AQUEOUS AMINE SOLUTIONS

Technical field

The present invention relates to a process for treating natural gas, in particular for removing impurities, such as acid gas and water, from natural gas. Specifically, the process involves contacting the natural gas with two aqueous amine solutions with different water contents.

Background of the invention

Natural gas is a fossil fuel mainly comprising a complex mixture of

hydrocarbon and non-hydrocarbon components. The primary component of raw natural gas (i.e. natural gas directly taken from a geological formation) is typically methane. This is normally present together with varying amounts of heavier hydrocarbons such as ethane, propane, n-butane, iso-butane, pentanes and other higher molecular weight hydrocarbons as well as so-called "BTX" (benzene, toluene and xylene) components. Other components such as carbon dioxide (C0 ₂ ), hydrogen sulfide (H ₂ S), mercaptans, and other sulfur-containing compounds, are typically also present. C0 ₂ and sulfur-containing compounds are referred to collectively as "acid gases". Additionally, water (either in vapour or liquid form) and mercury (primarily as elemental mercury but also in the form of chlorides and other mercury compounds) may be present.

Impurities such as acid gases (C0 ₂ and sulfur-containing gases such as H ₂ S), water, mercury, BTX and heavier hydrocarbons, can have undesirable effects when present in natural gas. Water and acid gases can act together to corrode storage vessels, pipelines and other containers, presenting a safety risk and increasing maintenance and operational costs. H ₂ S is also toxic. The presence of acid gases also reduces the heating value of the natural gas. Mercury is toxic to humans and can cause corrosion problems, e.g. in aluminium heat exchangers. Water, C0 ₂ , BTX and heavier hydrocarbons can condense and/or freeze during the liquefaction process, forming solids which interfere with liquefaction and block pipelines and other equipment such as heat exchangers. The presence of water may also lead to the formation of hydrates. These can deposit on the inside wall of gas and oil pipelines, leading to a reduction in the pipeline cross-sectional area, which, without proper counter measures, will lead to a loss of pressure and ultimately to a complete blockage of the pipeline or other process equipment. It is therefore necessary to reduce the impurity content of natural gas in order to minimise these problems. Industry standards relating to natural gas production and transportation typically require that the C0 ₂ content is in the region of 2 to 3 mol% (for sales gas, for example) and the H ₂ S content should be no more than 4 ppmv. In addition, the water content of the gas should ideally be reduced to a level of 20 to 40 ppm (for sales gas, for example), although in some locations higher amounts may be permitted.

Several technologies have been developed for the removal of impurities and these typically involve the addition of an absorbent medium or solvent (e.g. a glycol or amine), physical solvents, membranes, cold processes, etc.

Currently employed systems for the removal of water and acid gas by way of solvent absorption typically use two different solvents, each comprising different chemicals. One solvent is designed to remove the water and the other to remove the acid gas. For example, an aqueous amine solution comprising 30 to 50 wt% amine and 50 to 70 wt% water may be used to remove H ₂ S and a glycol solution comprising 99.5 to 99.38 wt% triethyleneglycol may be used for water removal.

The use of two different solvents in the processing system does, however, present challenges. Isolation of the two solvents for regeneration in separate systems can be difficult and the need to supply two separate chemicals increases costs. Moreover, for offshore (topside or subsea) units there is a push to make the process compact. Two solvent systems, with two separate regeneration systems, make the process facility large. Nevertheless, replacing these two solvents with a single solvent system has so far not proved viable because effective removal of both the water and acid gas to acceptable levels could not be achieved.

The present invention is conceived to solve or at least alleviate the problems identified above. An object of the invention is to provide a solvent system which can be used to remove water and acid gas (e.g. at least one of carbon dioxide and hydrogen sulfide) from natural gas in a more economical manner to those systems currently employed. It is also desirable to develop a solvent system which can be regenerated more easily and in fewer steps than is presently possible.

The present inventors have surprisingly found that this may be achieved by using two aqueous amine solutions with different water contents. Unexpectedly, this liquid absorbent is capable of removing both water and acid gas from a natural gas steam to levels low enough to comply with industry specifications. The process herein described represents a significant improvement compared to methods known in the art and thereby simplifies the processing and subsequent regeneration steps which need to be undertaken to remove acid gas and water. Summary of the Invention

In a first aspect, the invention provides a process for treating a natural gas stream, said process comprising the steps:

(i) contacting said natural gas stream with a first aqueous amine solution, said first solution comprising an amine and a first amount of water; and

(ii) contacting said natural gas stream with a second aqueous amine solution, said second solution comprising an amine and a second amount of water,

wherein steps (i) and (ii) are performed sequentially and in any order and wherein the amine in the first and second solution is the same and wherein the first amount of water is greater than the second amount of water.

