GB2142041A - Extracting natural gas streams with physical solvents - Google Patents

Abstract

A continuous process is described for extracting a raw inlet natural gas stream with a physical solvent, flashing the rich solvent, and selectively rejecting a consecutive molecular weight string of C1-C4 components from at least a portion of the off-gas flashed from the rich solvent stream or streams. The process produces: (a) a liquid C2 + hydrocarbon product, having a composition that is selectively adjustable to substantially any selected degree as the liquid market price for a low molecular weight C2-C4 component or string of components falls below the fuel price thereof, and (b) a sweet, dry residue natural gas stream of pipeline quality which includes the rejected C1-C4 hydrocarbon components. If the liquid market price of the C3 and/or C4 components is below the fuel price thereof while the liquid market price of a lower molecular weight component is not, the C1-C4 components are further extracted, flashed, and split before returning the desirably priced component or components to the liquid product. <IMAGE>

Description

SPECIFICATION Process for extracting natural gas streams with physical solvents This invention relates to the treatment of hydrocarbons and more specifically relates to separating and recovering ethane and higher boiling hydrocarbons from the methane in a - natural gas stream which may or may not contain acidic components, such as CO2 and H2S.

A typical natural gas stream contains a mixture of individual gaseous constituents, some of which can be liquefied at atmospheric temperatures and pressures when isolated. The quantities of each component vary from one gas to another, with methane as a usual majority component.

Other hydrocarbon components include ethane, propane, isobutane, normal butane, isopentane, normal pentane, hexane, heptane, octane, and nonane, in the order of increasing molecular weight and increasing normal boiling temperature. Usually, natural gases contain some gaseous contaminants such as nitrogen, carbon dioxide, carbonyl sulfide, hydrogen sulfide, mercaptans, disulfides, and water. However, all of these impurities except water and nitrogen are removed by sweetening.

Numerous processes have been used to extract liquids from natural gas streams. These processes include oil absorption, refrigerated oil absorption, simple refrigeration, cascaded refrigeration, Joule-Thompson expansion, and cryogenic turbo-expansion. Typical recoveries for these processes are given in Table I.

TABLE 1 COMPARISON OF TYPICAL LIQUID RECOVERIES

EXTRACTION PROCESS ETHANE PROFANE 3UTANES GASOLINE ( % ) . (o/) ( O (o ABSORPTION 4 24 1 75 87 REFRIGERATED ABSORPTION 15 65 90 95 SIMPLE REFRIGERATION 35 80 1 93 97 CASCADED REFRIGERATION 70 96 99 100 JOULE-THOMPSON EXPANSION i5 96 99 100 TURBO-EXPANDER 85 97 100 100 In summary, the oil absorption, refrigerated oil absorption, simple refrigeration, and cascaded refrigeration processes operate at the pipeline pressures, without letting down the gas pressure, but the recovery of desirable liquids (ethane plus heavier components) is quite poor, with the exception of the cascaded refrigeration process which has extremely high capital and operating costs but achieves good ethane and propane recoveries. The Joule-Thompson and cryogenic expander processes achieve high ethane recoveries by letting down the pressure of the entire inlet gas, which is primarily methane (typically 80-85%), but recompression of most of the inlet gas is quite expensive.

In all of the above processes, the ethane plus heavier components are recovered in a specific configuration determined by their composition in the raw natural gas stream and equilibrium at the key operating conditions of pressure and temperature within the process.

Specifically, the refrigeration process which typically recovers 80% of the propane also typically requires the recovery of 35% of the ethane. In order to boost propane recovery to the 95 + % level, cascaded refrigeration, Joule-Thompson, or cryogenic turbo expander processes would have to be used while simultaneously boosting the ethane recovery to 70 + % at a considerably larger capital investment.

Under poor economic conditions when ethane price as petrochemical feedstock is less than its equivalent fuel price and when the propane price for feedstock usage is attractive, the operator of a natural gas liquid extraction plant is limited as to operating choice because he is unable to minimize ethane recovery and maximize propane recovery in response to market conditions.

Specifically, when the ethane price as petrochemical feedstock is greater than its fuel value while propane price as propane feedstock is unattractive, none of the above-mentioned processes allow an operator to selectively recover ethane while rejecting propane.

Extraction processes are available that employ liquids other than hydrocarbon oils for removal of acidic components, including H25 and CO2, and water. These liquids comprise most physical solvents, such as propylene carbonate, N-methyl pyrrolidone, glycerol triacetate, polyethylene-glycol dimethyl ether, triethylolamine, tributyl phosphate, and gamma butyrolactone.

U.S. Patents 3,362,133, 3,770,622, 3,837,143, 4,052,176, and 4,070,165 teach various prior art processes for extracting acidic components, heavier hydrocarbons, or water from natural gas streams.

As presented at the 50th Annual Gas Processors Association Convention, March 17-19, 1980, Houston, Texas, U.S.A., in a paper entitied "High C02-High H2S Removal with SELEXOL Solvent" by John W. Sweny, the relative solubility in dimethylether of polyethylene glycol (DMPEG) of CO2 over methane is 15.0 while that of propane is 15.3. The relative solubility in DMPEG of H2S over methane is 1 34 versus 165 for hexane. The relative solubilities in DMPEG of iso and normal butanes and iso and normal pentanes are between those of CO2 and H2S.These data indicate that if CO2 and H2S are present in a natural gas stream which contains C2 + heavier hydrocarbons desirable for petrochemical industry feedstocks, substantial quantities of C2 + hydrocarbons will be lost with CO2 and H2S vent streams when treated with DMPEG.

