PROPER PRETREATMENT SYSTEMS REDUCE MEMBRANE REPLACEMENT
ELEMENT COSTS AND IMPROVE RELIABILITY
David R. Koch and William R. Buchan
UOP LLC
Des Plaines, Illinois, USA
Tom Cnop
UOP NV
Antwerp, Netherlands
ABSTRACT
Membrane-based CO2 removal systems have become an established technology in the Oil and
Natural Gas Industry. Membrane systems continue to win economic evaluations against traditional
solvent based CO2 removal systems for their simplicity and ease of operation. The size and quantity of
large scale membrane-based CO2 removal systems have increased over the last 15 years, with large
membrane plants currently treating 500-700 MMSCFD of natural gas to pipeline quality specifications.
New large scale designs are approaching flow rates of one BCFD.
The critical component for winning economic evaluations against time-proven solvent-based
technologies has been the increased reliability of membrane elements in membrane processing
facilities. In early membrane systems, suppliers quickly learned the need for adequate pretreatment
systems when processing natural gas; Natural gas can, depending on the source and initial treatment,
contain a variety of contaminants that may reduce membrane performance. Advanced pretreatment
systems have been designed to protect membrane elements and further increase longevity.
Using standard non-regenerable pretreatment, feed gases containing light hydrocarbons known
as dry gas applications can result in a membrane element life exceeding 4-6 years, however, this can
change dramatically with heavier hydrocarbon feed gases. Upgrading to a regenerable adsorbent
pretreatment system for heavy gas streams can now provide similar time of operation before membrane
element replacement may be required.
The improvement to membrane element life has positively impacted the economics of
membrane systems, enabling competitive advantages in even the largest of natural gas processing
applications.
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Introduction
Carbon dioxide falls into the category of acid gases, along with others such as hydrogen sulfide.
It is commonly found in natural gas streams at levels ranging from a few percent to as high as 80%. In
combination with water it is highly corrosive and will rapidly affect pipelines and equipment unless it
is partially removed upstream or exotic and expensive materials of construction are utilized. CO2 also
reduces the heating value of natural gas streams and wastes pipeline and compression capacity. In
NGL extraction plants and LNG plants, CO2 must be removed to low levels to prevent freezing in low
temperature operations.
A wide variety of CO2 / acid gas removal technologies are available. They include reactive
absorption processes such as hot potassium carbonate and amine solutions, cryogenic processes,
adsorption processes such as pressure swing adsorption (PSA), thermal swing adsorption (TSA) and
the subject of this paper, membranes.
Each process has its own advantages and disadvantages, but membranes are increasingly being
selected for new projects, especially for large flow, medium to high CO2 concentration and
remote-location applications. The reasons for this trend are described later in the paper. Membranes
have been widely used in two main CO2 removal applications:
1. Natural gas treating to pipeline specification
2. Enhanced oil recovery (EOR), where CO2 is removed from an associated natural gas stream and
reinjected into the oil field to improve oil recovery
Less common applications such as landfill gas purification exist, but these are fewer in number.
Membrane Performance
Membranes are made by casting a thin layer onto membrane support material or as self
supported hollow fiber tubes of membrane material. Gases are separated in membrane elements by
differences in permeability. Permeable gases are separated in the membrane by first dissolving into the
surface of the membrane, diffusing through the membrane layer and desorbing on the opposite side as
the permeate gas. Non permeable gases remain at high pressure as the residual or residue gas.
Separation of gases in natural gas applications depends on how well the CO2 dissolves into the surface
of the membrane and how well it diffuses through the membrane relative to methane.
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Fick’s law, shown below, is widely used to approximate the solution-diffusion process:
Ji =
k i × Di × ∆pi
l
Where,
Ji
is the membrane flux of component i,
e.g., the molar flow of species i
through the membrane per unit area of
membrane,
ki
is the solubility of component in the
membrane
Di
is the diffusion coefficient of
component i through the membrane
∆pi
is the partial pressure difference of
component i between the feed (high
pressure) and permeate (low pressure)
side of the membrane
l
is the membrane skin layer thickness
Transport through solution-diffusion membranes is dependent upon the product of diffusivity
and solubility called permeability. Pi = ki x Di. The diffusivity coefficient of a membrane for a gas
molecule is defined by the size and frequency of the gas molecule traveling through the membrane
material. The solubility coefficient is a measure of the amount of gas sorbed by the membrane
material.