In a second aspect, the invention provides a process for treating a natural gas stream, said process comprising the steps:

(i) contacting said natural gas stream with a first aqueous amine solution so as to produce a natural gas stream having reduced acid gas content, said first solution comprising an amine and a first amount of water; and

(ii) contacting said gaseous feed stream with a second aqueous amine solution so as to produce a natural gas stream having a reduced water content, said second solution comprising an amine and a second amount of water,

wherein steps (i) and (ii) are performed sequentially and in any order and wherein the amine in the first and second solution is the same and wherein the first amount of water is greater than the second amount of water.

In a further aspect, the invention provides the use of a first aqueous amine solution comprising an amine and a first amount of water and a second aqueous amine solution comprising an amine and a second amount of water in a process for treating a natural gas stream, wherein the amine in the first and second solution is the same and wherein the first amount of water is greater than the second amount of water.

In a yet further aspect the invention provides the use of a first aqueous amine solution comprising an amine and a first amount of water and a second aqueous amine solution comprising an amine and a second amount of water in a process for the production of purified natural gas, wherein the amine in the first and second solution is the same and wherein the first amount of water is greater than the second amount of water. In a further aspect the present invention provides purified natural gas obtained or obtainable by any of the processes herein described.

In an additional aspect, the invention provides apparatus arranged to perform the process as herein described, said apparatus comprising:

(i) A first contactor configured to receive a natural gas stream and a first aqueous amine solution via at least one first inlet so as to produce a natural gas stream with reduced acid gas content and a rich first aqueous amine solution, wherein the natural gas stream with reduced acid gas content exits the first contactor via a first gas phase conduit and the rich first aqueous amine solution exits the first contactor via a first liquid phase conduit; and

(ii) A second contactor configured to receive a natural gas stream and a second aqueous amine solution via at least one second inlet so as to produce a natural gas stream with reduced water content and a rich second aqueous amine solution, wherein the natural gas stream with reduced water content exits the second contactor via a second gas phase conduit and the rich second aqueous amine solution exits the second contactor via a second liquid phase conduit.

Detailed Description of the Invention

The present invention describes a process for treating a natural gas stream. The process involves contacting the natural gas stream with a two aqueous amine solutions with different water contents.

The natural gas stream used in the process of the invention may be any stream of natural gas, but is typically a "raw" natural gas feed from a wellhead, i.e. a natural gas feed which has been taken directly from a geological formation.

The natural gas stream will typically comprise methane as the primary component, but may also comprise varying amounts of heavier hydrocarbons such as ethane, propane, n-butane, iso-butane, pentanes and other higher molecular weight hydrocarbons as well as so-called "BTX" (benzene, toluene and xylene) components. Other components such as carbon dioxide (C0 ₂ ), hydrogen sulfide (H ₂ S), mercaptans, and other sulfur-containing compounds, are typically also present. Additionally, water (either in vapour or liquid form) and mercury (primarily as elemental mercury but also in the form of chlorides and other mercury compounds) may be present.

The composition of the natural gas stream can vary, but typically contains methane (70-90 vol%), ethane/butane (0-20 vol%), nitrogen (0-5 vol%) carbon dioxide (0-8 vol%) and hydrogen sulfide (0-5 vol%). In the context of the invention, the term "treating" is intended to cover at least the partial removal of water (either in vapour or liquid form) and acid gas (e.g. at least one of carbon dioxide and hydrogen sulfide) from the natural gas stream, preferably the at least partial removal of water and H ₂ S. The term "acid gas" in the context of the invention means at least one of carbon dioxide and hydrogen sulfide. However, in a preferable embodiment, by "acid gas" we mean hydrogen sulfide only.

By "partial removal" we typically mean that at least 50% of the total amount of water and acid gas is removed, such as at least 70%. Preferably up to 90% of the total amount of water and acid gas will be removed, more preferably up to 95%, even more preferably up to 99%. These figures are particularly relevant where "acid gas" refers only to H ₂ S. The processes of the invention will ideally remove up to 90% of the water, more preferably up to 95%, even more preferably up to 99%. Preferably up to 90% of the H ₂ S will be removed, more preferably up to 95%, even more preferably up to 99%.