A natural gas stream is usually saturated with water at its ambient temperature which may have a range of 24-49'C so that its water content may vary from 0.34 kg to more than 0.85 kg per thousand normal cubic meters. However, difficulties are frequently met while pumping such natural gas unless the water content is reduced to a value of less than 0.2 kg, preferably less than 0.12 kg, of water per thousand normal cubic meters of natural gas. In terms of dew point, a natural gas having a dew point of - 1 'C, preferably - 7'C or lower, is generally considered safe for transportation in a pipeline. Dehydration can be carried out under a wide range of pressures from 100 to 35,000 kPa, but it is usually carried out at pipeline pressures of 3500-10,000 kPa and generally near 7,000 kPa.

There has nevertheless existed a need for a process wherein C2 + hydrocarbons and water could be simultaneously removed to any selected degree without also extracting hydrocarbons of lower molecular weight, such as methane.

There has additionally existed a need for a process wherein any natural gas, from very sour to entirely sweet, could be handled by the same equipment while simultaneously dehydrating the gas and recovering the heavier hydrocarbons.

However, daily changes in market conditions may also cause the price of a single liquid hydrocarbon heavier than ethane to drop below its fuel price so that this hydrocarbon should be selectively rejected, but there is presently no way of doing so without also rejecting all components of lower molecular weight. For example, if the price of ethane is below its fuel value, it can be rejected with the methane, but if the price of propane is below its fuel value while the price of ethane is above its fuel value, no method exists for recovering ethane and butane plus heavier hydrocarbons (C4 +) from the natural gas stream.

Therefore, for all components heavier than ethane, there exists a need for selectively rejecting any one or two selected hydrocarbons of consecutive molecular weight that are heavier than another recoverable and desirable hydrocarbon which may include ethane. As a practical matter, such hydrocarbons which need to be selectively rejectable are propane, the butanes, and propane plus the butanes.

An object of this invention is to provide an extraction process for selectively removing C2 +, C3 +, C4 +, or C5 + hydrocarbon components from a natural gas stream by contact with a physical solvent, according to an extremely flexible wide range of hydrocarbon recoveries but preferably while achieving extremely high hydrocarbon recoveries, for selectively rejecting therefrom the C1 + C2, C1 - C3, C1 - C4, or C2 - C4 components of consecutive molecular weight, and for selectively recovering therefrom the C2, the C3, or the C2 + C3 components.

Another object is to provide a process for forming a residue natural gas of pipeline quality consisting only of undesirable hydrocarbon components of a natural gas stream to any selected degree and for producing a liquid hydrocarbon product consisting only of desirable hydrocarbon components to any selected degree.

An additional object is to provide a process for selectively removing C2 +, C3 +, C4 +, or C5 + components, water, and acid components from a sour natural gas stream by contact with a hydrocarbon extraction solvent and to separate all such components from the solvent and in the same equipment and then to separate the acid components from the C2 +, C3 +, C4 +, or C5 + components in liquid phases.

It is a particular object of this invention to utilize a physical solvent as the preferred hydrocarbon extraction solvent and to utilize a dialkyl ether of polyethylene or polypropylene glycol or mixtures thereof as the preferred physical solvent.

A further object is to provide a process for forming a residue natural gas to be used for burning purposes with a heat content within a specified range.

A still further object is to provide a process for forming a residue natural gas to bused as petrochemical feedstock with a specified composition, such as two or three components of a specified ratio, in which methane is the inert diluent.

According to these objects and the principles of-this invention, a process is herein provided that is useful when changes in the market prices for individual hydrocarbons in liquid form cause the market price for an individual hydrocarbon liquid to fall below its fuel price. Such prices change on a daily basis. Accordingly, it becomes advantageous to be able to extract all of the hydrocarbon liquids while rejecting and returning to the residue gas line one or more hydrocarbons that are priced below their fuel value. The extracting plant can thereby be operated at optimum profit levels at all times.

Another market condition can be founded on a customer preference, based on a need to supply feeds to a chemical plant, for example. Specifically, such a plant may require ethane, butanes, and all heavier hydrocarbons but no propane.

