Technical Field

The present invention relates to a process and system for treating a natural gas feedstock.

Background

Natural gas is presently the third most-utilized form of fossil fuel energy and it is also well-known as a clean energy source. As predicted by the International Energy Outlook 2011 (IEO), by 2035, natural gas consumption will increase by 52% compared to 2008, accounting for 24% of the energy consuming market, and surpassing coal as the second most utilized fuel.

Extracted natural gas usually contains a certain amount of acid gases (or "sour gases") , such as carbon dioxide (C0 ₂ ) , hydrogen sulfide (H ₂ S) , etc. These acid gases cause reduction in the heat value of the natural gas and further corrode pipelines used for their transportation. Hence, a number of methods have been proposed for the separation and removal of such acid gases. Ideally, carbon dioxide concentration in commercially produced natural gas should not exceed 3 mol %.

Presently known techniques for acid gas separation in the industry include chemical and physical absorption, solid adsorption, cryogenic distillation, and membrane separation. Among all these methods, amine-based CO2 absorption is the most frequently used. Amine-based CO2 absorption methods involve removing CO2 by reacting amine solvents with CO2 present in the natural gas. This reaction is usually performed in an absorption column. Typically, the resultant rich amine solution (i.e., amine solution that is rich in CO2 ) is later regenerated via heating to desorb CO ₂ . However, this method entails a number of disadvantages, including the need to install and maintain large-scale equipment (e.g., absorption columns) , the attendant high capital costs for these installations, and the small effective mass transfer area afforded by absorption columns. Furthermore, there is significant difficulty in controlling gas and liquid flow rates independently in a conventional absorption column, which renders this method unsuitable for treating natural gas with high acid gas content. During operation, absorption columns also encounter problems such as entrainment, flooding, weeping, leakage, etc.

Moreover, with the development of natural gas extraction processes trending towards extracting natural gas with relatively high sour gas concentrations, and which is performed at off-shore sites, the continued use of conventional absorption columns is increasingly disadvantageous and fast becoming untenable.

To address the technical drawbacks of traditional absorption columns, it has been proposed to utilize membrane contactors for the treatment of natural gas. A membrane contactor is a device that achieves gas/liquid mass transfer without dispersion or mixing of one phase within another. Generally, in a membrane contactor, the gas and liquid phases are partitioned by a permeable membrane, wherein mass transfer occurs at a gas/liquid interface provided on the membrane surface.

Compared to the conventional separation equipment, such as the packed-bed tower, spray tower, venturi scrubber or bubble column, the membrane contactor has the following advantages: The two phases flow on opposite sides (i.e., shell and tube sides) of a membrane contactor and thus do not mix. This is useful in avoiding problems such as flooding, foaming, channeling and entrainment, which are often encountered in packed- bed/tray columns. In addition, the specific gas-liquid interfacial area (i.e., the interfacial surface area per unit volume of the membrane contactor) offered by membrane contactors is relatively higher, especially in the case of hollow fiber membrane contactors.

For commercially available hollow fiber membrane modules, the specific interfacial area varies between 1500-3000 m ² /m ³ of contactor volume, depending on the diameter and packing density of the hollow fiber membranes. Notably, the specific interfacial area is significantly higher than the surface area offered by conventional absorption apparatuses (which varies from 100-800 m ² /m ³ ) , e.g., stirred tanks, bubble columns, packed and plate columns.

Additionally, membrane contactors provide a compact structure and thus reduce footprint. Furthermore, membrane contactors allow the flow rates of the gas and liquid phases to be independently controlled and adjusted, and are thus suitable for use in the treatment of natural gas with high acid content. Moreover, as the focus of natural gas extraction gradually shifts to offshore operations, tall and cumbersome absorption towers will not be suited for use atop unsteady off-shore platforms.