The water content of the natural gas stream, after having been treated using the processes of the invention will ideally be sufficiently low such that hydrates do not form during transportation at ambient seabed temperatures. Typically this is a water content in the range of 20 to 100 ppm.

The hydrogen sulfide content should ideally be reduced to less than 4 ppm. If C0 ₂ is removed, it is generally to a level of around 2 to 3 mol%.

The processes of the invention employ two aqueous amine solutions (herein referred to as a "first aqueous amine solution" and a "second aqueous amine solution") with different water contents. It will be understood that by "aqueous solution" we mean a liquid solution in which the solvent is water, i.e. a solution which contains at least a proportion of water.

The first and second aqueous amine solutions comprise an amine. Whilst it is within the ambit of the invention for the first and second aqueous amine solutions to each comprise more than one amine, it is preferred if each solution contains only a single amine. The amine in the first and second aqueous amine solution is the same. If the first and second aqueous amine solutions comprise more than one amine, the first aqueous amine solution will contain the same amines as the second aqueous amine solution. The amine may, for example, be any primary, secondary or tertiary amine, amino acid salt or ammonia. In particular, it may be at least one primary, secondary or tertiary alkanolamine.

According to one embodiment the amine may be an alkanolamine of formula

(I):

NR ¹ R ² R ³ (I) wherein R ¹ , R ² and R ³ are independently selected from hydrogen, Ci _-6 alkyl and Ci _-6 alkanol, with the proviso that at least one of R ¹ , R ² and R ³ is a Ci _-6 alkanol.

As used herein the term "C _1-6 alkyl" refers to any straight-chain or branched alkyl group having one, two, three, four, five or six carbon atoms, such as methyl, ethyl, n-propyl, isopropyl, n-butyl, iso-butyl, sec-butyl, t-butyl, n-pentyl, tert-pentyl, neopentyl, isopentyl, sec-pentyl, 3-pentyl, 1 -hexyl, 2-hexyl or 3-hexyl groups.

As used herein the term "C _1-6 alkanol" refers to any straight-chain or branched alkyl group having one, two, three, four, five or six carbon atoms such as those described above, wherein at least one hydrogen atom is substituted by an -OH functional group. Examples include methanol, ethanol, propanol (e.g. 1 - hydroxypropyl, 2-hydroxypropyl and 3-hydroxypropyl), butanol, pentanol and hexanol groups.

In a preferred embodiment the amine may be selected from the group consisting of 2-amino-2-methyl-1 -propanol (AMP); 2-amino-2-hydroxymethyl-1 ,3- propanediol (TRIS); diethyl monoethanolamine (DEMEA); dimethyl

monoethanolamine (DMMEA); N-methyl diethanolamine (MDEA); hydroxethyl piperazine (HEPZ); 2-aminoethanol (MEA); 2,2'-dihydroxydiethylamine (DEA);

diethylene glycol monoamine (DGA); di-isopropyl amine (DIPA); triisopropanolamine (TIPA); and mixtures thereof. MEA, DEA, DGA, DIPA and/or MDEA are preferred for use in the invention. A particularly preferred amine is N-methyl diethanolamine (MDEA).

The amine is typically present in the first aqueous amine solution in an amount of 10 to 60 mol%, preferably 15 to 50 mol%, more preferably 25 to 40 mol% relative to the total amount of the first amine solution. The amount of amine in the second aqueous amine solution is usually in the range 55 to 99.5 mol%, preferably 60 to 98.5 mol%, more preferably 70 to 98 mol% relative to the total amount of the second aqueous amine solution.

The first aqueous amine solution and second aqueous amine solution have different water contents. The amount of water in the first aqueous amine solution is herein defined to be the "first amount of water". The amount of water in the second aqueous amine solution is herein defined to be the "second amount of water". In particular, the first amount of water is greater that the second amount of water.

Preferably the first amount of water is at least 5 times greater than the second amount of water, preferably at least 10 times greater, even more preferably at least 20 times greater. The first amount of water should be in a range which enables the first aqueous amine solution to absorb acid gas (e.g. H ₂ S) from the natural gas stream. Typically, the first amount of water is in the range 40 to 90 mol%, preferably 50 to 85 mol%, more preferably 60 to 75 mol% relative to the total amount of the first aqueous amine solution. The second amount of water should be in a range which enables the second aqueous amine solution to absorb water from the natural gas stream. The second amount of water is typically in the range 0.5 to 45 mol%, preferably 1 to 40 mol%, more preferably 3 to 30 mol% relative to the total amount of the second aqueous amine solution. It will be appreciated that the first and second amounts of water will be selected appropriately based on the amounts of water and acid gas which are to be removed from the natural gas stream.

