AU2018256480B2 - Process and system for treating natural gas feedstock - Google Patents

Abstract

Process and System For Treating A Natural gas Feedstock Abstract The present invention provides a process for 5 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 (PF) ; (b) passing an absorbent stream comprising an absorbent fluid on an 10 absorbent side of the membrane, opposite said feed side, wherein the pressure of said absorbent stream is at an absorbent pressure (PA), to remove acid gas from said natural gas stream; (c) controlling at least one of the feed pressure (PF) and absorbent pressure (PA) so that the 15 (PA) is substantially equal to or greater than the (PF) without allowing the absorbent fluid to reside in the pores of the membrane. The present invention further provides a system for performing the process. 31

Description

PROCESS AND SYSTEM FOR TREATING A NATURAL GAS FEEDSTOCK

Related Application

This application is a divisional application of Australian Patent Application No. 2013394334, filed on 11 July 2013, the contents of which are hereby incorporated in its entirety.

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 2S), 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 C02 absorption is the most frequently used. Amine-based C02 absorption methods involve removing C02 by reacting amine solvents with C02 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 C0 2 ) is later regenerated via heating to desorb C02. 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.OMPa). 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 natural gas feed stream comprising natural gas and acid gas through a feed side of a membrane at a feed pressure (PF), wherein said natural gas feed stream is at a pressure between 1.0 to 15.0 MPa; (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 (PA), to remove acid gas from said natural gas stream; (c) controlling at least one of the feed pressure (PF) and absorbent pressure (PA) so that the absorbent pressure (PA) is substantially equal to or greater than the feed pressure (PF) without allowing the absorbent fluid to reside in the pores of the membrane.

There is disclosed 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 (PF); (b) passing an absorbentstream 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 (PA), to remove acid gas from said natural gas stream; (c) controlling at least one of the feed pressure (PF) and absorbent pressure (PA) so that the (PA) is substantially equal to or greater than the (PF) 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 PF and PA to be substantially the same. In one embodiment, during the treatment process, the differential pressure (AP) 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 PA.

21542182_1

In a second 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 natural gas feed stream comprising natural gas and acid gas in fluid communication with the feed side of said membranes and being at a feed pressure (PF), wherein said natural gas feed stream is at pressure between 1.0 to 15.0 MPa; an absorbent stream comprising an absorbent fluid in fluid communication with the absorbent side of the membrane at an absorbent pressure (PA); control means for controlling at least one of the feed pressure (PF) and absorbent pressure (PA) so that the absorbent pressure (PA) is substantially equal to or greater than the feed pressure (PF) without allowing the absorbent fluid to reside in the pores of the membrane.

There is disclosed 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 (PF); an absorbent stream comprising an absorbent fluid in fluid communication with the absorbent side of the membrane at an absorbent pressure (PA); control means forcontrolling at least one of the feed pressure (PF) and absorbent pressure (PA) so that the (PA) 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.

21542182_1

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., C02, 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 Pm.

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 (PF) and

absorbent pressure (PA) means that the (PF) and (PA) 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 PA>PF or

PA<PF, as long as the AP 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 PA at a

value that is not 5% greater than PF• In a preferred embodiment, PA is not 4% greater than PF. More preferably, PA is not 3% greater than PF. Even more preferably, PA is not 2% greater than PF• In one preferred embodiment, PA is not 1% greater than PF• In one embodiment, the pressure difference between PA and PF 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 Ci-C6 alkanes, C02, H 2 S, and water (H 2 0). The natural gas may contain from about 3% to about 85% acid gaese, i.e., C02 or H2 S 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 50C 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.,

C02 and H 2 S. 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: (c1) measuring a pressure

differential (AP) between the absorbent and the natural

gas stream; (c2) comparing the AP to a pre-determined set

point; and (c3) reducing a flow rate of the absorbent

when the measured pressure differential (AP) 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 PA. 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 AP is returned to an acceptable value on or below the pre-determined set point.

In one embodiment, the measured pressure differential,

AP may be represented by the following equation (I)

Equation (I): AP = PA PF

wherein PA represents a pressure of the absorbent

entering an absorbent side of the membrane; and PF represents a pressure of the natural gas stream passing

through the feed side of the membrane. In one embodiment,

AP is a value in a range from about 0 to about 0.2 MPa.

In other embodiments, AP 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 (AP) between the absorbent stream

and the natural gas stream, wherein AP = PA - PF. 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

(AP) 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 AP 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 PA• 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 AP 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 AP 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., C02 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 50C 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 50C 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 pm.

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 Ci-C6 alkanes, C02, H2 S 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 0C 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 AP,

wherein AP = PA - PF. PA denotes the measured pressure of the amine absorbent 44 whereas PF denotes the pressure of the natural gas 36. A pre-determined set point is input to the pressure controller 48. If AP 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 AP 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 case, as 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 1100, and the average pore

size of the membrane is 0.1 pm. 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 300C.

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 27.80C. The temperature of

pre-treated natural gas was 250C 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 1300. The average pore size was 0.2pm 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 350C. 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 /0 C 25 36.7

Temperature after heat 35

exchange /0 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.

Claims (36)

1. A process for removing acid gas from a natural gas stream, the process comprising the steps of: (a) passing a natural gas feed stream comprising natural gas and acid gas through a feed side of a membrane at a feed pressure (PF), wherein said natural gas feed stream is at a pressure between 1.0 to 15.0 MPa; (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 (PA), to remove acid gas from said natural gas stream; (c) controlling at least one of the feed pressure (PF) and absorbent pressure (PA) SO that the absorbent pressure (PA) is substantially equal to or greater than the feed pressure (PF) without allowing the absorbent fluid to reside in the pores of the membrane.