For ideal dense films, solubility in glassy polymers can be described as a combination of
Henry’s Law and a Langmuir sorption. Henry’s Law predicts the solubility is linear as the
concentration and pressure is increased. Langmuir sorption graphs show that the solubility will reach a
maximum as concentration is increased regardless of additional pressure increases. Glassy polymers
used in CO2 removal can be described with the dual sorption theory that predicts these two sorption
mechanisms occur simultaneously.
Henry’s Law
Langmuir
Sorption
Ch
Cd
kd
C’h
B-1
Pressure
Pressure
Figure 1. Dual Sorption Theory Mechanisms
3 of 18
To simplify matters further, the solubility and diffusion coefficients are usually combined into a
new variable called permeability, P. Pi = ki x Di. This splits Fick’s law into two portions: a
membrane-dependent portion, P/ l and a process-dependent portion, ∆p. To achieve a high flux a
favorable membrane material is needed as well as favorable processing conditions. Note that P/ l , the
parameter describing membrane material and thickness, is also sensitive to a variety of operating
conditions, such as temperature and pressure.
The selectivity of a membrane is defined as the ratio of the permeability of CO2 to that of the
other components in the stream and is thus a measure of how much better the membrane permeates
CO2 compared to other components. High membrane performance is defined as having high
selectivity. Most high performing membranes in natural gas service have selectivity between 15 and
25 indicating that CO2 will permeate the membrane 15-25 times faster than methane.
Membrane Elements
Gas separation membranes are currently manufactured in one of two forms: flat sheet or hollow
fiber. The flat sheets are typically combined into a spiral wound element, while the hollow fibers are
combined into a bundle, similar to a shell and tube heat exchanger. Figures 2 and 3 illustrate these
element types.
Feed
Residual
Permeate
Feed
Residual
Feed Spacer
Membrane
Permeate Spacer
Membrane
Feed Spacer
P e r me a t i o n
Pa t h
Figure 2. Spiral Wound Membrane Element
In the spiral wound arrangement, two flat sheets of membrane with a permeate spacer in
between are glued along three of their sides to form an envelope which is open at one end. Many of
these envelopes are separated by feed spacers and wrapped around a permeate tube, with their open
ends facing the permeate tube.
Feed gas enters along the side of the membrane, and passes through the feed spacers separating
the envelopes. These feed spacers also provide mechanical strength. As the gas travels between the
envelopes, CO2, H2S, H2O and other highly permeable compounds permeate into the envelope. These
permeated components have only one outlet, which is to travel within the envelope to the permeate
tube. The driving force for transport is the differential pressure between the high-pressure feed gas and
the low-pressure permeate. Once the permeate gas reaches the permeate tube it enters it through the
perforated tube. From there it travels down the tube joining permeate from other membrane elements.
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Any gas on the feed side that does not get a chance to permeate, leaves through the side of the element
opposite the feed position.
To construct hollow fiber elements, very fine hollow fibers are wrapped around a central tube
in a highly dense pattern. The natural gas feed flows over and between the fibers and the soluble
components permeate into the hollow fiber. The wrapping pattern used to make the element is such
that both open ends of the fiber terminate at a permeate pot out the bottom of the element. The
permeate gas travels within the fibers until it reaches the permeate pot, where it mixes with permeate
gas from other fibers. A permeate pipe allows the collected gases to exit the element. An illustration
is shown in Figure 3.
As the feed gas passes over the fibers, the components that do not permeate eventually reach
the center tube in the element, which is perforated like the spiral-wound permeate tube. In this case,
however, the central tube is for residual gas collection, not permeate collection.