In one embodiment, the first and second aqueous amine solutions consist of at least one amine and water. Alternatively, in addition to the amine and water, each of the first and second aqueous amine solutions may comprise additional components such as glycols (e.g. TEG (Triethyleneglycol), DEG (deethyleneglycol) or MEG (monoethyleneglycol)) or alcohols.

The processes of the invention involve contacting the natural gas steam with the first and second aqueous amine solutions. By "contacting" we mean bringing the natural gas stream into contact, either directly or indirectly (e.g. via a membrane contactor) with each of the first and second aqueous amine solutions. Specifically, the processes involve two contacting steps:

(i) contacting the natural gas stream with a first aqueous amine solution, said first solution comprising an amine and a first amount of water; and

(ii) contacting the natural gas stream with a second aqueous amine- solution, said second solution comprising an amine and a second amount of water.

These two contacting steps are performed sequentially (i.e. in sequence) and in any order. Thus, step (i) may be performed first, followed by step (ii). Equally step (ii) may be performed first, followed by step (i). In all embodiments, it is preferable if step (i) is performed first, followed by step (ii).

Typically, each contacting step is performed such that equilibrium conditions are reached, i.e. in step (i) the acid gas (e.g. at least one of C0 ₂ and H ₂ S) is in equilibrium between the natural gas stream and the first aqueous amine solution and in step (ii) the water is in equilibrium between the natural gas stream and the second aqueous amine solution. Those skilled in the art will appreciate that the conditions under which steps (i) and (ii) are performed and the relative amounts of the natural gas stream and first and second aqueous amine solutions supplied in each step will be selected such that, under equilibrium conditions, absorption of the acid gas/water into the amine solution will be favoured, i.e. in step (i) a higher concentration of acid gas in the first aqueous amine solution than in the natural gas stream and in step (ii) a higher concentration of water in the second aqueous amine solution than in the natural gas stream.

When the processes of the invention are used to at least partially remove water and H ₂ S only (e.g. in circumstances where no C0 ₂ is present or the C0 ₂ concentration in the feed gas is already at an acceptable level below <2-3 mol%), each contacting step is performed such that in step (i) H ₂ S is in equilibrium between the natural gas stream and the first aqueous amine solution and in step (ii) water is in equilibrium between the natural gas stream and the second aqueous amine solution. In this embodiment, it is preferred if C0 ₂ absorption from the natural gas stream into the first amine solution is as far from equilibrium as possible, i.e. it is favoured for any C0 ₂ to remain in the natural gas stream.

Preferably step (i) occurs at a temperature of 10 to 60 °C. Step (ii) preferably takes place at a temperature of 5 to 30 °C.

Each contacting step typically occurs in an absorber. By "absorber", we mean an apparatus which facilitates the absorption of the water or acid gas into the aqueous amine solution. The absorber is typically an absorption column or a membrane contactor. The absorption column may be any suitable column known in the art such as a packed column, a tray column, a falling-film column, a bubble column, a spray tower, a gas-liquid agitated vessel, a plate column, a rotating disc contactor or a Venturi tube.

Contact between the natural gas stream and the first or second aqueous amine solution may also be carried out in a conventional mixer, for example in a co- current mixer. In one embodiment, contact is effected in a co-current mixer or column in which the components (i.e. the natural gas stream and the first or second aqueous amine solution) are both added at the same inlet point (or inlet points which are in close proximity to one another) and removed at the same outlet point. It is preferred that this step is carried out in a single mixing step (i.e. with a single mixer), however, multiple mixing steps may be employed, for example employing a plurality of co-current mixers arranged in series. Where a plurality of co-current mixers are used, the resulting mixture will usually be separated into separate gas and liquid phases prior to the addition of further amine solution and further co-current mixing (and separation).