At the moment, membrane contactors remain confined to natural gas treatment operations performed at low pressures (<1.0MPa) and where the natural gas contains a low concentration of acid gases (less than 10%) . This could be due to known problems in operating membrane contactors under high pressure and high acid gas conditions. For instance, where the natural gas contains a large molar fraction of acid gases, condensation of heavier components in the natural gas may occur within the membrane contactor after removal of the acid gases due to a change in the gas composition. This problem may be further compounded by high pressure operating conditions. This causes the formation of heavy hydrocarbon liquid droplets, which may adhere to the membrane surface and foul the membrane.

Furthermore, processing high pressure natural gas will entail supplying an equally pressurized stream of absorbent. However, under such high pressure operating conditions, minor fluctuations in the pressure differential between the natural gas and absorbent fluid may lead to undesirable effects. For instance, if the pressure of the absorbent is lower that the natural gas pressure, some of the natural gas components, particularly useful compounds like methane (CH ₄ ) , may be forced through the membrane pores and become lost to the absorbent stream. On the other hand, if the absorbent is at a higher pressure relative to the natural gas, the absorbent molecules may enter the pores of the membrane, resulting in clogging of the membrane pores, or even causing absorbent breakthrough into the gas stream at extreme conditions. This reduces the available surface area for mass transfer and hence reduces the overall efficiency of the de-souring process.

The above drawbacks have thus discouraged the use of membrane contactors for high pressure extractions of relatively acidic natural gas. However, natural gas is usually extracted directly from gas wells pressurized conditions (normally from about greater than 1.0 to 8.0MPa) . It is preferable to treat the natural gas at the conditions which the natural gas is being extracted, to avoid redundant and costly de-pressurization steps. Doing so is further expected to be more practical and economically palatable. Accordingly, there is a need to provide a system and method for treating natural gas that overcomes or at least ameliorates the technical issues described above. Summary

In a first aspect, there is provided a process for removing acid gas from a natural gas stream, the process comprising the steps of: (a) passing a feed stream comprising natural gas and acid gas through a feed side of a membrane at a feed pressure (P _F ) ; (b) passing an absorbent stream comprising an absorbent fluid on an absorbent side of the membrane, opposite said feed side, wherein the pressure of said absorbent stream is at an absorbent pressure (P _A ) , to remove acid gas from said natural gas stream; (c) controlling at least one of the feed pressure (P _F ) and absorbent pressure (P _A ) so that the (P _A ) is substantially equal to or greater than the (P _F ) without allowing the absorbent fluid to reside in the pores of the membrane.

The disclosed process is advantageously suited for processing natural gas feed streams with high pressures ranging from 1.0 MPa to 15 MPa. In this regard, the disclosed process advantageously provides a controlling step which is capable of maintaining P _F and P _A to be substantially the same. In one embodiment, during the treatment process, the differential pressure (ΔΡ) between the absorbent fluid and the natural gas feed stream is advantageously controlled on or below a pre-determined set point. In one embodiment, if the pressure of the absorbent fluid becomes significantly higher than the natural gas pressure, i.e., where the pressure differential exceeds the pre-determined set point, the controlling step may comprise a step of removing absorbent from the absorbent pressure to thereby reduce the pressure P _A .

In another aspect, there is provided a system for removing acid gas from a natural gas stream, the system comprising: a membrane contactor comprising an array of membranes, each membrane having a feed side and an absorbent side opposite said feed side; a feed stream comprising natural gas and acid gas in fluid communication with the feed side of said membranes and being at a feed pressure (P _F ) ; an absorbent stream comprising an absorbent fluid in fluid communication with the absorbent side of the membrane at an absorbent pressure (P _A ) ; control means for controlling at least one of the feed pressure (P _F ) and absorbent pressure (PA) so that the (P _A ) is substantially equal to or greater than the (PF) without allowing the absorbent fluid to reside in the pores of the membrane.

Advantageously, the disclosed system is capable of treating high pressure natural gas feed streams as the control means act to prevent clogging of the membrane pores by the pressurized absorbent.

In one embodiment, the system further comprises heating means disposed upstream of the membrane contactor for heating the natural gas feed stream to on or above a calculated dew point of the natural gas feed stream.

