable salts and iron sulfides.
It is similar to a gel material, has a black
color and is usually fairly soluble in water.
Common
Type
The material is a mixture of iron sulfide,
sizes, in.
heat-stable salts, traces of hydrocarbons
6 × 30
S
and polymerized amine, and requires a
much more careful and rigorous filtration.
2.5 × 40
D
The amorphous material contains solid
2.5 × 40
D
particulate iron sulfides, predominantly
2.5 × 40
D
between 1 microns and 5 microns in size.
6 × 60
S
This material also causes a rapid increase in
filter pressure differential, thereby leading
2.5 to 6.5
S
OD × 40
to a rapid decrease in filter lifetime.
The formation of shoe-polish material
Process Optimization
should be monitored and prevented by maintaining low suspended solids and corrosion rates, ensuring that amine degradation is
minimized and heat-stable salts are kept to low levels, and not using silicone antifoams, if possible. Silicone antifoam products are
good for removing foam from liquids, but they often negatively
affect the amine process through solids or semi-solids deposition.
In terms of amine solvent filters, disposable filter elements (internals) are the most common for both lean amine and rich amine
circuits. Some examples of disposable filters are shown in FIG. 6.
Common filters used in amine units include bag filters, pleated
cartridge filters, depth-style cylindrical filters and string-wound
filters. All filter element designs have a number of pros and cons,
and should be properly evaluated for use in amine units. It is necessary to use proper sealing mechanisms to ensure that no bypass
takes place inside the vessel. Filters normally use flat gaskets, as
shown in FIG. 6 (right); however, O-rings are much better because
they offer an efficient sealing method.
Flat gaskets often must be affixed to the filter using an adhesive. Several adhesives have been observed to fail if chemically
incompatible with amine solvents. Gaskets and O-rings used
in amine units should be ethylene-propylene-diene-monomer
(EPDM) rubber, as they offer good compatibility and stability
for the process. Other types of filters, such as automatic systems, have not shown successful results in amine units due to
their ineffective cleaning results. Solids in amine units tend to
FIG. 6. Common disposable filters used in amine units. Left to right:
cotton-wound, polypropylene melt-blown and pleated styles.
FIG. 7. Amine solvent samples. Left: new amine solvent; right:
contaminated amine solvent.
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JUNE 2018 | HydrocarbonProcessing.com
be highly fouling and strongly adherent to metal surfaces, hindering backwash or mechanical removal by automatic filers. Finally, some amine units have used centrifuges with good results;
however, reliability and the inability to tolerate high pressures
make them less common in the industry today.
All filter elements will filter suspended solids to some extent
when installed in an amine unit. Some are more effective or have
lower costs than others. Field experience has shown that the pleated cartridge filters, operating as surface filters where solids are
accumulated at the filter surface, often perform better compared
to the other types. In addition, the cost performance is the best
among other filters. Bag filters are low-cost, but they do not have
the efficiency or the surface area for proper amine solvent filtration. Cotton string-wound filters display good chemical compatibility with the amine solvent, but they lack contaminant removal
capacity, and efficiency decreases as the media deforms from high
differential pressure. Depth filters, where the suspended solids
are immobilized in the inner structure of the filter element, are
also less effective because solids in amine units are usually filtered
at the surface of the filter media and form a cake or seal off the
surface. This eliminates the benefits of depth filtration, leading
to short online life. TABLE 1 summarizes various amine unit filter
types and key properties.
Lean amine solvent activated carbon beds. Activated carbon can be manufactured from various materials, such as wood,
coal, lignite, coconut shell, peat or other organic sources. Activated carbon can be in powder form, granular or extruded in various
shapes. The purpose of activated carbon is to remove dissolved
organic components by adsorption. These dissolved organics often generate foam in amine unit solvents, so their removal
is beneficial to the operation of the amine unit. Other activated
carbon functions include odor control and color improvement.
Dissolved contaminants, such as surfactants and chemical additives, that lead to foam are generally dissolved hydrocarbons or
surfactants that interact with the activated carbon surface due to
the pore structure of activated carbon.