Although it is preferred that the steps of contacting the natural gas with the amine solutions takes place in one or more co-current mixers, as described above, a conventional counter-current absorber may be employed instead of or in addition to the co-current mixer or mixers. Such processes are particularly appropriate in applications where co-current mixing is not sufficient to remove enough of the acid gas to reach the industry standard

In some embodiments (e.g. where contacting occurs in an absorber or a mixer), the processes of the invention may further comprise a separation step after each of steps (i) and (ii) to separate the natural gas stream from the first aqueous amine solution containing absorbed acid gas or the second aqueous amine solution containing absorbed water, as appropriate. These separation steps may be carried out in a separator.

Thus, in one embodiment, the invention may comprise the following steps: (i) contacting the natural gas stream with a first aqueous amine solution, said first solution comprising an amine and a first amount of water, so as to produce a natural gas stream with a reduced acid gas content and a first aqueous amine solution containing absorbed acid gas;

(i) (a) separating the natural gas stream with a reduced acid gas content and the first aqueous amine solution containing absorbed acid gas;

(ii) contacting the natural gas stream with a second aqueous amine- solution, said second solution comprising an amine and a second amount of water, so as to produce a natural gas stream with a reduced water content and a second aqueous amine solution containing absorbed water; and (ii)(a) separating the natural gas stream with a reduced water content and the second aqueous amine solution containing absorbed water.

In a further embodiment of the invention, steps (i) and (ii) are carried out in a single contactor, such as a single absorber column. This may occur by way of the absorber column being split into two sections, such as a lower section in which step (i) occurs and an upper section in which step (ii) occurs, or vice versa. The two sections are typically separated by a chimney tray, which enables passage of the natural gas from the lower to the upper section without passage of the first or second aqueous amine solutions.

In an alternative embodiment, steps (i) and (ii) are carried out in separate contactors, such as two absorber columns. For example, step (i) takes place in a first absorber column so as to produce a natural gas stream having reduced acid gas content and a first aqueous amine solution containing absorbed acid gas. The first aqueous amine solution may be referred to as a lean solution prior to the absorption of acid gas from the natural gas. After absorption of acid gas, the first aqueous amine solution may be referred to a rich solution. The natural gas stream having reduced acid gas content and the rich first aqueous amine solution exit the first absorber via separate outlets.

By "reduced acid gas content" we mean that the natural gas stream exiting the first absorber contains a lower amount of acid gas than the natural gas stream entering the first absorber. Where the "acid gas" is hydrogen sulfide only, the natural gas stream with reduced acid gas content will typically contain at least 50% less acid gas than the natural gas stream entering the first absorber, preferably at least 70% less acid gas.

The gas stream is then typically fed to a second absorber column where step (ii) takes place so as to produce a natural gas stream having reduced water content and a second aqueous amine solution containing absorbed water. The second aqueous amine solution may be referred to as a lean solution prior to the absorption of water from the natural gas. After absorption of water, the second aqueous amine solution may be referred to a rich solution. The natural gas stream having reduced water content and the rich second aqueous amine solution then exit the second absorber via separate outlets.

By "reduced water content" we mean that the natural gas stream exiting the second absorber contains a lower amount of water than the natural gas stream entering the second absorber. Typically, the natural gas stream with reduced water content will contain at least 50% less water than the natural gas stream entering the first absorber, preferably at least 70% less water

The process of the invention may comprise additional processing steps such as cooling or heating, as appropriate, in addition to further treatment steps including mercury removal, and removal of heavy hydrocarbons (HHC) and BTX. Such steps may be carried out according to conventional methods known to those skilled in the art. Other downstream processing steps may also be performed, as desired. For example, the purified natural gas stream may be subjected to liquefaction using conventional technology.

Regeneration steps will typically also be included so as to recover the first and second aqueous amine solutions. The first and second aqueous amine solutions may be recovered in separate processes or in a single integrated process.

Regeneration will typically take place by methods known in the art and may involve the use of vacuum conditions.

The process of the invention is preferably carried out subsea.

In a particularly preferred embodiment, the process of the invention produces the second aqueous amine solution in situ. This has the added benefit that only a single aqueous amine solution (equivalent to the first aqueous amine solution of the invention) needs to be supplied to the treatment facility. The second aqueous amine solution with a lower water content is produced in situ.

The in situ production of the second aqueous amine solution may be carried out in a stripper. Thus, in a further preferable embodiment of the invention, the process further comprises a stripping step in which the first aqueous amine solution is stripped of water using a water-undersaturated natural gas stream so as to produce a natural gas stream containing stripped water and the second aqueous amine solution. This stripping step will typically be carried out prior to step (i) of the process. Thus, the natural gas stream used in step (i) may be the "natural gas stream containing stripped water" produced in the stripping step.