The invention is an improvement in a continuous process for separating water and hydrocarbons heavier than methane from an inlet natural gas stream which comprises: 1) extracting the water and the hydrocarbons heavier than methane from the natural gas stream with a physical solvent at pipeline pressures and at a solvent flow rate sufficient to produce rich solvent containing the water, a C, + mixture of hydrocarbons, and a residue natural gas of pipeline quality which is returned to a pipeline, 2) successively flashing the rich solvent in a plurality of flashing stages at successively decreasing pressures to produce a plurality of successive C, + gas fractions, having successively lower methane contents, and liquid mixtures of the water, the solvent, and mixtures of hydrocarbons having successively lower methane contents, and 3) regenerating the liquid mixture from the last stage of the flashing stages to produce the physical solent for the extracting. This improvement produces a residue natural gas stream and a liquid hydrocarbon product having a composition which is selectively adjustable to substantially any selected degree in accordance with market conditions. Such adjustment in the liquid hydrocarbon product composition enables the product: (1) to consist essentially of C2 +, C3 +, C4 +, or C5 + hydrocarbon components; or (2) to contain all C2 + or C3 + components except at least one intermediate component, selected from the group consisting of the C3 and the C4, which is combined with the residue natural gas stream; or (3) to contain other selected components of the inlet natural gas stream to any selected degree.The process comprises the capability of utilizing at least one of the following operational procedures: A. Selectively varying the flow rate of the solvent with respect to the flow rate of the inlet natural gas stream during the first extracting to adjust the composition of the rich solvent relative to selected components of the group consisting of ethane, propane, and iso and normal butanes while producing the residue natural gas stream; B. selectively varying the flashing pressures of the successive flashing stages to adjust the composition of the successive gas fractions and the successive liquid mixture relative to the selected components; C. recycling at least the first of the successive flashed C, + gas fractions to the extracting to extract maximum quantities of the ethane and heavier hydrocarbons;; D. stripping at least the last of the successive C + gas fractions, in order to produce the liquid hydrocarbon product comprising the selected components and a recycle gas stream comprising Cl, C1 + C2, C, + C2 + C3, or Cl + C2 + C3 + C4 for recycle to the extracting, by:: 1) selectively varying the pressure of the stripping and/or 2) selectively varying the bottoms temperaure of the stripping; E. as a second extracting step, extracting an extract feed stream, selected from the group consisting of the recycle gas stream, a flashed-off gas stream from at least one of the plurality of flashing stages, and mixtures thereof, with the physical solvent at a selected flow rate that controls the selected degree of recovery of the selected C2 + components in a rich solvent stream, the unextracted portion of the extract food stream being recycled to the extracting of the inlet natural gas stream; F. flashing the rich solvent stream and producing a singly flashed-off gas stream, containing the selected C2 + components, and a bottoms solvent stream;; G. regenerating the liquid mixture from at least the last stage of the flashing stages of step B and the bottoms solvent stream of step F in order to produce the physical solvent for the first extracting and the second extracting; and H. splitting the singly flashed-off gas stream and producing an overhead product stream, selected from the group consisting of C2, C3, and C2 + C3, and a bottoms stream, selected from the group consisting of C3, C4, and C3 + C4, the bottoms stream being combined with the residue natural gas stream of Step A and the overhead product stream being combined with the liquid hydrocarbon product of Step D.

If the natural gas stream is sour, it is preferred that it be sweetened by contact with a chemical solvent that does not absorb hydrocarbons, such as an amine before the absorption process of this invention is utilized. However, if an amine pretreating step is not economical in the gas phase, the sour natural gas stream can be treated according to the instant process. The acidic components are then maintained in liquid-phase or vapor-phase solution or contact, respectively, with the heavier hydrocarbon components until the solution or mixture, as a liquid, can be contacted by a chemical solvent. Because such post-absorption sweetening is done in liquid phase, the capital cost for treating equipment is relatively low.

When an operator is changing process conditions to produce a new liquid product mix of consecutive molecular weight components in accordance with the needs of the market, he must have all process steps A-H available for consideration. He must consider each of the steps in the order listed, but he need not necessarily change all of them. For some natural gas streams, solvent flow variation and recycling in addition to stripping is adequate, for example. However, for most natural gas streams, optimum efficiency is obtained when all eight of the preceding conditions and steps are utilized.It is thereby extremely easy, for example, to recover 99 + % of propane along with 100% of heavier hydrocarbons and less than 2% of ethane without any additional investment or to recover 98 + % of the ethane and 99 + % of the butanes with all heavier hydrocarbons and less than 2% of the propane without any additional investment.

The flexibility of this process is illustrated in the accompanying Table II. The first four cases or situations summarize the capabilities for selectively extracting C2 + hydrocarbons and particularly for selectively not extracting or extracting and then rejecting consecutively lower molecular weight hydrocarbons, viz., C, + C2, C, + C2 + C3, or C, + C2 + C3 + C4. It should be understood, however, that C4 refers to both iso and normal butanes, C5 refers to both iso and normal pentanes, and all components heavier than C5.

It should also be understood that minor amounts of other desirable or undesirable components may be present which are not shown in Table II. The components shown under various streams are those which are predominant.