Advantageously, by heating the natural gas feed stream to a temperature on or above its dew point, condensation of heavier hydrocarbon components in the natural gas feedstock can be avoided, thereby preventing the formation of liquid hydrocarbon droplets which may adhere to the surface of the membranes and cause membrane fouling during operation. In one embodiment, natural gas that is being passed towards the membrane contactor is substantially gaseous. Definitions

The following words and terms used herein shall have the meaning indicated:

Unless otherwise stated, percentages used to denote the concentration of acid gases, e.g., CO ₂ , H ₂ S, shall be taken to refer to mole percentages.

In the context of the present specification, the term "micro-porous" when used to refer to a permeable membrane is to be taken to refer to a permeable membrane having pore sizes in the range of about 0.01 to about 10 ym.

The word "substantially" does not exclude "completely" e.g. a composition which is "substantially free" from Y may be completely free from Y. Where necessary, the word "substantially" may be omitted from the definition of the invention.

The term "substantially equal" in the context of this specification when referring to feed pressure (P _F ) and absorbent pressure (P _A ) means that the (P _F ) and (P _A ) are the same or do not vary from each other by more than 5% or less, or 4% or less, or 3% or less or 2% or less, or 1% or less. For the avoidance of doubt, the expression "substantially equal" may be taken to mean that P _A >P _F or P _A <P _F , as long as the ΔΡ does not exceed a critical pressure differential value resulting in liquid entering the membrane. The critical pressure differential for membrane wetting can be derived by one skilled in the art and is dependent on several factors including pore size of the membrane, the type of absorbent used, the material of the membrane, operation temperature, etc.

Unless specified otherwise, the terms "comprising" and "comprise", and grammatical variants thereof, are intended to represent "open" or "inclusive" language such that they include recited elements but also permit inclusion of additional, unrecited elements.

As used herein, the term "about", in the context of concentrations of components of the formulations, typically means +/- 5% of the stated value, more typically +/- 4% of the stated value, more typically +/- 3% of the stated value, more typically, +/- 2% of the stated value, even more typically +/- 1% of the stated value, and even more typically +/- 0.5% of the stated value.

Throughout this disclosure, certain embodiments may be disclosed in a range format. It should be understood that the description in range format is merely for convenience and brevity and should not be construed as an inflexible limitation on the scope of the disclosed ranges. Accordingly, the description of a range should be considered to have specifically disclosed all the possible sub-ranges as well as individual numerical values within that range. For example, description of a range such as from 1 to 6 should be considered to have specifically disclosed sub-ranges such as from 1 to 3, from 1 to 4, from 1 to 5, from 2 to 4, from 2 to 6, from 3 to 6 etc., as well as individual numbers within that range, for example, 1, 2, 3, 4, 5, and 6. This applies regardless of the breadth of the range.

Disclosure of Optional Embodiments

Exemplary, non-limiting embodiments of the above disclosed process for treating a natural gas feed stream will now be disclosed.

In one embodiment of the disclosed process, controlling step (c) is configured to maintain P _A at a value that is not 5% greater than P _F . In a preferred embodiment, P _A is not 4% greater than P _F . More preferably, P _A is not 3% greater than P _F . Even more preferably, P _A is not 2% greater than P _F . In one preferred embodiment, P _A is not 1% greater than P _F .

In one embodiment, the pressure difference between P _A and P _F is not greater than a pressure selected from: 0.2 MPa, 0.19 MPa, 0.18 MPa, 0.17 MPa, 0.16 MPa, 0.15 MPa, 0.14 MPa, 0.13 MPa, 0.12 MPa, 0.11 MPa, 0.10 MPa, 0.09 MPa, 0.08 MPa, 0.07 MPa, 0.06 MPa, 0.05 MPa, 0.04 MPa, 0.03 MPa, 0.025 MPa, 0.02 MPa, and 0.01 MPa.