Residue
Feed
(Low CO2)
(High CO2)
Permeate
(Very High CO2)
Figure 3. Hollow Fiber Membrane Element
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Membrane Modules and Skids
Once they have been manufactured into elements, membranes are connected by a clamp
mechanism and inserted into a steel tube. This is illustrated in Figure 4 using spiral wound membranes
as an example,. Multiple tubes are then mounted in skids, in a horizontal orientation. Figure 5 shows
a horizontal arrangement of tubes with the structural steel supports and a horizontal particle filter in
front of the tubes. Skid-edge isolation valves are installed allowing the module to be taken off line as
needed. A small unit shown in Figure 5 can process approximately 5-30 MMSCFD depending upon
the CO2 content.
For large systems, pretreatment vessels are mounted on their own skids or are installed on their
own foundation next to the membrane tube skid. Smaller systems can have pretreatment vessels and
membrane element tubes mounted on the same skid. Due to the modular construction of the skids, a
membrane system can be installed on site and connected to the rest of the gas plant very quickly.
Figure 4. Membrane module with spiral wound membrane elements
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Figure 5. Membrane Skid
Differences between Spiral Wound and Hollow Fiber Elements
Both spiral wound and hollow fiber elements are used in bulk CO2 removal processes however
major operational differences exist between the two types of elements in this service. Spiral wound
elements are proven to perform at pressures up to 1600 psia. The mechanical integrity of the spiral
wound element can withstand a high pressure environment and the subsequent operational
depressurizations. Hollow fiber elements must decrease their fiber diameter and/or increase their fiber
wall thickness to sustain the fiber mechanical integrity in a high pressure environment. The drawback
of the first is a decrease in performance due to increased permeate pressure drop when decreasing the
internal fiber diameter. Increasing the wall thickness of the hollow fiber decreases the permeance
through hollow fiber and requires more hollow fiber elements for the same application. As a result,
hollow fiber membrane elements for CO2 removal are typically only utilized in lower pressure
applications whereas spiral wound elements can perform in both low and high pressure applications.
Pretreatment
Harmful contaminants, when condensed on the surface of the membrane, can cause permanent
damage and downturn in performance resulting in early membrane replacement. Proper pretreatment
design is therefore critical to the performance of all membrane systems. Systems installed with
inadequate pretreatment generally lead to performance decline rather than complete non-performance.
Therefore a complete feed gas definition is essential during the design phase of a membrane treatment
system to ensure the membrane elements achieve the expected life.
Substances commonly found in natural gas streams that will lower the performance of CO2
removal membranes include:
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• Liquids: Liquids can cause swelling of the membranes, a decrease in the permeance and possible
destruction of membrane integrity.
• Heavy hydrocarbons, approximately > C15: Significant levels of heavy hydrocarbons slowly coat
the membrane surface, thus decreasing permeation capacity.
• Particulate Material: This is not as much of an issue with spiral-wound membrane as it is with
hollow fiber membranes, which have lower flow area. However, long term flow of particles into
any membrane could eventually block them and/or tear them.
• Certain Corrosion Inhibitors and Well Additives: Some corrosion inhibitors and well additives
are destructive to the membrane material.
Some membrane vendors have observed membrane damage due to aromatic and poly-nuclear
compounds in the liquid phase. On the other hand, UOP designed a number of landfill gas applications
where a wide variety of volatile organic compounds (VOCs), including halogenated VOCs and
aromatics, are encountered in the vapor phase and no membrane damage has been reported in these
applications. The pretreatment system must provide adequate protection to ensure that components
stay in the vapor phase or are completely removed.
Two effects may cause condensation within the membrane. First, the permeate gas cools down
as it passes through the membrane as a result of the Joule-Thomson effect. Second, since CO2 and the
lighter hydrocarbons permeate faster than the heavy hydrocarbons, the residue gas hydrocarbon dew
point increases through the membrane. Condensation within the membrane is prevented by providing
a margin of superheat.
The pretreatment system must have a predetermined safety margin, and must be highly flexible
to cope with unexpected circumstances. Experience has shown that the heavy hydrocarbon content of
a feed gas can vary widely from initial estimates, and also from month to month during the plant’s life.
Large variations are seen even between different wells in the same area. A reliable pretreatment
system must take this variation into account and must be able to protect the membranes against a wide
range of (possibly unknown) contaminants.
