WO2015003286A1 - Process and system for treating natural gas feedstock - Google Patents
Process and system for treating natural gas feedstock Download PDFInfo
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- WO2015003286A1 WO2015003286A1 PCT/CN2013/000840 CN2013000840W WO2015003286A1 WO 2015003286 A1 WO2015003286 A1 WO 2015003286A1 CN 2013000840 W CN2013000840 W CN 2013000840W WO 2015003286 A1 WO2015003286 A1 WO 2015003286A1
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- natural gas
- absorbent
- mpa
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- stream
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/22—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by diffusion
- B01D53/229—Integrated processes (Diffusion and at least one other process, e.g. adsorption, absorption)
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
- B01D53/1456—Removing acid components
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
- C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
- C10L3/10—Working-up natural gas or synthetic natural gas
- C10L3/101—Removal of contaminants
- C10L3/102—Removal of contaminants of acid contaminants
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2256/00—Main component in the product gas stream after treatment
- B01D2256/24—Hydrocarbons
- B01D2256/245—Methane
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- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
- Y02C20/00—Capture or disposal of greenhouse gases
- Y02C20/40—Capture or disposal of greenhouse gases of CO2
Definitions
- the present invention relates to a process and system for treating a natural gas feedstock.
- 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.
- IEO International Energy Outlook 2011
- 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 %.
- 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.
- the resultant rich amine solution i.e., amine solution that is rich in CO2
- 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.
- a membrane contactor is a device that achieves gas/liquid mass transfer without dispersion or mixing of one phase within another.
- 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.
- the membrane contactor 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.
- 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.
- 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.
- 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.
- 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.
- 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%) .
- processing high pressure natural gas will entail supplying an equally pressurized stream of absorbent.
- 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.
- 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.
- a process for removing acid gas from a natural gas stream 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.
- the disclosed process advantageously provides a controlling step which is capable of maintaining P F and P A to be substantially the same.
- the differential pressure ( ⁇ ) between the absorbent fluid and the natural gas feed stream is advantageously controlled on or below a 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 .
- a system for removing acid gas from a natural gas stream 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.
- 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.
- 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.
- natural gas that is being passed towards the membrane contactor is substantially gaseous.
- 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 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.
- 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.
- controlling step (c) is configured to maintain P A at a value that is not 5% greater than P F .
- 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 .
- 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.
- 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 3 ⁇ 4S or mixtures thereof.
- 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.
- the natural gas feedstock may contain from about 9% to about 61% acid gases.
- the disclosed process further comprises a step of (d) , heating the natural gas feed stream to on or above a calculated dew point.
- the dew point may be calculated based on the composition of the natural gas feed stream.
- the dew point may be calculated based on a modified composition of the natural gas feed stream which omits the acid gas fractions.
- heating step (d) comprises heating the natural gas feed stream to a temperature at least 5°C above the calculated dew point.
- 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.
- 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 3 ⁇ 4S.
- 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.
- controlling step (C) may further comprise the following steps: (cl) measuring a pressure differential ( ⁇ ) between the absorbent and the natural gas stream; (c2) comparing the ⁇ to a pre-determined set point; and (c3) reducing a flow rate of the absorbent when the measured pressure differential ( ⁇ ) is greater than the pre-determined set point.
- Reducing step (c3) may comprise removing absorbent from the absorbent stream.
- 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.
- 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 ⁇ is returned to an acceptable value on or below the pre-determined set point.
- the measured pressure differential, ⁇ may be represented by the following equation (I)
- ⁇ is a value in a range from about 0 to about 0.2 MPa. In other embodiments, ⁇ 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.
- 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.
- 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.
- the natural gas feedstock may exhibit a pressure of at least 5.0 MPa to about 15.0 MPa.
- the natural gas feedstock may exhibit a pressure of at least 8.0 MPa.
- the natural gas feedstock may exhibit a pressure of at least 8.0 MPa to 12 MPa.
- 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.
- MDEA 2,2- methyldiethanolamine
- DEA diethanolamine
- DETA diethylenetriamine
- TETA triethylenetetramine
- the absorbent may be an ionic liquid selected from the group consisting of: phosphonium, ammonium, pyridinium and imidazolium based ionic liquids.
- 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.
- 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 .
- 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 ( ⁇ ) of the absorbent and the natural gas stream.
- the pressure analyzer may be operatively communicated with a flow controller, said flow controller being configured to remove absorbent from the absorbent stream.
- the flow controller may be configured to reduce flow rate of the absorbent when the measured ⁇ 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 .
- 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 ⁇ 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 ⁇ is returned to an acceptable value on or below the set point.
- 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.
- 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.
- 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.
- 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.
- 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.
- the natural gas stream after passing through the heat exchanger, contains substantially no liquid particles or droplets.
- the membrane contactor is used as the vessel for heat exchange.
- 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.
- 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.
- the selected membrane should exhibit a large surface area and should be substantially compatible with the absorbent to minimize membrane fouling or wetting.
- the permeable membrane is a PVDF hollow fiber membrane.
- 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.