By "water-undersaturated natural gas stream" we mean natural gas which has a pressure and/or temperature higher than its water dew pressure/temperature. This means that the water-undersaturated stream has capacity to hold additional gas- phase water. The water-undersaturated hydrocarbon gas stream has a high affinity for water and therefore draws water from the first aqueous amine solution to produce an aqueous amine solution with a water content lower than that of the first aqueous amine solution, i.e. the second aqueous amine solution. This process is known as "stripping". The water-undersaturated hydrocarbon gas stream may be produced by methods known in the art and will typically have a temperature between 50°C and 130°C and a pressure between 30 and 120 bar.

In one particularly preferred embodiment, the process of the invention is carried out as follows. This process is illustrated in Figure 1.

A natural gas stream is received from a wellhead via a pipeline 4. The gas stream will typically contain a mixture of liquid phase hydrocarbons, gas phase hydrocarbons and, acid gas and water. The mixture may also contain other contaminants and, depending on the distance from the wellhead, the mixture may also contain a hydrate inhibitor injected to prevent hydrate formation in the pipeline 4.

The well stream is separated into a gas phase and a liquid phase via a separator 6. The gas phase is output via a first gas-phase conduit 8 and the liquid phase is output via a first liquid-phase conduit 10. The gas phase stream comprises hot, saturated hydrocarbon gas, typically at temperatures of between 30-130°C.

The gas phase stream in the first gas-phase conduit 8 is then mixed with a rich first aqueous amine solution using a first mixer 14. The rich first aqueous amine solution mixture is supplied to the first mixer 14 via a rich first aqueous amine solution conduit 12.

The gas phase stream is then cooled using a first cooler 16 to a temperature which facilitates further acid gas absorption into the rich first aqueous amine solution. The first cooler 16 typically comprises a gas-water cooler that heat exchanges with the surrounding sea water. However, a choke valve may also be used to expand the gas phase stream, thereby cooling the gas phase stream to below the sea water temperature due to the Joule Thomson or Joule-Kelvin effect.

The cooled stream is then passed from the cooler 16 to a second separator 18 where gas and liquid phases are separated into a gas phase exiting the separator 18 via a second gas-phase conduit 20 and a liquid phase exiting the separator 18 via a second liquid-phase conduit 22.

The liquid phase exiting the second separator 18 is a very rich first aqueous amine solution mixture comprising amine, water and absorbed acid gas. By "very rich first aqueous amine solution" we mean a first aqueous amine solution which has been used in at least two acid gas absorption steps and thus contains more acid gas than a "rich first aqueous amine solution" which, in the context of this embodiment of the invention, has been used in only a single acid gas removal step.

The gas phase exiting the second separator 18 via the second gas-phase conduit 20 is a cool, saturated gas-phase hydrocarbon stream. The gas phase in the second gas-phase conduit 20 is then heated and/or pressurised to create a water- undersaturated natural gas stream. A water-undersaturated gas is one having a pressure/temperature higher than its water dew pressure/temperature. This means that, the water-undersaturated stream has capacity to hold additional gas-phase water. In this embodiment, the gas phase stream is both heated and pressurised using a compressor 24.

The water-undersaturated hydrocarbon gas stream in the second gas-phase conduit 20 is then mixed with a lean first aqueous amine solution using a second mixer 26. The lean first aqueous amine solution is supplied to the second mixer 26 via a lean first aqueous amine solution conduit 28. The lean first aqueous amine solution conduit 28 receives a first portion of a lean first aqueous amine solution supplied via supply conduit 30.

The water-undersaturated hydrocarbon gas stream has a high affinity for water and therefore draws water from the lean first aqueous amine solution. This process is known as "stripping". The high temperature of this mixture also causes water to evaporate from the lean first aqueous amine solution, further decreasing the water content in the solution.

The mixture is then passed from the second mixer 26 to a third separator 32 where gas and liquid phases are separated into a gas phase exiting the separator 32 via a third gas-phase conduit 34 and a liquid phase exiting the separator 32 via a third liquid-phase conduit 36. The liquid phase in the third liquid-phase conduit 36 comprises a lean second aqueous amine solution that has a lower water content than the lean first aqueous amine solution supplied by conduit 28. By selecting suitable parameters for the flow rate of the lean first aqueous amine solution and hydrocarbon gas and for the operation of the compressor 24, it is possible to regulate the water content of the lean second aqueous amine solution such that it is sufficiently low to dry a gas to a desired specification.