Traditional Pretreatment
The traditional CO2 removal membrane pretreatment scheme, illustrated in Figure 6, consists of the
following items of equipment:
• Coalescing filter for liquid and mist elimination
• Non-regenerable adsorbent bed for trace contaminant removal
• Particle filter for dust removal after the adsorbent bed
• Heater for providing sufficient superheat to the gas
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Sales Gas
Filter
Coalescer
Guard Bed
Preheater
Particle
Filter
Membrane
Feed Gas
Condensate
Permeate Gas
Figure 6. Traditional Membrane Pretreatment
Traditional pretreatment is adequate for light, stable composition gases, but has the limitation
that the adsorbent bed is the only item removing heavy hydrocarbons. If there is a sudden upward
surge in heavy hydrocarbon content, or the feed gas is heavier than initially estimated, it can become
saturated within a very short period. Since these beds are typically non-regenerable, they can only
become functional again after the adsorbent has been replaced.
Regenerative Pretreatment
Regenerative pretreatment is called for in cases where the operator might expect:
•
Wide variation in the feed gas content
•
Significant heavy hydrocarbon or other contaminant content
•
Heavier feed gas than analyzed based on the known information from nearby wells or adjacent
reservoirs.
UOP’s regenerative pretreatment scheme is illustrated in Figure 7. The feed gas is routed to a
filter-coalescer to remove liquids or entrained particles. The liquid-free gas is then treated in a thermal
swing regenerable adsorbent-based system where water, heavy hydrocarbons and other harmful
components are completely removed. The contaminant-free gas passes through a particle filter to
recover any adsorbent fines. Membrane feed gas temperature control is provided by a preheater. The
regeneration system for this enhanced pretreatment scheme is very similar to thermal swing molecular
sieve units.
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Clean Gas
Regen Gas Blower
Adsorbtion
Bed
Regen Gas
Heater
Regen Gas
Separator
Regen Gas
Air Cooler
Particle
Filter
FEED
Regeneration
Bed
Coalescer
Liquids
Figure 7. Regenerative Pretreatment Scheme
The regenerative system has a major advantage in that water and other contaminants such as
mercury are removed along with the heavy hydrocarbons, so no additional dehydration is required.
With regenerative pretreatment, it is also possible to remove mercury and mercaptans in the same bed
without the need for extra vessels.
Reference Plants
To illustrate the benefits of effective pretreatment, several installations are presented that have
been in service for a long time. UOP spiral wound membrane systems using standard pretreatment and
regenerative pretreatment are described. Standard pretreatment examples in Michigan and Pakistan
explain the limitations of standard pretreatment. Regenerative pretreatment systems in Pakistan and
Mexico document the benefits of installing regenerative pretreatment systems.
Michigan, USA
This plant has been operated since August of 1994. The facility processes 40 MMSCFD of gas,
removing CO2 from 11% to the pipeline specification of less than 2%. The gas is simultaneously
dehydrated to 4 lbs H2O/MMSCF.
A two-stage configuration is used to minimize methane losses. In a two stage membrane
system, the permeate stream from the first membrane stage is recompressed and is sent to a second
stage membrane where it is separated into a CO2 depleted residue stream and a CO2 enriched permeate
stream. The CO2 enriched permeate stream is sent to the vent whereas the hydrocarbon rich residue
stream is recycled to the inlet of the first stage membrane for additional hydrocarbon recovery.
The feed gas to the facility contains only light hydrocarbons and the plant has operated
successfully using a traditional pretreatment system. The plant has experienced very high on-stream
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efficiency and operates most of the time without operators on site. An article on this plant appeared in
the April 1995 issue of Hydrocarbon Processing (Ref. 8).
As of June of 2004 the plant is operating with 11% inlet CO2 and is still meeting pipeline
specifications of less then 2% CO2 and water less then 1 lb/MMSCFD after ~11 years of continuous
operation.
During the initial technology selection process the customer wanted a system that did not
require a large operating staff. After 11 years of operation the plant still operates with one operator
working an 8-hour shift, 5 days per week. A relief operator is available 2-3 days per week. This low
manpower requirement allows operators to work at multiple plants and keeps manpower costs low.