As adsorbent media, activated carbon removes, on average,
5%–10% of its weight in organic species, if operating below the
material’s isotherm. Depending on the type of contaminants
and operating conditions (temperature, flow velocity, activated
carbon type, pore size and activation mode), the capacity of the
carbon may vary.
Activated carbon beds are best employed in lean amine
streams after the heat exchangers and coolers. Lower temperatures lead to better adsorption. The use of activated carbon beds
in the rich amine stream is not recommended because of difficult maintenance procedures, operator exposure and waste generation/disposal. Spent activated carbon in rich amine streams
may contain high concentrations of H2S, thereby requiring additional steps for changeout.
Activated carbon used in liquid streams is usually granular
or extruded as pellets, and not in powder form given the higher
drag, increased entrained fines and higher differential bed pressure. However, the efficiency of granular activated carbon is
higher compared to the pelletized form. All types of activated
carbon suffer structural fractures and generate solids that are
carried out with the outgoing process stream (carbon fines).
Granular carbon—and, to a lesser degree, extruded/pellet-
Process Optimization
ized carbon—often fracture during installation and operation,
making it necessary to backwash the material to remove as many
fines as possible, as well as to separate any carbon fines at the outlet of the carbon bed before they can enter the amine unit contactor. Some activated carbons are also activated with certain acids,
and the backwash ensures that acid residues are removed. High
suspended solids entering the amine unit contactor will cause
solids deposition, possible erosion/corrosion and, in some cases,
foaming due to foam stabilization by suspended solids. These
scenarios can cause lower H2S removal efficiency in the amine
unit, equipment failures and other problems.
In many cases, carbon fines from the lean amine can reach all
the way to the rich amine circuit, causing deposits in the flash tank
and reducing residence time. Deposits may also be found in the
heat exchanger, reducing rich amine temperature to the amine
unit regenerator; and the regenerator tower, possibly leading to
erosion/corrosion at the bottom of the regenerator.
For removing solids at the outlet of the activated carbon bed,
a general guideline of 5-micron (beta5 5000, 99.98% efficiency)
filters are required, using surface filtration. However, this is only
a starting point, and the filter micron ratings should be adjusted
FIG. 8. Various activated carbon types, origins and associated pore
structures. Image courtesy of Calgon.
FIG. 9. Lean amine filtration system (pre-filter and post-filter) with
activated carbon bed.
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JUNE 2018 | HydrocarbonProcessing.com
based on the particle size distribution of the amine solvent leaving the carbon bed. Note: The beta5 5000 filter efficiency is the
ratio of the number of particles exiting the filter and the number
of particles entering the filter, for particles 5 microns and larger
(i.e., the reason for the subscript 5 notation).
Activated carbon that is activated with and/or rinsed with
phosphoric acid or phosphorous-based additives should not be
used in amine units because of the potential for foaming. Only
heat- or steam-activated carbon should be used. A properly designed activated carbon bed can considerably reduce foaming
from amine solvents by removing surfactants, dissolved hydrocarbons and amine degradation products. Activated carbon beds
are generally sized for a 20%–25% minimum slipstream flow. It is
best to have at least 25%–50% slipstream flow of the total circulating amine solution. A minimum contact time of 15 min. and a
cross-sectional flow velocity of 2 gal/min/ft2–3 gal/min/ft2 are
considered suitable for a correctly designed activated carbon bed.
Finally, the design of the inlet distributor is key to carbon beds, as
it ensures the most efficient use of the entire bed.
When the amine solution changes color or presents haziness,
or when foaming tendency is increased, the carbon bed must be
evaluated and replaced, if necessary. Color changes are associated
with dissolved metals and amine degradation products. Foam is
generally caused by surfactants, haziness, suspended solids, dissolved metals from corrosion or hydrocarbon emulsions. FIG. 7
shows amine samples in a gas processing plant. The bottle on the
left represents a new amine solvent, and the bottle on the right is
a contaminated amine solvent. The contaminated amine solvent
sample presents considerable haziness from emulsified hydrocarbon and oil, in addition to a separate upper-hydrocarbon phase.