The gas phase from the third separator 32 in the third gas-phase conduit 34 comprises a higher water content than the gas phase in the second gas-phase conduit 20 from the second separator 18 because water has been stripped from the amine solution by the hydrocarbon gas.

The gas phase in the third gas-phase conduit 34 is cooled by a second cooler 38 and the cooled gas phase stream is then mixed with a lean first aqueous amine solution by a third mixer 40. The lean first aqueous amine solution is supplied to the third mixer 40 via a conduit 42. Conduit 42 receives a second portion of a first lean aqueous amine solution supplied via supply conduit 30.

Cooling the gas stream using the second cooler 38 knocks out most of the water stripped from the lean first aqueous amine solution injected by the second mixer 26.

The mixture is then passed from the third mixer 40 to a fourth separator 44 where gas and liquid phases are separated into a gas phase exiting the separator 44 via a fourth gas-phase conduit 46 and a liquid phase exiting the separator 44 via a fourth liquid-phase conduit 48.

The liquid phase exiting the fourth separator 44 in the fourth liquid phase conduit 48 is a rich first aqueous amine solution comprising amine, acid gas and water. In this embodiment, the fourth liquid phase conduit 48 connects to the rich first aqueous amine solution conduit 12 such that the rich first aqueous amine solution from the fourth separator 44 is supplied to the first mixer 14.

The gas phase in the fourth gas-phase conduit 46 is pressurised by a compressor 50 to a pressure for pipeline transportation. The pressurised gas stream is then cooled by a third cooler 52.

The gas phase in the fourth gas-phase conduit 46 is then mixed with the lean second aqueous amine solution by a fourth mixer 54. The lean second aqueous amine solution is supplied to the fourth mixer 54 via the lean second aqueous amine solution conduit 36 from the third separator 32. A pump 56 is incorporated in the lean second aqueous amine solution line 36 to pressurise the supply of lean second aqueous amine solution to the fourth mixer 54 for mixing with the pressurised gas phase stream.

The mixture is then passed from the fourth mixer 54 to a fifth separator 58 where gas and liquid phases are separated into a gas phase exiting the separator 58 via a fifth gas-phase conduit 60 and a liquid phase exiting the separator 58 via a fifth liquid-phase conduit 62.

Relatively little acid gas remains in the gas phase in the fourth gas-phase conduit 46. Thus, the rich second aqueous amine solution from the separator 58 that exits in the fifth liquid phase conduit 62 comprises mainly amine and water. The solution in this conduit 62 can therefore be recycled into one of the conduits 28, 42 to improve efficiency.

The gas phase exiting the fifth separator 58 via the fifth liquid phase conduit 60 has been dried so as to have a water content sufficiently low such that hydrates do not form during transportation at ambient seabed temperatures. Typically this is a water content in the range of 20 to 100 ppm.

The invention also provides apparatus arranged to perform the processes of the invention. Preferable aspects discussed in the context of the processes of the invention apply equally to the apparatus embodiments.

Thus, in a further embodiment, the invention provides apparatus comprising:

(i) A first contactor configured to receive a natural gas stream and a first aqueous amine solution via at least one first inlet so as to produce a natural gas stream with reduced acid gas content and a rich first aqueous amine solution, wherein the natural gas stream with reduced acid gas content exits the first contactor via a first gas phase conduit and the rich first aqueous amine solution exits the first contactor via a first liquid phase conduit; and

(ii) A second contactor configured to receive a natural gas stream and a second aqueous amine solution via at least one second inlet so as to produce a natural gas stream with reduced water content and a rich second aqueous amine solution, wherein the natural gas stream with reduced water content exits the second contactor via a second gas phase conduit and the rich second aqueous amine solution exits the second contactor via a second liquid phase conduit.

The first and second contactors may be connected in series. Preferably, the first gas phase conduit is in fluid communication with the at least one second inlet of the second contactor so as to allow the natural gas stream with reduced acid gas content to flow from the first contactor to the second contactor.