In the 1995 article, an operating cost comparison was made between an amine plant and a
membrane plant. The operating cost table compared Labor, Transportation, Utilities, Fuel Gas and
Expendables (membrane elements, activated carbon and filter coalescer elements). After 11 years of
operation the actual replacement element costs were only 20% of the estimate used in the 1995 paper.
This is a major operational savings realized each year. Many of the original membrane elements
installed in 1994 are still in service after 11 years of service.
During membrane element replacement it may not be necessary to replace all the membrane
elements. A major advantage of using a spiral wound element is the fact that a high number of
membrane elements are installed in series in each tube. Since plant performance is usually restored by
replacing the first few elements in each tube, spiral wound elements allow partial replacement of
membrane area that performs the greatest portion of the separation.
The Michigan customer has been satisfied with the technology selection of a membrane plant in
lieu of an amine system. Since this installation this customer has installed a separate membrane plant
at another facility adjacent to an aging amine facility. The online factor is consistently above 98% for
both membrane plants. The membrane installation has met or exceeds the customer expectations on
performance and operating costs.
Mexico Enhanced Oil Recovery
UOP installed a membrane system in an enhanced oil recovery (EOR) facility in Mexico. The
system processes 120 MMSCFD of inlet gas containing 70% CO2. The purified CO2 gas stream
contains 93% CO2 and is reinjected. The hydrocarbon product contains 5% CO2 and is transported to a
nearby gas plant for further processing. Figure 8 shows the membrane system with the regenerative
pretreatment vessels in the foreground and membrane skids behind them.
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Figure 8. Enhanced Oil Recovery System in Mexico
The feed gas to this facility is saturated with heavy hydrocarbons from enhanced oil recovery
and the membrane system requires a regenerative pretreatment system to achieve long membrane life.
The unit was started up in July 1997 and has maintained product specifications. The unit has sustained
high reliability and longevity of the membrane elements and regenerative adsorbent.
Recent gas analysis has shown that the pretreatment system continues to exceed expectations.
Figure 9 illustrates recent gas analyses before and after the pretreatment system. The feed gas
contained 934 ppm C7+ compounds, which were reduced to 55 ppm after the pretreatment. The C9+
content was completely removed.
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1,000
Hydrocarbon Content, ppm
900
800
Pretreatment Feed
700
Pretreatment Discharge
600
500
Feed Content
400
C10+ 110 ppm
C15+ 16 ppm
2 ppm
C20+
300
200
100
0
C5
C7
C9
C11
C13
C15 +
Hydrocarbon Type
Figure 9. Pretreatment Performance
Enhanced oil recovery is a much harsher environment for membrane systems than typical CO2 removal
applications. In enhanced oil recovery the CO2 must be purified for reinjection and the sales gas must
meet pipeline specifications. After three years 34% of the total elements installed in 1997 were
replaced as part of routine maintenance to the plant. After four years, another 32% of the elements
installed in 1997 were replaced. The remainder of the original elements will be replaced next year and
will have been in service for 8 years. The regenerative pretreatment system installed in Mexico is
directly responsible for the long membrane life achieved in the harsh environment of an enhanced oil
recovery operation.
Pakistan
Two of the largest land based CO2 removal membrane systems in the world are the UOP
membrane units installed in Pakistan. Both of these plants specified membranes as the CO2 removal
technology after a rigorous comparison against solvent technologies, because of their simplicity, ease
of use, and high reliability, essential attributes for remotely located plants. These criteria have all been
met, and significant lessons have been learned. For example, a major impetus in the development of
UOP advanced pretreatment systems came from experience with the Pakistan 1 unit.
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Pakistan 1
When this facility started up in 1995, it was the largest membrane-based natural gas processing plant in
the world. It has now been in operation for more than 9 years using UOP cellulose acetate membranes.
The Pakistan 1 system is a two-stage unit designed to treat 210 MMSCFD of feed gas at 1,305 psia.
The CO2 content is reduced from 12% to less than 3%.