In one embodiment, the natural gas feed stream may comprise C1-C6 alkanes, CO2, H ₂ S, and water (H ₂ o) . The natural gas may contain from about 3% to about 85% acid gaese, i.e., CO ₂ or ¾S or mixtures thereof. In other embodiments, the natural gas feedstock may contain about at least about 5%, about 10%, about 15%, about 20%, about 25%, about 30%, about 35%, about 40%, about 45%, about 50%, about 55%, about 60%, about 65%, about 70%, about 75%, about 80% and at least about 85% acid gases. In one embodiment, the natural gas feedstock may contain from about 9% to about 61% acid gases.

In one embodiment, prior to passing step (a) , the disclosed process further comprises a step of (d) , heating the natural gas feed stream to on or above a calculated dew point. In one embodiment, the dew point may be calculated based on the composition of the natural gas feed stream. In yet another embodiment, the dew point may be calculated based on a modified composition of the natural gas feed stream which omits the acid gas fractions. Advantageously, by calculating the dew point based on the modified composition, the calculated dew point would be a closer approximation of state of the natural gas after the acid gases have been absorbed into the absorbent. In one embodiment, heating step (d) comprises heating the natural gas feed stream to a temperature at least 5°C above the calculated dew point.

In one embodiment, the heating step (d) comprises the following steps: (dl) analyzing the composition of the natural gas feed stream; (d2) calculating a dew point of said natural gas feedstock; and (d3) heating the natural gas feed stream to a temperature on or above the calculated dew point.

Analyzing step (dl) may comprise analyzing the specific composition of the natural gas and determining the relative fractions of the various components present therein. The calculation may be performed by a computer program. In one embodiment, during calculation step (d2), the dew point is calculated based on a reference natural gas composition consisting of the analyzed components of the natural gas feedstock minus acid gas components, e.g., CO ₂ and ¾S. Advantageously, this calculation modification is performed to derive the theoretical dew point of the treated (de-soured) natural gas after the acid gases have been stripped / absorbed by the absorbent. This modification ensures that a more accurate dew point is calculated and prevents condensation of heavier natural gas components on the membrane during operation, which may cause membrane fouling.

In one embodiment, controlling step (C) may further comprise the following steps: (cl) measuring a pressure differential (ΔΡ) between the absorbent and the natural gas stream; (c2) comparing the ΔΡ to a pre-determined set point; and (c3) reducing a flow rate of the absorbent when the measured pressure differential (ΔΡ) is greater than the pre-determined set point.

Reducing step (c3) may comprise removing absorbent from the absorbent stream. In one embodiment, this step may comprise bypassing at least a fraction of the absorbent being supplied to the membrane. The bypass stream may be routed back to a storage area, e.g., an absorbent storage unit. As a result, the total flow rate of absorbent being supplied to the membrane may be reduced, causing a drop in P _A . This bypassing step may comprise activating one or more valves to divert the flow of absorbent away from the membrane. Reducing step (c3) may comprise making step-wise reductions to the absorbent flow rate such that ΔΡ is returned to an acceptable value on or below the pre-determined set point.

In one embodiment, the measured pressure differential, ΔΡ may be represented by the following equation (I)

Equation (I) : ΔΡ = P _A - P _F

wherein P _A represents a pressure of the absorbent entering an absorbent side of the membrane; and P _F represents a pressure of the natural gas stream passing through the feed side of the membrane. In one embodiment, ΔΡ is a value in a range from about 0 to about 0.2 MPa. In other embodiments, ΔΡ may be a value selected from the group consisting of: 0, 0.01 MPa, 0.02 MPa, 0.03 MPa, 0.04 MPa, 0.05 MPa, 0.06 MPa, 0.07 MPa, 0.08 MPa, 0.09 MPa, 0.1 MPa, 0.11 MPa, 0.12 MPa, 0.13 MPa, 0.14 MPa, 0.15 MPa, 0.16 MPa, 0.17 MPa, 0.18 MPa, 0.19 MPa and 0.20 MPa.

In the disclosed process, the absorbent stream and the natural gas stream may be contacted in a countercurrent or a co-current configuration.

