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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:

liii

ipDk

J∆××

=

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.

Figure 1. Dual Sorption Theory Mechanisms

Henry’s Law

Pressure

kd

Pressure

LangmuirSorption

C’h

Ch

B-1

Cd

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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.

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.

Feed SpacerMembrane

Permeate SpacerMembrane

Feed Spacer

PPPPPPeeeeee rrrrrr mmmmmmeeeeee aaaaaa tttttt iiiiii oooooo nnnnnn PPPPPPaaaaaa tttttt hhhhhh

Feed

Permeate

Residual

Residual

Feed

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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.

Figure 3. Hollow Fiber Membrane Element

Residue(Low CO2)

Feed(High CO2)

Permeate(Very High CO2)

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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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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.

Membrane

Preheater

Sales Gas

FilterCoalescer

ParticleFilter

Condensate

Guard Bed

Permeate Gas

Feed Gas

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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

Coalescer

AdsorbtionBed

ParticleFilter

RegenerationBed

Regen GasHeater

Regen GasAir Cooler

Regen GasSeparator

Regen Gas Blower

FEED

Clean Gas

Liquids

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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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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.

0

100

200

300

400

500

600

700

800

900

1,000

C5 C7 C9 C11 C13 C15

Hydrocarbon Type

Hyd

roca

rbon

Con

tent

, ppm Pretreatment Feed

Pretreatment Discharge

+

Feed ContentC10+ 110 ppmC15+ 16 ppmC20+ 2 ppm

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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.

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

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

0

4 0 0

8 0 0

1 ,2 0 0

1 ,6 0 0

2 ,0 0 0

-1 5 0 -1 0 0 -5 0 0 5 0 1 00 1 5 0 2 0 0 2 5 0

T e m p e ra tu re , °F

Pre

ssu

re,

p

D e s ig nb a s is

A c tu a lG a s

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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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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

0.0

0.5

1.0

1.5

2.0

2.5

3.0

0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00Light Heavy

Feed Gas Quality

Rel

ativ

e M

embr

ane

Rep

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men

t Rat

e

Traditional Pretreatment

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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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Final Report to the Energy Research and Development Administration, Report No. FE-2000-4 (1976).

6. Reid, C.E. and E.J. Breton, Journal of Applied Polymer Science, 1,133 (1959). 7. Echt, W.I., “Hybrid Systems, Combining Technologies Leads to More Efficient Gas Conditioning”,

Lawrence Reid Gas Conditioning Conference, (2001). 8. Cook, P.J., and M.S. Losin, Hydrocarbon Processing, April 1995. 9. Baker, R. W., Membrane Technology and Applications, McGraw-Hill 2000 10. Mulder, M., Basic Principles of Membrane Technology, Kluwer Academic Publishers 1996 11. Dortmundt, D. D., Doshi, K., Recent Developments in CO2 Removal Membrane Technology

(1998)