The system was originally designed for a light feed gas with standard pretreatment. After start
up, the feed gas deviated significantly from the original design specification. Figure 10 shows the
difference in phase envelopes between the design basis and the actual feed composition. The designed
pretreatment system did not have enough flexibility to compensate for this large deviation from the
design basis for two reasons; the non-regenerative adsorbent beds were saturated within a short amount
of time and the preheaters were not large enough to achieve proper operating temperatures required for
the new feed composition.
The standard way to operate with a heavier then expected feed gas is to operate at higher
temperatures and this was the initial solution to this unexpected situation. The higher temperature
increases the margin between the gas dew point and the operating temperature. This margin prevents
condensation on the membrane elements. Due to a lower production requirement, the customer was
able to sufficiently elevate the feed temperature with the existing preheaters. After 7 years of operation
using standard pretreatment, the membrane system was retrofitted with a regenerative pretreatment
system to shift the phase envelope and allow operational temperatures at or below the initial design.
Along with the regenerative pretreatment system, new elements were installed and since 2002 the plant
production exceeds the design production capacity of 210 MMSCFD feed gas.
E x p e c te d a n d A c tu a l P h a s e E n v e lo p e s
2 ,0 0 0
P r e s s u re , p
1 ,6 0 0
A c tu a l
G as
1 ,2 0 0
800
D e s ig n
b a s is
400
0
-1 5 0
-1 0 0
-5 0
0
50
100
150
200
250
T e m p e r a tu re , ° F
Figure 10. Pakistan 1 Design and Actual Phase Envelope
Pakistan 2
The UOP membrane system, Pakistan 2, is now the largest land based membrane natural gas
plant in the world. It was originally designed to produce 235 MMSCFD of natural gas at 855 psia. The
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CO2 content is reduced from 6.5 to less than 2%. The unit was designed to also provide gas
dehydration to pipeline specifications.
The original Pakistan 2 membrane system was designed in two 50% membrane trains. Each
membrane train consists of a conventional pretreatment section and a membrane section. The
pretreatment section has filter coalescers, guard beds, and particle filters. Membrane feed heaters are
included in this design to maintain stable membrane process conditions.
This plant started up in 1995 and has been in operation continuously for 9 years, with the
majority of the original membrane elements still in operation at the 2003 upgrade. UOP provided on
site assistance from the loading of the membrane elements through start-up and remained until the
customer was fully comfortable with the equipment. The plant continues to operate routinely,
processing all gas available unless limited by pipeline demand.
The Pakistan 2 system is proof of the ruggedness of UOP membrane systems and cellulose
acetate membranes. The feed gas contained a significant heavy hydrocarbon content as well as
polynuclear aromatics, which are known to damage other membranes. In spite of these contaminants,
the unit has been operating at design capacity.
An upgrade of the Pakistan 2 plant was successfully started up in 2003. The plant capacity was
increased from 235 MMSCFD to 500 MMSCFD. The Pakistan 2 membrane plant was retrofitted with
a chiller system and a regenerative pretreatment system to allow colder operation. The compression
system was revamped and high performance membrane elements installed in the existing membrane
skids. The result was an expansion of the plant that more than doubled the capacity of the plant
without the requirement of additional recycle compressors and only 30% additional membrane area.
Based on the success of these existing installations, UOP has continued to win new larger scale
membrane units. Recently UOP was awarded two major membrane installations that treat 650-700
MMSCFD of natural gas each. Both of these plants will use a regenerative pretreatment system to
protect the membrane elements. The new customers agreed that the regenerative pretreatment system
designed by UOP will provide the best possible protection for the membrane system.
Membrane Life
Depending upon operating conditions and composition of the feed gas, actual plant operations show a
membrane element life and membrane replacement rates that are exceeding past expectations and
customer OPEX forecasts. Several units have shown membrane element life to exceed 4-6 years with
some elements still in continuous operation after 11 years. Experience confirms that there is a
significant difference in replacement element rate between plants treating a light feed gas and plants
treating a heavy feed gas. In systems treating a heavy gas, the installation of a regenerative
pretreatment system decreases the yearly membrane element replacement costs.