The last four cases or situations in the table summarize the capabilities for further processing the rejected hydrocarbons from the stripping unit plus any flashed-off gases that are neither recycled to the first extracting unit nor sent to the stripping unit. This combined feed is extracted in the second extracting unit with a portion of the same physical solvent as used in the first extracting unit. The unextracted hydrocarbons, which are methane, or methane plus ethane, containing minor amounts of desirable hydrocarbons such as ethane or propane, are sent to the first extracting unit, and the rich solvent stream from the second extracting unit is sent to the single flashing unit. The extracted and flashed-off hydrocarbons are compressed, cooled, and condensed, and are then sent to the splitting unit which has a reboiler. The operating pressure and bottoms temperature of the stripping and the splitting units can be varied at will. The overhead from the splitting unit is combined with the selected liquid hydrocarbon product from the stripping unit, and the bottoms from the splitting unit is the selected reject having a liquid hydrocarbon value below its fuel value and is combined with the residue gas of pipeline quality. TABLE II

First Extracting, Multiple Second Extracting, Single Flashing, and Stripping Flashing, ans Splitting Products I C1 C1 C2+ C1 --- --- --- --- --- C2+ C1 II C1,C2 C1,C2 C3+ C1,C2 --- --- --- --- --- C3+ C1,C2 III C1,C2, C1,C2, C4+ C1,C2, --- --- --- --- --- C4+ C1,C2, C3 C3 C3 C3 IV C1,C2, C1,C2, C5+ C1,C2, --- --- --- --- --- C5+ C1,C2, C3,C4 C3,C4 C3,C4 C3,C4 V C1,C3 C1 C4+ C1,C2, C1,C2, C1 C2,C3 C3 C2 C2,C4+ C1,C3 C3 C3 VI C1,C4 C1 C5+ C1,C5, C1 C2,C3, C4 C2,C3 C2,C3, C1,C4 C3,C4 C3,C4 C4 C5+ VII C1,C2, C1,C2 C5+ C2,C3, C2,C3' C2 C3,C4 C4 C3 C3,C5+ C1,C2, C4 C4 C4 C4 VIII C1,C3, C1 C5+ C1,C2, C1,C2, C1 C2,C3, C3,C4 C2 C2,C5+ C1,C3, C4 C3,C4 C3,C4 C4 C4 Pipelinos 12 95 92 137 152 162 175 172 84 19 This process can be operated to remove C2 + hydrocarbon liquids from the inlet natural gas stream and to reject the methane therein as the selected degree, whereby the liquid product of the stripping, being operated as demethanizing, comprises up to 98% of the ethane content, all heavier hydrocarbons that are in the inlet natural gas stream, and less than 2% of the methane content therein as the selected degree (Case I in Table II).

On the other hand, this process can be operated to remove C3 + hydrocarbon liquids from the natural gas stream and to reject the methane and ethane therein as the selected degree, the stripping of the Step D being operated as de-ethanizing (Case II in Table II). The liquid product of the de-ethanizing thereby comprises up to 99% of the propane content, all heavier hydrocarbons that are in the natural gas stream and less than 2% of the ethane content therein as the selected degree.

This process can also be operated to recover C4 + hydrocarbon liquids and to reject methane, ethane, and propane therein as the selected degree, the stripping of Step D being operated as a depropanizing which produces a liquid product comprising approximately 100% of the butanes, all heavier hydrocarbons that are in the natural gas stream, and less than 2% of ethane and propane therein as the selected degree (Case Ill in Table II).

Furthermore, the process can be operated to recover C5 + hydrocarbon liquids from the natural gas stream and to reject the ethane, propane, and butane therein as the selected degree, the stripping being operated as a debutanizing step which produces a liquid product comprising approximately 100% of the pentanes, all heavier hydrocarbons that are in the natural gas stream, and less than 2% of ethane, propane, and butanes as the selected degree (Case IV in Table II).

The ethane and propane can be substantially completely rejected in the first extracting and in the multiple flashing stages. Alternatively, they can be partially rejected in the first extracting, further rejected in the multiple flashing stages, and substantially completely rejected after passing through the stripping operation; the first one or two off-gas streams are typically recycled to the first extracting and the last one or two off-gas streams are sent to the stripping.

As a second alternative, they can be rejected only slightly, if at all, in the first extracting, moderately rejected in the flashing stages, and mostly rejected in the stripping or all of the offgas from the multiple flashing stages may then be sent to the demethanizing. Either alternative can be used for the selective rejection of propane according to this invention because a fairly small part of the methane and 98% of the ethane and propane are available as an extract feed stream for the second extracting unit.

Selective rejection of propane, according to Case V in Table II, occurs by operating the stripping as depropanizing and by countercurrently extracting the extract feed stream, containing C1, C2, and C3, with the physical solvent in the second extracting, whereby the C, is removed and returned to the first extracting. The rich solvent is then singly flashed, compressed, condensed and processed in the splitting unit being operated as a de-ethanizer thereby producing C2 as the overhead product which is combined with C4 + from the stripping unit and C3 as the bottoms product which is combined with the residue natural gas from the first extracting.

According to Case VI in Table II, the extract feed stream consists essentially of C1, C2, C3, and C4 hydrocarbons because the stripping unit is operated as debutanizing. After the second extracting, C, is primarily the unextracted hydrocarbon which is recycled to the first extracting and C2, C3, and C4 form the flashed-off gas stream which is depropanized in the splitter to form C4 as the bottoms stream which is rejected to the residue gas pipeline and C2 + C3 as the overhead product stream which is combined with the bottoms stream from the stripping unit being operated as debutanizing.