Activated carbon beds should not be changed out solely due
to pressure drop, since this parameter is a misrepresentation of
bed efficiency. In fact, activated carbon beds should not experience any increase in differential pressure. When differential
pressure increases in a carbon bed, it is necessary to replace the
bed because of solids or hydrocarbon obstruction of the carbon
grain pores, which hinders contaminants removal.
To avoid solids buildup inside the carbon bed, it should
be protected by a pre-filter. The pre-filter micron size for the
protection of carbon beds is often 10 microns (beta10 5000 or
99.98% efficiency) and surface filtration. However, this is only
a starting point, and the filter micron ratings and micron size
should be adjusted based on the particle size distribution of the
amine solvent entering the bed, ideally at the time of processing
into the carbon bed.
Activated carbon bed lifetimes are typically 6 mos–12 mos.
This industry guideline is not always consistent, however, because carbon bed lifetimes depend on several factors, such as
bed size, bed design, internal flow velocity, contaminant concentration and carbon type. Therefore, evaluating carbon beds
for replacement is complex. The best way to evaluate bed lifetime is to take samples of the carbon inside the bed and test
for its activity (molasses number, methylene blue number and
iodine number). However, sampling is not straightforward, as
it depends largely on where and how the sample of carbon was
taken inside the bed. In addition, carbon-sampling ports are not
an existing feature in most carbon beds.
At present, the only way to test for a spent carbon bed and
determine its life is by using a surface rheology (and sometimes
Process Optimization
surface tension) analysis of the amine solvent at the inlet and
outlet of the bed, and then comparing the results. A simpler test
is to compare the foaming tendency of amine into and out of
the bed. Also, the outlet amine solvent should be lighter in color
and lower in viscosity.
The origin of activated carbon generally defines its adsorption
power, capacity and pore size distribution. A general guideline
for activated carbon use in amine units is as follows: If the amine
unit has an efficient feed gas coalescer, then the type of activated
carbon used should be granular, 8 × 30 (mesh), of bituminous
origin and activated by steam. This type of activated carbon has
the most suitable balance of pore sizes (small, medium and large)
capable of adsorbing a wide range of contaminants in the amine
solution. However, if the amine unit does not have a feed gas
coalescer or has an inefficient feed gas coalescer, then the most
suitable activated carbon type is granular, 4 × 10 (mesh), from lignite. This type of activated carbon has a greater balance of larger
carbon pores, allowing for better absorption of larger molecules,
such as hydrocarbons or surfactants, that cause foaming.
FIG. 8 shows a diagram of the various activated carbon types
based on origin and overall pore size distribution. It can be seen
that the pore size distribution is very different depending on the
carbon type. The rationale for using lignite carbon when poor
inlet separation is present is to have larger pore sizes to accommodate larger surfactant molecules.
Special types of activated carbons are also available. They
generally come from the family of impregnated activated carbons that contain chemical additives to perform certain specific
functions, such as sulfur-impregnated activated carbon for the
removal of vapor-phase mercury in feed gas to processing plants.
Activated carbon beds are recommended for bypass mode in
only three scenarios:
• When combating foaming events with antifoams.
Antifoams will be removed in the carbon bed to a certain
level, depending on the antifoam product. The bed will
exhaust much more rapidly, and the antifoam will be
rendered ineffective.
• During plant startup due to high-solids loads in the system.
• During ingress of liquid hydrocarbons causing amine
emulsification.
Activated carbon beds should always be a three-stage process that includes pre-filtration, carbon bed adsorption and
post-bed filtration. FIG. 9 shows a refinery lean amine filtration
system with an activated carbon bed in the center. The bed is
flanked by duplex pre-filters to the left and the duplex post filters to the right. Duplex (or parallel) filters are commonly used
when a constant flow through a filter is desired; they work by
alternating between the two filters when maintenance is performed. This arrangement represents a correct activated carbon
bed system configuration.
Guidelines for lean amine filtration and adsorption. In
amine units, the lean amine stream requires both filtration and
adsorption purification processes. The stream often contains
suspended and dissolved contaminants that must be removed.