The disclosed process may be used to treat a natural gas feed stream having a high pressure of between 1.0 to 15.0 MPa. In certain embodiments, the natural gas feed stream may exhibit pressures selected from the group consisting of: 1.0 MPa, 2.0 MPa, 3.0 MPa, 4.0 MPa, 5.0 MPa, 6.0 MPa, 7.0 MPa, 8.0 MPa, 9.0 MPa, 10.0 MPa, 11.0 MPa, 12.0 MPa, 13.0 MPa, 14.0 MPa and 15.0 MPa. In one embodiment, the natural gas feedstock may exhibit a pressure of at least 5.0 MPa to about 15.0 MPa. In another embodiment, the natural gas feedstock may exhibit a pressure of at least 8.0 MPa. In one embodiment, the natural gas feedstock may exhibit a pressure of at least 8.0 MPa to 12 MPa.

In one embodiment, the absorbent may be an amine solution selected from the group consisting of: 2,2- methyldiethanolamine (MDEA) , diethanolamine (DEA) , diethylenetriamine (DETA) , triethylenetetramine (TETA) , or mixtures thereof. In another embodiment, the absorbent may be an ionic liquid selected from the group consisting of: phosphonium, ammonium, pyridinium and imidazolium based ionic liquids. In yet another embodiment, the absorbent is sea water.

The disclosed method may comprise additional pre- treatment steps performed prior to heating step (d) . Exemplary pre-treatment steps may include, but are not limited to, a gravity separation, a gas/liquid separation, and filtration. Advantageously, the natural gas after pre-treatment preferably does not contain liquid particles or other particulate matter with sizes larger than the pore size of the membrane used in the membrane contactor .

Exemplary, non-limiting embodiments of the above disclosed system for treating a natural gas feed stream will now be disclosed.

In one embodiment, the control means may comprise at least one pressure analyzer configured to measure a differential pressure (ΔΡ) between the absorbent stream and the natural gas stream, wherein ΔΡ = P _A - P _F . The pressure analyzer may comprise a plurality of pressure sensors disposed at suitably selected locations of the treatment system for measuring the pressures of the absorbent and natural gas stream. For instance, sensors may be provided at the absorbent inlet of the membrane contactor to measure the pressure of the absorbent supplied to the membrane contactor. Sensors may also be provided at the feed outlet of the membrane contactor for measuring the pressure of the product natural gas exiting the membrane contactor. The pressure analyzer may further comprise an electronic means, e.g., a computer, configured to receive the pressure values from the pressure sensors and to compute the differential pressure (ΔΡ) of the absorbent and the natural gas stream.

In one embodiment, the pressure analyzer may be operatively communicated with a flow controller, said flow controller being configured to remove absorbent from the absorbent stream. For instance, the flow controller may be configured to reduce flow rate of the absorbent when the measured ΔΡ is greater than a pre-determined set point. The disclosed system may further comprise at least one bypass route for bypassing at least a portion of the absorbent being transmitted towards the membrane contactor. As a result of the bypass, the total flow rate of absorbent being supplied to the membrane contactor may be reduced, thus causing a drop in pressure of the absorbent P _A . In some embodiments, at least one or more valves may be disposed along said bypass route, and these bypass valves may be activated by the flow controller to open or close to varying extents, to achieve flow rate reduction of the absorbent. For instance, where ΔΡ is greater than the pre-determined set point, the flow controller may be programmed to open the bypass valves to allow a fraction of the absorbent to be bypassed from the membrane contactor, wherein the bypass quantity is carefully controlled such that ΔΡ is returned to an acceptable value on or below the set point.

In some embodiments, the predetermined set point is an integer value that ranges from about 0 to about 0.2 MPa. In one embodimemt, the set point is selected to be 0.08 MPa.

In certain embodiments of the disclosed system, heating means may be provided to heat the natural gas stream prior to entering the membrane contactor. The heating means may be operatively communicated with a temperature control system comprising an analyzer and a temperature controller. The analyzer may be configured to calculate the dew point of the natural gas feed stream. The calculated dew point may be relayed to the temperature controller which is in turn configured to control the heating means to heat the natural gas feed stream on or above this calculated dew point.