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3.0
Traditional Pretreatment
Relative Membrane
Replacement Rate
2.5
2.0
Regenerative Pretreatment
1.5
1.0
0.5
0.0
0.00
1.00
2.00
3.00
4.00
5.00
6.00
Light
7.00
8.00
9.00
10.00
Heavy
Feed Gas Quality
Figure 11. Pretreatment Impact on Element Replacement Rate
The graph in Figure 11 plots the relative rate of membrane element replacements versus the
quality of the feed gas. The data points on the graph represent the relative membrane replacement
rates for some of the units represented in this paper. Light feed gas quality is defined as feed gas
containing trace components larger then C4 and/or CO2 concentrations of approximately 6-10%.
Heavy feed gas quality is defined as feed gas containing ppm levels of C15+ components and/or CO2
concentrations of 40-80%. The graph shows an increasing economic benefit for installing regenerative
pretreatment as the feed gas quality increases in CO2 and heavy hydrocarbon concentration. Systems
with very light feed gas compositions may realize little economic gain from installing regenerative
pretreatment and typically regenerative pretreatment would not be proposed. On the other hand,
typical enhanced oil recovery systems with heavy hydrocarbons and high CO2 concentrations realize
tremendous economic benefit from regenerative pretreatment.
The Michigan plant has been successfully operating continuously for 11 years. The feed gas to
the plant is a coal seam gas which contains very little heavy hydrocarbons. Little or no liquid
hydrocarbons are produced from this plant. The activated carbon traditional pretreatment system has
provided adequate protection against contaminants and the membrane life has exceeded the forecasted
replacement schedule.
The Mexico plant has been successfully operating for 7 years. The feed gas originates from an
enhanced oil recovery operation and the feed is saturated with heavy hydrocarbons. The system is
installed with regenerable pretreatment to protect the membrane elements. A portion of the elements
were replaced over a four year period and the plant still continues to meet expected performance with
part of the original membrane elements still in operation. The heavy feed gas composition in enhanced
oil recovery requires a regenerable pretreatment system to ensure membrane element longevity.
The Pakistan 1 plant has been operating for 9 years. During the first 7 years the plant operated
with a heavy feed composition using standard pretreatment with a yearly membrane replacement
higher than average because the feed gas was significantly heavier then the initial design. After 7
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years, the plant was retrofitted with regenerable pretreatment and membrane element replacement for
this plant is now similar to that expected in a light feed gas plant with traditional pretreatment.
The Pakistan 2 plant has also been operating for 9 years with a heavy feed composition.
During the first 8 years the plant operated successfully with a heavy feed composition using standard
pretreatment and experienced a low membrane replacement rate. After 8 years, the plant was
revamped with regenerable pretreatment to increase the plant capacity from 235 MMSCFD to 500
MMSCFD. Since the startup of the revamp in 2003, no membrane elements have been replaced.
Conclusions
UOP has presented an example of operating plants that performed well using traditional
pretreatment and this performance is measured by the low quantity of replacement elements for the
plant. Also presented is an example of an enhanced oil recovery (EOR) operation using regenerative
pretreatment. The EOR operation contained high CO2 concentrations and heavy hydrocarbons. This
plant has been successfully operating for 7 years and the performance is measured by the reasonable
quantity of replacement element used in this severe service.
The Pakistan 1 example confirmed the improvement of replacement element rates when
installing a regenerative pretreatment system. This plant encountered a heavier than expected feed
composition when using traditional pretreatment and experienced a moderately high membrane
element replacement rate. During the first 7 years the plant met performance by changing elements at
a replacement rate consistent with being challenged by a heavy feed gas. After the installation of a
regenerative pretreatment system the replacement element rate improved to levels typical of a light fed
gas plant.
The Pakistan 2 example presented a creative example of using regenerative pretreatment to
revamp an existing plant. At the Pakistan 2 plant, the regenerative pretreatment benefits included
increased capacity without additional compression horsepower and improved replacement element
rates. Although this plant operated with heavy hydrocarbons and polynuclear aromatics using standard
pretreatment for 8 years the customer found the benefits of a regenerative pretreatment system
warranted the additional capital investment. The revamped plant has been operating since 2003 and is
expected to achieve element replacement rates typical of a light feed gas plant.
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