Below is a general set of filtration and adsorption guidelines for
amine units. FIG. 10 shows a basic flow diagram of lean amine
flow from the heat exchanger to the absorber. Recommended
activated carbon system parameters in amine units include:
• If an efficient inlet gas coalescer is in place at the unit,
then the unit should use bituminous activated carbon,
granular, 8 × 30 mesh size.
• If an inefficient, undersized or no inlet gas coalescer
is in place, then the unit should use lignite activated
carbon, granular, 4 × 10 mesh size. (Note: Grain size is
irrelevant here).
• Steam- or heat-activated. If acid-activated, avoid phosphoric
acid. When using acid-activated carbon, the materials must
be fully rinsed by reverse flow to a neutral pH.
• Process 25%–50% of lean amine flow for best results.
• Activated carbon pre-filter. To appropriately select the level
of pre-filtration efficiency, it is necessary to analyze the lean
amine particle size distribution and total suspended solids.
However, if this is unavailable, a good starting point is 10
microns (beta10 5000/99.98% efficiency).
Lean filter flow
is normally 25%
Recommended to
split flow after precarbon filter
Lean amine
flow
Lean amine
Post-carbon
Pre-carbon
Carbon
filter
filter
bed
From lean/rich
exchanger
Amine
cooler
Booster
pump
FIG. 10. Typical lean amine filtration flow diagram.
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65
Process Optimization
• Activated carbon post-filter. To appropriately select
the level of post-filtration efficiency, it is necessary
to analyze the lean amine particle size distribution
and total suspended solids. However, if this is
unavailable, a good starting point is 5 microns (beta5
5000/99.98% efficiency).
The split flow to the carbon bed is commonly placed upstream of the pre-filter with a 75% bypass and only 25% of the
flow processed into the carbon bed. This leaves the contactor
predominately unprotected. For this reason, it is recommended
to place the split flow after the pre-filter to provide full-flow prefiltration and to better protect the contactor from suspended
solids. Finally, it is necessary to emphasize that activated carbon
beds should be installed in the cool lean amine side, just before
the unit contactor. The objective is to properly clean the amine
solvent of any soluble contaminant that can cause foaming prior
to entering the contactor. To achieve this objective, operating
the activated carbon bed at lower temperatures favors adsorption, making it more effective. Using rich amine-activated carbon beds or operating the activated carbon process at high temperatures is not recommended. These cases are often plagued
with problems, low effectiveness and negative results.
Takeaway. Contamination control is a critical step in any optimization process—especially in an amine unit, where contamination is often strongly linked with process performance. Lean
amine filtration and adsorption play a critical role in amine
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66JUNE 2018
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units. The fundamental parameters and lessons shared in Part 1
of this article can be applied to most, if not all amine units.
It is important to differentiate lean amine filtration from rich
amine filtration, as both have different purposes and objectives.
Lean amine filtration and adsorption protects the amine unit
contactor (or absorber) and, in certain cases, the lean-rich heat
exchanger, especially for fouling and foam minimization. The rich
amine filtration (and sometimes coalescence) protects the leanrich heat exchanger and, in particular, the regenerator. In addition, the rich amine filtration ensures that any downstream units
that process the acid gas are also protected.
In Part 2 of this article, fundamental concepts for rich amine
filtration and inlet separation will be discussed.
DAVID ENGEL is Managing Director of Nexo Solutions and
Global Technology Leader for Exion Systems. He holds a BS
degree in industrial chemistry from the University of Santiago,
Chile, and a PhD in organic chemistry from Indiana University in
Bloomington, Indiana. Dr. Engel has published more than 75
articles and has 18 invention patents in his name.
P. SCOTT NORTHROP is a gas treating advisor in the facilities
function of ExxonMobil’s Upstream Research Co. in Houston,
Texas. He received his BS degree from Washington University in
St. Louis, Missouri, and an MS degree and PhD from the California
Institute of Technology, all in chemical engineering. Dr. Northrop
has 28 yr of experience in the industry, and is the author/co-author
of a number of patents, presentations and articles in a variety of
related subjects. He sits on Technical Section F of the Gas Processors Association
(GPA), and on the board of directors of Alberta Sulfur Research Ltd., Canada.