This calculation step may comprise analyzing the specific composition of the natural gas and determining the relative fractions of the various components present therein. The calculation may be performed by a computer program. In one embodiment, the dew point is calculated based on a reference natural gas composition consisting of the analyzed components of the natural gas feedstock minus acid gas components, e.g., CO ₂ and H ₂ S. Advantageously, this calculation modification is done to derive the dew point of natural gas passing through the membrane contactor after the acid gases have been stripped / absorbed by the absorbent. This modification ensures that a more accurate dew point is calculated and prevents condensation of heavier natural gas components in the membrane contactor during operation, which would otherwise cause membrane fouling. In one embodiment, the heating means is configured to heat the natural gas feedstock at least 5°C above the calculated dew point to provide sufficient buffer for errors in estimates.

The heating means may comprise one or more heat exchangers selected from the group consisting of: shell and tube heat exchanger, plate heat exchanger, plate and fin heat exchanger, plate and shell heat exchanger, waste heat exchanger, adiabatic heat exchanger, and tubular heat exchangers. In one embodiment, after passing through the heat exchanger, the natural gas stream contains substantially no liquid particles or droplets.

In another embodiment, the membrane contactor is used as the vessel for heat exchange. For instance, the absorbent liquid being passed into the membrane contactor may be sufficiently heated to raise the temperature of the natural gas passing through the membrane contactor to its calculated dew point or at least 5°C higher.

One or more permeable membranes may be disposed within the membrane contactor. The permeable membrane may be composed of a substantially micro-porous and hydrophobic polymer material. In other embodiments, the permeable membrane may be surface-treated to impart hydrophobicity on its surface. The polymer material of the permeable membrane may be selected from the group consisting of, polypropylene (PP) , polyvinylidene fluoride (PVDF) polytetrafluoroethylene (PTFE) , polysulfone (PS) , polyethylenimide (PEI), polyamide/polyimide, cellulose acetate or co-polymers thereof. The permeable membranes may be provided in a spiral wound, cascade sheet or hollow fiber configuration. Each membrane may be made of the same or different polymer material. Preferably, the selected membrane should exhibit a large surface area and should be substantially compatible with the absorbent to minimize membrane fouling or wetting. In one embodiment, the permeable membrane is a PVDF hollow fiber membrane. In other embodiments, the permeable membrane is preferably a low surface energy membrane such as a PTFE membrane. The PTFE membrane may be a surface-modified membrane to reduce its surface energy. In one embodiment, the porosity of hollow fiber membrane is a range from 15% to 70%, and the average pore size is 0.01 - 2.0 μιη.

The membrane contactor may comprise a tube side for passing the gaseous natural gas stream therethrough and a shell side for passing absorbent in countercurrent flow relative to the tube side, and vice versa. In other embodiments, the membrane contactor may be configured to flow the natural gas and absorbent in a co-current configuration .

The disclosed system for treating natural gas may further comprise pre-treatment units located upstream of the heat exchanger. Exemplary pre-treatment units may include, but are not limited to, a gravity separator, a gas/liquid separator, and a filter. Advantageously, the natural gas after pre-treatment preferably does not contain liquid particles or other particulate matter with sizes larger than the pore size of the membrane used in the membrane contactor.

Brief Description of Drawings

The accompanying drawing illustrates a disclosed embodiment and serves to explain the principles of the disclosed embodiment. It is to be understood, however, that the drawing is designed for purposes of illustration only, and not as a definition of the limits of the invention . Fig. 1 is a schematic diagram of the disclosed system for the treatment of a natural gas feedstock to remove sour gases therefrom. Detailed Description of Figures

Fig. 1 depicts a schematic diagram of a natural gas treatment system 10 according to the present invention. Natural gas feedstock 2 is a highly pressurized gaseous stream (1.0 MPa to 15.0 MPa) containing a mixture of C ₁ -C6 alkanes, CO ₂ , ¾S and water. A series of valves 4 is disposed along various sections of the system 10 to control the flow rate of natural gas passing through system 10.