2. The process as claimed in claim 1, wherein the difference between absorbent pressure (PA) and feed pressure (PF) is not greater than 0.2 MPa.

3. The process as claimed in claim 1, wherein the difference between absorbent pressure (PA) and feed pressure (PF) is not greater than 0.15 MPa.

4. The process as claimed in claim 1, wherein the difference between absorbent pressure (PA) and feed pressure (PF) is not greater than 0.1 MPa.

5. The process as claimed in claim 1, wherein the difference between absorbent pressure (PA) and feed pressure (PF) is not greater than 0.05 MPa.

6. The process as claimed in claim 1, wherein the difference between absorbent pressure (PA) and feed pressure (PF) is not greater than 0.025 MPa.

7. The process according to any one of claims 1 to 6, further comprising, prior to step (a), a step (d): heating said natural gas feed stream to or above a calculated dew point of said natural gas feed stream.

8. The process according to claim 7, wherein step (d) comprises heating said natural gas feed stream to a temperature at least 5°C above said calculated dew point.

9. The process according to claim 8, wherein step (c) comprises the steps of: (c1) measuring a pressure differential between said absorbent and said natural gas feed stream; (c2) comparing the pressure differential to a pre-determined set point; and (c3) reducing a flow rate of said absorbent when the measured pressure differential is greater than said pre-determined set point.

10. The process according to claim 9, wherein step (c3) comprises removing absorbent from the absorbent stream.

11. The process according to any one of claims 9 or 10, wherein said measured pressure differential refers to a value AP, wherein AP = PA - PF.

12. The process according to claim 11, wherein AP is a value in a range from about 0 to 0.2 MPa.

13. The process according to any one of claims I to 12, wherein said absorbent stream and said natural gas feed stream are contacted in a countercurrent configuration.

14. The process according to any one of claims I to 13, wherein the pressure of the natural gas feed stream is at least 5 MPa.

15. The process according to any one of claims I to 14, wherein the pressure of the natural gas feed stream is from 5 MPa to 15 MPa.

16. The process according to any one of claims I to 15, wherein the pressure of the natural gas feed stream is from 8 MPa to 12 MPa.

17. The process according to any one of claims 1 to 16, wherein said natural gas feed stream contains acid gases in a range of 3% to 85%.

18. The process according to any one of claims 1 to 17, wherein said absorbent stream comprises an amine solution.

19. A system for removing acid gas from a natural gas stream, the system comprising:

21542182_1 a membrane contactor comprising an array of membranes, each membrane having a feed side and an absorbent side opposite said feed side; a natural gas feed stream comprising natural gas and acid gas in fluid communication with the feed side of said membranes and being at a feed pressure (PF), wherein said natural gas feed stream is at pressure between 1.0 to 15.0 MPa; an absorbent stream comprising an absorbent fluid in fluid communication with the absorbent side of the membrane at an absorbent pressure (PA); control means for controlling at least one of the feed pressure (PF) and absorbent pressure (PA) so that the absorbent pressure (PA) is substantially equal to or greater than the feed pressure (PF) without allowing the absorbent fluid to reside in the pores of the membrane.

20. The system as claimed in claim 19, wherein the difference between absorbent pressure (PA) and feed pressure (PF) is not greater than 0.2 MPa.

21. The system as claimed in claim 19, wherein the difference between absorbent pressure (PA) and feed pressure (PF) is not greater than 0.15 MPa.

22. The system as claimed in claim 19, wherein the difference between absorbent pressure (PA) and feed pressure (PF) is not greater than 0.1 MPa.

23. The system as claimed in claim 19, wherein the difference between absorbent pressure (PA) and feed pressure (PF) is not greater than 0.05 MPa.

24. The system as claimed in claim 19, wherein the difference between absorbent pressure (PA) and feed pressure (PF) is not greater than 0.025 MPa.

25. The system according to any one of claims 19 to 24, further comprising heating means disposed upstream of said membrane contactor, for heating said natural gas feed stream to or above a calculated dew point of said natural gas feed stream.

26. The system according to claim 25, wherein said heating means is configured to heat said natural gas feed stream to a temperature at least 5°C above said calculated dew point.

21542182_1

27. The system according to claim 26, wherein the control means comprises a pressure analyzer configured to measure a differential pressure (AP) between said natural gas feed stream

and absorbent stream, wherein AP = PA - PF.

28. The system according to claim 27, wherein the pressure analyzer is operatively communicated with a flow controller capable of removing absorbent from said absorbent stream.

29. The system according to claim 28, wherein said flow controller is configured to remove absorbent from said absorbent stream when AP is greater than a pre-determined set point.

30. The system according to claim 29, wherein AP is a value in a range from about 0 to 0.2 MPa.

31. The system according to any one of claims 19 to 30, wherein said membrane contactor passes said absorbent stream and said natural gas feed stream in a countercurrent configuration.

32. The system according to any one of claims 19 to 31, wherein the pressure of the natural gas feed stream is at least 5 MPa.

33. The system according to any one of claims 19 to 32, wherein the pressure of the natural gas feed stream is from 5 MPa to 15 MPa.

34. The system according to any one of claims 19 to 33, wherein the pressure of the natural gas feed stream is from 8 MPa to 12 MPa.

35. The system according to any one of claims 19 to 34, wherein said natural gas feed stream contains acid gases in a range of 3% to 85%.

36. The system according to any one of claims 19 to 35, wherein said absorbent stream comprises an amine solution.

Petroliam Nasional Berhad, Dalian Institute of Chemical Physics

Patent Attorneys for the Applicant/Nominated Person

SPRUSON&FERGUSON

21542182_1