- the porosity of hollow fiber membrane is a range from 15% to 70%, and the average pore size is 0.01 - 2.0 ⁇ .
- 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.
- 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.
- pre-treatment units may include, but are not limited to, a gravity separator, a gas/liquid separator, and a filter.
- 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.
- FIG. 1 is a schematic diagram of the disclosed system for the treatment of a natural gas feedstock to remove sour gases therefrom.
- 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 , 3 ⁇ 4S 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) .
- 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.
- 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.
- 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.
- the natural gas feedstock 2 is heated to a temperature at least 5 °C above its calculated dew point.
- 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.
- the membrane contactor 32 is configured to flow the natural gas stream 18 and the pressurized amine absorbent 44 in counter-current mode.
- 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.
- 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.
- 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 ⁇ 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.
- 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 ⁇ 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 ⁇ .
- 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.
- MDEA 2,2- methyldiethanolamine
- 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.
- 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 .
- 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.
- the natural gas was heated by a heat exchanger prior to being passed into the membrane contactor .
- 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 0.2 ⁇ 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.
- DEA diethanolamine
- 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) .
- composition of the product natural gas is also provided in Table 2.
- the disclosed system and methods 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.
- 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.
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Abstract
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Priority Applications (6)
Application Number | Priority Date | Filing Date | Title |
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PCT/CN2013/000840 WO2015003286A1 (en) | 2013-07-11 | 2013-07-11 | Process and system for treating natural gas feedstock |
MYPI2016000030A MY176836A (en) | 2013-07-11 | 2013-07-11 | Process and system for treating a natural gas feedstock |
AU2013394334A AU2013394334A1 (en) | 2013-07-11 | 2013-07-11 | Process and system for treating natural gas feedstock |
CA2917734A CA2917734C (en) | 2013-07-11 | 2013-07-11 | Process and system for treating natural gas feedstock |
CN201380079506.XA CN105658307B (en) | 2013-07-11 | 2013-07-11 | Handle the method and system of gas material |
AU2018256480A AU2018256480B2 (en) | 2013-07-11 | 2018-10-29 | Process and system for treating natural gas feedstock |
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PCT/CN2013/000840 WO2015003286A1 (en) | 2013-07-11 | 2013-07-11 | Process and system for treating natural gas feedstock |
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CN (1) | CN105658307B (en) |
AU (2) | AU2013394334A1 (en) |
CA (1) | CA2917734C (en) |
WO (1) | WO2015003286A1 (en) |
Citations (5)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20020189445A1 (en) * | 2001-04-25 | 2002-12-19 | Miller Stephen J. | Process for the wellbore separation of CO2 from hydrocarbon gas |
CN1488422A (en) * | 2003-07-30 | 2004-04-14 | 浙江大学 | Method and system for separating carbon dioxide form fume by hollow film membrane contactor |
CN101091873A (en) * | 2007-04-21 | 2007-12-26 | 大连理工大学 | Technical method by using seawater to remove sulfur dioxide in smoke through membrane absorption method |
WO2013037128A1 (en) * | 2011-09-16 | 2013-03-21 | Petroliam Nasional Berhad (Petronas) | Separation of gases |
KR20130064324A (en) * | 2011-12-08 | 2013-06-18 | (주)세프라텍 | Membrane contact method for seperating carbon dioxide and system therefor |
Family Cites Families (1)
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NO301458B1 (en) * | 1993-12-27 | 1997-11-03 | Norsk Hydro As | Purification of natural gas |
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2013
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- 2013-07-11 WO PCT/CN2013/000840 patent/WO2015003286A1/en active Application Filing
- 2013-07-11 CA CA2917734A patent/CA2917734C/en active Active
- 2013-07-11 CN CN201380079506.XA patent/CN105658307B/en active Active
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2018
- 2018-10-29 AU AU2018256480A patent/AU2018256480B2/en active Active
Patent Citations (5)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20020189445A1 (en) * | 2001-04-25 | 2002-12-19 | Miller Stephen J. | Process for the wellbore separation of CO2 from hydrocarbon gas |
CN1488422A (en) * | 2003-07-30 | 2004-04-14 | 浙江大学 | Method and system for separating carbon dioxide form fume by hollow film membrane contactor |
CN101091873A (en) * | 2007-04-21 | 2007-12-26 | 大连理工大学 | Technical method by using seawater to remove sulfur dioxide in smoke through membrane absorption method |
WO2013037128A1 (en) * | 2011-09-16 | 2013-03-21 | Petroliam Nasional Berhad (Petronas) | Separation of gases |
KR20130064324A (en) * | 2011-12-08 | 2013-06-18 | (주)세프라텍 | Membrane contact method for seperating carbon dioxide and system therefor |
Also Published As
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CN105658307A (en) | 2016-06-08 |
CN105658307B (en) | 2018-10-19 |
AU2018256480A1 (en) | 2018-11-22 |
CA2917734C (en) | 2021-07-06 |
AU2018256480B2 (en) | 2020-08-20 |
CA2917734A1 (en) | 2015-01-15 |
AU2013394334A1 (en) | 2016-02-04 |
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