A pretreatment section is provided upstream of system 10, the pretreatment section comprising a gravity separator 6, a gas/liquid separator 8 and a filter 16. Gravity separator 6 removes the bulky particulate matter that may be present in the natural gas feedstock 2 through a settling process. The natural gas feedstock 2 is then passed towards a gas/liquid separator 8, wherein any liquid components of the feedstock 2 is removed as liquid stream 12. The effluent natural gas stream 14 is then routed to filter 16 for further removal entrained bulky particulate matter. The filter 16 may have a mesh size from 1 nm to 100 nm. In an embodiment, the filter has a mesh size of 10 nm (0.01 micron) .

Next, the filtered natural gas is conveyed towards a heat exchanger 24. Heat exchanger 24 is operatively communicated with a composition analyzer 26 acting in tandem with a temperature control system 28. When in operation, the analyzer 26 is used to detect the various components comprised within the natural gas feedstock 2. The specific composition is determined and this information is relayed to the temperature control system 28. Based on the relayed compositional information, the temperature control system 28 is able to calculate a theoretical dew point of the natural gas feedstock 2. The calculated dew point is used by the temperature control system 28 to manipulate the heating duty of the heat exchanger 24, such that the natural gas feedstock 2 is heated on or above its calculated dew point. In one embodiment, the natural gas feedstock 2 is heated to a temperature at least 5 °C above its calculated dew point.

The heated natural gas stream 18 is subsequently passed towards a membrane contactor 32. Membrane contactor 32 comprises a plurality of hollow fiber membrane modules disposed within its housing. The hollow fiber membranes define a shell side for receiving an inflow of a pressurized amine absorbent 44 and a tube side for receiving the high pressure, heated natural gas stream 18. In one embodiment, the membrane contactor 32 is configured to flow the natural gas stream 18 and the pressurized amine absorbent 44 in counter-current mode.

When in operation, a high pressure pump 42 acts to supply a pressurized amine absorbent 44 to the membrane contactor 32. A differential pressure control system is provided, which acts to finely adjust and control the pressure of the pressurized amine absorbent 44. The differential pressure control system comprises a pressure controller 48 which is capable of receiving information on pressure values at the amine inlet and the product natural gas 36. The pressure controller 48 compares the pressure values of both the amine 44 and the natural gas 36 and generates a pressure differential value ΔΡ, wherein ΔΡ = P _A - P _F . P _A denotes the measured pressure of the amine absorbent 44 whereas P _F denotes the pressure of the natural gas 36. A pre-determined set point is input to the pressure controller 48. If ΔΡ exceeds the input set point, the pressure controller acts to open valve 46 in order to bypass at least a fraction of the amine absorbent 44 back into a lean amine source 38. In doing so, the pressure of the amine absorbent 44 is reduced. Notably, the valve 46 is opened at a level sufficient to return the ΔΡ value to a value on or below the pre ^¬ determined set point. Rich amine, i.e., amine that is saturated with / contains a high concentration of acid gases, is then removed from the membrane contactor 32 as rich amine stream 34. Whilst not shown in Fig. 1, rich amine stream 34 can be routed to a regenerator unit where the acid gases are removed from the rich amine stream 34, e.g., via heating, to regenerate lean amine for use in treatment system 10.

Examples

Non-limiting examples of the invention will be further described in greater detail by reference to specific Examples, which should not be construed as in any way limiting the scope of the invention.

Example 1

A natural gas feedstock which has been pre-treated with gravity separation, gas/liquid separation, filtration and heating is to be treated with the disclosed system of the present invention. A gas composition analyzer, e.g., ABB TotalFlow, Gas Chromatograph, NGC 8209, was used to analyze the feedstock composition. The detailed composition data of the natural gas feedstock is provided in Table 1. The dew point of the natural gas (without acid gas) is -2.9°C, which was calculated via a simulation calculation. In this CcL S Θ cL S the temperature of pre- treated natural gas was higher than the calculated dew point, the natural gas was passed into the membrane contactor without additional heating.