According to Case VII in Table II, wherein C5 + hydrocarbon liquids form the bottoms of the stripping unit being operated as debutanizing, the first extracting and the multiple flashing stages are operated so that, with recycling of the first two off-gas streams to the first extracting, essentially all of the C, and much of the C2 are not extracted and are in the residue natural gas stream. The remaining C2, the C3, and the C4 form the extract feed stream for the second extracting. C2 forms the overhead stream which is recycled to the first extracting, and C3 and C4 are extracted in the second extracting and depropanized in the splitter to produce C3 as the overhead stream which is combined with the C5 + hydrocarbon liquids to form the liquid hydrocarbon product.The bottoms stream from the depropanizing in the splitter is C4 which is combined with the residue natural gas stream from the first extracting.

According-to Case VIII in Table II, wherein C5 + hydrocarbon liquids also form the bottoms of the stripping unit being operated as debutanizing, the first extracting and the multiple flashing stages are operated and the off-gas recycling is arranged so that essentially all of the C2 + components are extracted in addition to some C,. The second extracting feed stream consists of C1, C2, C3, and C4. The overhead from the second extracting is C1, the single-flashed gases are C2, C3, and C4, the de-ethanizing overhead from the splitter is C2, and the de-ethanizing bottoms are C3 and C4.The combined residue natural gas stream therefore contains C1, Cs, and C4, and the combined liquid hydrocarbon products stream contains C2 and C5 + hydrocarbons.

Since the gaseous feed stream to the second extracting unit contains significantly smaller amounts of methane than the inlet natural gas stream being fed through the first extracting unit, the relative partial pressures of the heavier hydrocarbons in the second extractor feed are considerably higher. This situation causes the solvent requirements for the second extracting unit to be significantly lower (in the range of 0.14 to 28 cubic meters per thousand normal cubic meters of second extractor feed) than the solvent requirements for the first extracting unit (0.71 to 71 cubic meters per thousand normal cubic meters of inlet natural gas as first extractor feed), provided both first and second extracting units are operating at the same pressure.

However, there is no external requirement for the pressure in the second extractor to be the same as in the first extractor since the first extractor generally operates at residue gas pipeline pressures. A minimal pressure of 2,700 kHa is essential for the second extracting unit. Since compression of gases is relatively quite expensive, it may be preferred to operate the second extracting unit as close to 2,700 Kpa as possible and consequently forfeit the advantage of concentration of heavier hydrocarbons in the second extractor feed which produces higher partial pressures. In other words, it may be preferred to use higher solvent feed rates to the second extracting unit, similar to the requirements for the first extracting unit of 0.71 to 71 cubic meters per thousand normal cubic meters of extracting feed.In general, therefore, and depending upon the pressures within the extractors, the solvent flow rates to the first and second extractors can vary from 0.14 to 71 m3/Nm3 of feed.

The physical solvent that is preferred for the invention should be selective toward ethane and heavier hydrocarbon components of the inlet natural gas stream with respect to methane, such that the relative volatility of methane over ethane is at least 5.0 and the hydrocarbon loading capacity, defined as solubility of ethane in solvent, is at least 1.77 normal cubic meters of ethane per cubic meter of solvent.

This physical solvent is selected from the group consisting of dialkyl ethers of polyalkylene glycol, N-methyl pyrrolidone, dimethyl formamide, propylene carbonate, tetramethylsulfone, glycerol triacetate, triethanolamine, tributyl phosphate, and gamma butyrolactone. The solvent is preferably selected from the group consisting of dimethyl ether of polyethylene glycol, dimethyl ether of polypropylene glycol, dimethyl ether of tetramethylene glycol, and mixtures thereof, and the solvent most preferably is dimethyl ether of polyethylene glycol containing 3-10 ethylene units and having a molecular weight of 146 to 476.

The solvent regenerating is done by supplying heat to a reboiler to produce an overhead vaporous stream which is cooled, condensed, settled, pumped, and returned to the regenerator as reflux after disposing of excess waste water therefrom. Typically, the selected solvent flow rate ranges between 0.14 to 71 cubic meters per thousand normal cubic meters of the natural gas streams.

The selected flashing pressures of the successive flashing stages vary between 8960 kPa and 1 4 kPa. The bottoms temperature of the stripping and splitting units varies between - 1 8'C and 150"C.

In the drawings, which are by way of example: Figure 1 is a block diagram which schematically shows the interrelationship of the basic operations of this invention.

Figure 2 is a detailed flowsheet which schematically illustrates a varied combination of preferred embodiments for treating both sweet and sour natural gases, having any water content up to saturation.

The summarized schematic flowsheet of Fig. 1 combines the processes, as given in Cases I through IV in Table II, that produce a recycle stream of consecutive lower molecular weight hydrocabons, selectively from CX through C4, and the processes, as given in Cases V through VIII in Table II, that extract from this recycle stream any Cl and C2 for recycling to the first extracting and then remove C2, C3, or C2 + C3 for combining with the liquid hydrocarbon products from the stripping.

As broadly shown in Fig. 1, sweet or sour inlet natural gas 1 3 enters first extraction unit 10 to which solvent in line 55 and recycled materials in lines 22, 92, and 1 52 are also fed.

Unextracted gas leaves through line 12, and rich solvent leaves through line 1 5 to enter multiple flashing stages 20, 30, 40, 70. Flashed materials pass to stripping unit 90 through line 42, to second extraction unit 1 50 through line 137, and to first extraction unit 10 through line 22. The solvent flows from multiple flashing stages 20, 30, 40, 70 to solvent regeneration unit 50 through line 45, and additional solvent enters through line 1 65. Regenerated solvent returns to first extraction unit 10 through line 55 and to second extraction unit 1 50 through line 141.