The apparatus may further comprise a stripper (e.g. in those embodiments of the invention where in situ generation of the second aqueous amine solution is desired), wherein the stripper is configured to receive a natural gas stream and the first aqueous amine solution via at least one inlet and is further configured to strip water from the first aqueous amine solution using the natural gas stream so as to produce a wet gas stream and the second aqueous amine solution, wherein the wet gas stream exits the stripper via a gas phase conduit and the second aqueous amine solution exits the stripper via a liquid phase conduit.

The natural gas stream supplied to the stripper is typically a water- undersaturated hydrocarbon gas stream.

By "wet gas stream" we mean a natural gas stream which contains absorbed gas phase water. In the context of the present invention, the gas phase water is typically absorbed from the first aqueous amine solution.

The apparatus of the invention may also further comprise the following features:

(i) The gas phase conduit from the stripper is in fluid communication with the at least one first inlet of the first contactor so as to allow the wet gas stream to flow from the stripper to the first contactor; and

(ii) The liquid phase conduit from the stripper is in fluid communication with least one first inlet of the second contactor so as to allow the second aqueous amine solution to flow from the stripper to the second contactor.

The rich second aqueous amine solution may have a water content similar to the first aqueous amine solution. Thus, it is possible for the rich second aqueous amine solution to be combined with the first aqueous amine solution and recycled back to the stripper and/or the first contactor. This may be achieved by having apparatus configured such that the second liquid phase conduit from the second contactor is in fluid communication with the at least one inlet of the stripper and/or the at least one first inlet of the first contactor.

The invention also provides the use of a first aqueous amine solution comprising an amine and a first amount of water and a second aqueous amine solution comprising an amine and a second amount of water in a process for treating a natural gas stream, wherein the amine in the first and second solution is the same and wherein the first amount of water is greater than the second amount of water. Preferable aspects for each of the features in this embodiment are as hereinbefore defined.

In a yet further aspect the invention provides the use of a first aqueous amine solution comprising an amine and a first amount of water and a second aqueous amine solution comprising an amine and a second amount of water in a process for the production of purified natural gas, wherein the amine in the first and second solution is the same and wherein the first amount of water is greater than the second amount of water. Preferable aspects for each of the features in this embodiment are as hereinbefore defined.

The invention also provides purified natural gas obtained or obtainable by any of the processes herein described. The purified natural gas will preferably have a water content in the range of 20 to 100 ppm and acid gas (C0 ₂ + H ₂ S) content in the range of less than 4 ppm H ₂ S and around 2 to 3 mol% C0 ₂ .

Examples

Internal equilibrium data were measured for a number of solutions containing a range of MDEA contents. The results are presented in Figures 2 and 3.

In the H ₂ S-experiments, the partial pressure of H ₂ S was varied up to 1 bar - all experiments were carried out at 70 °C and total pressure below 1.1 bar. Data for three partial pressures are given in Figure 2.

In the C0 ₂ experiments, the temperature was varied between 40 and 80 °C. The total pressure was 1 .1 bar (meaning that P_H20 + P_C02 = 1 .1 bar in all experiments). These results are given in Figure 3.

The figures demonstrate the ability of the amine solutions to absorb H ₂ S and C0 ₂ . The solubility of C0 ₂ /H ₂ S depends significantly on the wt% of MDEA, and that it is at a maximum in the 40-50 wt% range. Moreover, a solution with 70-90 wt% MDEA is able to absorb a significant quantity of the acid gas. However, when the wt% MDEA approaches 100%, the C0 ₂ /H ₂ S capacity of the solvent is very low.

Simulation data for the absorption of water and H ₂ S according to the processes of the invention were obtained. The data relate to the use of a first aqueous amine solution containing 75 wt% MDEA and 25 wt% water and a second aqueous amine solution containing 98.9 wt% MDEA and 1 .1 wt% water. The natural gas stream in this example is a dry, lean gas, comprising heavy C ₂₊ hydrocarbons and acid gases. The process is carried out according to the specific embodiment shown in Figure 1 . Thus, the conduit numbering and points A to G relate to the reference numerals used in Figure 1 .

Tables 1 and 2 below set out the conditions in the various gas phase and liquid phase conduits. Table 1. Amine stream conditions in the various liquid-phase conduits.

Table 2. Conditions at points A to G in the various gas phase conduits.

These results demonstrate that treatment of a natural gas stream with a first and second aqueous amine solution according to the processes of the invention can produce a treated gas stream with a water content of 29 ppm and an H ₂ S content of 3.9 ppm. These values are well within the specifications required by industry standards relating to natural gas production and transportation.