A porous, hollow fiber, PTFE membrane was used in the membrane contactor. The static surface water contact angle is measured to be about 110°, and the average pore size of the membrane is 0.1 μιη. The porosity of the PTFE membrane was about 40% and the absorbent used is 2,2- methyldiethanolamine (MDEA) having a mass fraction of 40% and its temperature was kept at 30°C.

Natural gas was passed through the tube side of the membrane contactor from top to bottom whereas MDEA adsorbent was supplied via the shell side from bottom to the top of the membrane contactor. At steady-state, natural gas pressure in the membrane contactor was approximately 40.0 atm (4.053 MPa) whereas the MDEA pressure was about 40.5 atm (4.104 MPa) .

Table 1 further shows the composition of the product natural gas obtained from the above treatment configuration .

Table 1

Natural gas Product after Natural gas pretreatment

Temperature / ° C 30 30.2

Temperature after heat 30 - exchange ° C

Operating pressure / atm 40 40

Methane / mol% 77.81 85.85

Ethane / mol% 7.88 8.70

Propane / mol% 3.15 3.48

Butane / mol% 0.77 0.85

Pentane / mol% 0.25 0.28

Hexane / mol% 0.18 0.20

Nitrogen / mol% 0.22 0.25

Carbon dioxide / mol% 9.70 0.39

Hydrogen sulfide / mol% 0.02 0

Water / mol% 0.01 0.01

Example 2

The composition of a pre-treated natural gas feedstock was determined as per Example 1 and its composition is being provided in Table 2.

The dew point of the natural gas (without acid gas) was calculated to be about 27.8°C. The temperature of pre-treated natural gas was 25°C and is lower than the calculated dew point. Thus the natural gas was heated by a heat exchanger prior to being passed into the membrane contactor .

In this example, a microporous, hollow fiber PTFE membrane which has been modified to impart hydrophobicity was used. The static surface water contact angle is measured to be 130°. The average pore size was 0.2μη and the porosity of the membrane is 60%. The adsorbent used is diethanolamine (DEA) having a mass fraction of 30% and was kept at a temperature of 35°C. Natural gas was passed through the tube side of the membrane contactor from top to bottom and adsorbent was passed through the shell side from bottom to top.

At steady-state conditions, the natural gas pressure in the membrane contactor was about 60.0 atm (6.08 MPa) whereas the adsorbent pressure was 60.5 atm (6.13 MPa) .

The composition of the product natural gas is also provided in Table 2.

Table 2

Natural gas Product after natural gas pretreatment

Temperature /° C 25 36.7

Temperature after heat 35 - exchange /° C

Operating pressure / atm 60.0 60.0

Methane / mol% 29.94 71.04

Ethane / mol% 2.76 6.35

Propane / mol% 1.95 4.59

Butane / mol% 1.56 3.67

Pentane / mol% 1.34 3.15

Hexane / mol% 0.55 1.29

Nitrogen / mol% 1.16 2.75

Carbon dioxide / mol% 60.69 7.19

Hydrogen sulfide / mol% 0.04 0.00

Water / mol% 0.01 0.01 Applications

Compared to the conventional natural gas treatment methods, e.g., those utilizing absorption columns, the disclosed system and methods boasts of numerous advantages over the conventional systems, including compact construction taking up lesser space, lower energy consumption, improved acid gas removal efficiency, reduced product gas loss, and further enables independent control of gas and liquid flow rates in the system. In addition, the disclosed pressure control system allows the disclosed system and method to be used for treating high pressure natural gas feedstock, without the attendant risks to membrane fouling, contamination and corrosion. As such, the disclosed method and system have promising applications in natural gas purification, especially for natural gas extraction in off-shore sites.

It will be apparent that various other modifications and adaptations of the invention will be apparent to the person skilled in the art after reading the foregoing disclosure without departing from the spirit and scope of the invention and it is intended that all such modifications and adaptations come within the scope of the appended claims.