The overhead or rejected hydrocarbons of consecutively lower molecular weight are recycled from stripping unit 90 through line 92 to first extraction unit 10 and pass through line 131 to second extraction unit 1 50. The bottoms streams of C2 +, C3 +, C4 +, or C5 + hydrocarbons leaves stripping unit 90 through line 95.

The unextracted hydrocarbons are recycled from second extraction unit 1 50 to first extraction unit 10 through line 1 52. The rich solvent stream flows to single flashing stage 1 60 through line 1 55. Stripped solvent passes to solvent regeneration unit 50 through line 1 65.

The singly flashed-off hydrocarbons pass from single flashing stage 1 60 to splitting unit 1 70 through line 1 62. The overhead stream of C2, C3, or C2 + C3 hydrocarbons passes through line 1 72 to join the bottoms stream of liquid hydrocarbons in line 95 to form stream 97 which leaves the process through line 84 as liquid product. If the inlet natural gas in line 1 3 is sour, however, the combined liquid hydrocarbons pass through line 181 to liquid sweetening 80 and thence, as a sweet liquid hydrocarbons product, through line 82 to line 84 as the liquid product of the process.The bottoms from splitting unit 1 70 is rejected through line 1 75 to combine with unextracted hydrocarbons in line 1 2 from first extracting unit 10 to form sweet residue gas in line 19.

The amplified flowsheet of the improved hydrocarbon separation process of this invention shown in Fig. 2 is the same as the flowsheet of Fig. 1 as to its main details. However, the varied flow paths of the flashed-off gases from multiple flashing stages 20, 30, 40, 70 and of the gases from stripping unit 90 are illustrated in much greater detail.

The process shown schematically in Fig. 2 comprises a first extraction (absorption) unit 10, a medium pressure flash unit 20, a low pressure flash unit 30, an atmospheric flash unit 40, a vacuum flash unit 70, a regenerator unit 50, a stripping unit 90, a liquid sweetening unit 80, a second extraction unit 150, a single flash unit 160, and a splitting unit 1 70. A multiplicity of lines, compressors, coolers, and valves are available for sending each of the flashed and liquid streams to these units in any desired succession in order to extract any hydrocarbon and/or to reject any specific hydrocarbon or group of hydrocarbons from C1 through C4.

When inlet stream 1 3 is a sweet natural gas at 2200-9100 kPa, it has generally been sweetened by countercurrent passage to an aqueous amine solution which has removed sour materials, including H2S and CO2, while saturating the natural gas with water.

Extractor 11 is maintained at about - 10 to 50'C, preferably at about 21 -27'C. Solvent is fed through line 55 at a rate sufficient to reduce the water content of the sweet natural gas leaving through line 1 2 to less than 0.2 Kg per thousand normal cubic meters and preferably to less than 0.12 kg/kNm3. Under these conditions, the ethane and other hydrocarbon components of greater molecular weight in line 1 2 are reduced to a very low value. By altering the amount of solvent entering through line 55, the proportion of ethane to the predominant methane may be varied at will, but the solvent ratio is usually at 0.71 to 71 cubic meters of solvent per thousand normal cubic meters of inlet natural gas, whether sweet or sour.

The rich solvent in line 15 enters medium pressure flash tank 21 from which primarily methane and some heavier hydrocarbons are discharged through line 22. A mixture of solvent, hydrocarbon components, and water is discharged through line 25 and valve 26 and enters low pressure flash tank 31 from which a mixture of additional methane and some heavier hydrocarbons is discharged through line 32. A mixture of solvent, remaining methane, ethane, heavier hydrocarbons, and water is discharged through line 35 and valve 36. Alternatively, the mixture can be sent through line 37 and valve 39 to join line 44 which is an alternative line from line 45 to vacuum flash tank 71.

It should be understood that the lower the solvent flow rate, the less C2 + hydrocarbons are removed from the inlet natural gas. It should be further understood that the more C2 + hydrocarbons are in the inlet natural gas, the less methane is extracted at a given solvent flow rate. Furthermore, the lower the flashing pressure, the more methane is removed in each flashing stage, However, the number of flashing stages that are used is generally a function of the inlet natural gas pressure. The reason therefor is that the higher the inlet pressure, the more stages can be used to create a smaller pressure drop between each stage and consequently a higher overall efficiency. If the inlet natural gas is, for example, at 8300 kPa, four flashing stages may be desirable. But if the inlet natural gas is at a low to moderate pressure such as 4100 Kpa, three flashing stages are adequate.In general, the smaller the pressure drop between flashing stages, the less the flashed amount of desirable hydrocarbons from the solvent and thereby the less recycle of the desirable components to the first extracting unit 11.

However, based on the economics of capital investment versus energy savings and the size of the facility, a single flashing stage may be effectively utilized to separate C1 + hydrocarbons from a liquid stream containing water and pjysical solvent. If the economics indicate that two flashing stages are optimum, both off-gas flashed streams may be sent to stripping unit 90 or, alternatively, the second flashed stream may be sent to stripping unit 90 while the first flashed stream may be sent either to first extraction unit 10 or to second extraction unit 1 50.

Solvent regeneration unit 50 comprises solvent regenerator 51, reboiler 59 with circulating line 54, overhead discharge line 52 and condenser 53, settler 61, waste water discharge line 68, water return line 65, pump 66, and hydrocarbon vapor return line 62 from settler 61 to either the vacuum flash tank 71 or the atmospheric flash tank 41 via line 63 and valve 69.

The feed to the solvent regenerator 50 can come from atmospheric flash tank 41 or vacuum flash tank 71 through line 45 and pump 46 or line 75 and pump 76, respectiely. Water-free solvent is discharged from regenerator 51 through line 55 and pump 56, cooled in cooler 57, and passed through valve 58 to first extractor 11 or to second extractor 151 via line 141 and valve 143. If the inlet natural gas entering the system through line 1 3 does not contain water, the solvent can bypass regenerator unit 50 through line 48 and valve 47, when valve 49 is closed, to join solvent return line 55- to first extractor 11 and second extractor 1 51.

As is apparent from Fig. 2, overhead streams in lines 22 and 32 can respectively bypass stripping unit 90 for direct recycle to extractor 11 through line 11 2 and valve 114 and line 111 and valve 11 3 via line 92. Alternatively, these streams in lines 22 and 32 can join line 42 for passing through cooler 74 and valve 103 to enter stripper 91. Before receiving streams in lines 22 and 32, however, line 42 has earlier received the atmospheric flash stream and, in some arrangements, the overhead vacuum flash stream in line 72.

Stripping unit 90 comprises stripper 91, reboiler 99, circulating line 98, overhead discharge line 92, bottoms discharge line 95, and pump 96. The temperature at the bottom of stripper 91 is controlled by providing heat through reboiler 99 and returning the heated bottom liquid through line 98 to stripper 91. The bottom liquid meets the product specifications as to undesirable components (such as methane, ethane, propane, butanes, CO2, H2S, and the like) and leaves the process through line 95 and pump 96 for pipeline shipments via valve 100, line 97, line 82, and line 84.

However, if acidic components have not previously been removed, liquid sweetening unit 80 is needed. Liquid sweetening unit 80 comprises a main contactor 81 and a desorbing unit 85. If a process arrangement does not require stripping unit 90, a liquid storage tank 77 is utilized.

The cooled stream in line 42 is fed through line 1 58 and valve 1 59 to storage tank 77 and then through line 78, pump 79, and valve 187 to main contactor 81. If a stripping unit 90 is utilized in the process, the sour liquids are fed from stripper 91 through line 95, pump 96, valve 89, and line 181 to line 78. Amines contactor 81 produces a sweet product, passing through valve 104 and line 82, which consists essentially of ethane plus heavier hydrocarbon liquids for pipeline shipment.

The identity of these heavier hydrocarbons depends upon previous demethanizing, deethanizing, depropanizing, or debutaizing treatment in the stripper. The sour amine stream in line 83 is desorbed in unit 85, providing a CO2 and H2S stream leaving through line 86 with negligible content of hydrocarbons. The sweet amines stream returns to contactor 81 through line 87. If the liquid product meets the required specifications without utilizing stripping unit 90 and the liquids are also sweet, the liquid product may bypass both stripping unit 90 and liquid sweetening unit 80 via line 84 and valve 88.

First extraction unit 10, medium pressure flash unit 20, low pressure flash unit 30, atmospheric flash unit 40, vacuum flash unit 70, and stripping unit 90, with recirculating lines for methane-rich streams in line 92, plus liquid sweetening unit 80 and solvent regenerator unit 50, are sufficient, with their accessory compressors, coolers, valves, and lines, to provide (a) sweet dry residue gas to a pipeline through line 1 2 and (b) C2 + liquids, C3 + liquids, C4 + liquids, or C5 + liquids through line 95, with C2, C3, C4 hydrocarbons of consecutive molecular weights being selectively rejected and discharged as a portion of the sweet, dry residue gas in line 12.However, when market prices change for individual hydrocarbons in liquid form, so that the market price for an individual hydrocarbon liquid falls below its fuel price, it becomes advantageous to be able to extract only those hydrocarbon liquids which are priced above their fuel value.

In order to make a selective extraction, second extractor unit 150, single flash unit 160, and splitting unit 1 70 are additionally needed. Extractor unit 1 50 receives a gaseous hydrocarbon stream in line 137 and a solvent stream passing through line 141 and valve 143 from line 55.

Methane or ethane leaves as an overhead stream in line 152, is compressed by compressor 153, and is cooled by heat exchanger 1 54 before passing through valve 1 56 and joining line 92 for recycle to first extractor 11 via line 28 and valve 24.

The flow system for selectively feeding the flashed-off gases and the stripper overhead to second extractor 151 comprises a collection line 137 which receives the contents of lines 138, 131, 101, and 121. Lines 138 and 131 are connected through valves 139 and 133, respectively, to line 92, the overhead discharge line from stripper 91, before and after compressor 93, respectively.

The flashed-off gases from medium pressure flash tank 21 have three paths to the next major process units, as follows: (1) to first extractor 11 through lines 22, 112, 92, and 28, (2) to second extractor 151 through lines 22, 121, 131, and 137, and (3) to stripper 91 through lines 22 and 42. The flashed-off gases from low pressure flash tank 31 also have three paths to the same process units, as follows: (1) to first extractor 11 through lines 32, 111, 92, and 28, (2) to second extractor 151 through lines 32, 101, 121, 131, and 137, and (3) to stripper 91 through lines 32 and 42. The flashed-off gases from atmospheric pressure flash tank 41 and from vacuum flash tank 71 have two paths to the next major process unit, as follows: to stripper 91 through line 42 (via line 72 for tank 71) and to liquid sweetener 81 through lines 42 and 158, storage tank 77, and line 78.

Line 32, the overhead discharge line from low pressure flash tank 31, is connected to line 101 through valve 102, upstream of compressor 33, and a valve 107, downstream of compressor 33. Line 32 has its own valve 34 and joins lines 22 and 42 for feeding to stripper 91.

Depending upon the operating pressure of second extracting unit 150, the gases from stream 92 may feed second extractor 151 via line 131. Line 131 has valve 133 and cooler 135 and discharges into line 127. Depending upon the operating pressures of tank 31 and second extractor 151, line 101 may be used to directly pass the gases from stream 32 to line 127 via line 108 having valve 109.

Line 22, the overhead discharge line from medium pressure flash tank 21, has a compressor 23 and is connected to line 115, having valve 117, upstream of compressor 23 and to line 121, having valve 123, downstream thereof. Line 22 is also connected to line 112, having valve 114, which discharges into line 92, upstream of cooler 94. Line 22 can also dischage into stripper 91.

Line 121 has additional valve 125 and discharges into line 131, upstream of cooler 135.

Bypass line 127, having valve 129, is connected to line 121, upstream of valve 125, and discharges into line 137. Bypass line 108, having valve 109, is connected to line 101, upstream of valve 106, and discharges into line 127.

The bottom stream in line 155, depending upon the rate of circulation of the solvent, comprises C2 + C3 hydrocarbon liquids or C2 + C3 + C4 hydrocarbon liquids which are fed to single flash tank 1 61 from which an overhead stream passes through line 162, compressor 163, and heat exchanger 164 to enter splitter 171. The bottom stream in line 165 is then pumped by pump 1 66 to solvent regenerator unit 50 through line 45.

The hydrocarbon stream in line 1 62 enters splitter 1 71 which is equipped with a reboiler 1 79 and a recirculating line 1 78 for heating the contents thereof. The overhead stream is ethane if the unit is being operated as a de-ethanizer or ethane plus propane if the unit is being operated as a depropanizer. The overhead products in line 1 72 are combined with products from line 95 to leave the process via line 84. Correspondingly, the bottoms stream in line 175, pumped by pump 176, consists of propane or propane plus butanes if the unit is being operated as a deethanizer or butane if the unit is being operated as a depropanizer.The hydrocarbon stream in line 1 75 passes through valve 1 77 to join line 1 2 containing residue natural gas. Line 1 73 and valve 1 74 may alternatively be used to recycle contents of line 1 75 to first extractor 11 via line 152.

Depending upon the recovery objectives, the recycle gases from the process in line 92 may bypass first extractor 11, via line 29 and valve 149, and go directly to residue gas line 1 2. The pipeline quality residue gas leaves the process only through line 1 9. If the primary objective is to produce a selected liquid product, the natural gas enters the process only through line 1 3, and its components leave only through line 84 as this liquid product, and the remaining components leave only through line 1 9 as residue natural gas. If, on the other hand, the primary objective is to produce a selected natural gas as product, the selected components leave as this gas product only through line 1 9 and the remaining components leave as residue liquid product only through line 84.

The flexibility of this treatment system for selectively extracting desired hydrocarbon components from an inlet natural gas stream, sweet or sour and having any water content up to saturation, with a physical solvent is illustrated in the following examples.

Example I Case I As shown in Figs. 1 and 2, an ethane recovery plant is put into operation to treat 100,000 normal cubic meters per day (100 kNm3D) of sweetened natural gas for 95% ethane recovery.

The composition of the natural gas entering extractor 11 of extractor unit 10 is as follows: Component MOL% Nitrogen 2.02 Methane 80.62 Ethane 9.69 Propane 4.83 Iso-Butane 0.50 N-Butane 1.45 Iso-Pentane 0.30 N-Pentane 0.37 Hexane Plus 0.22 100.00 Water Content 2.9 kgs/kNm3D inlet gas Inlet Pressure 4410 kPa Inlet Temperature 50"C In this example, the molar ratio of solvent to the fresh feed stream in line 1 3 is of the order of 1.36::1.00. Ethane and heavier liquids present in the inlet gas stream are selectively absorbed and removed from the first extractor through line 1 5. The remaining natural gas leaves the first extractor 11 through line 1 2 and is primarily composed of nitrogen, methane, and small amounts of ethane, depending upon the desirable recoveries of ethane. Virtually all of the propane and heavier components are removed from stream 1 3.

In order to remove methane from recovered hydrocarbons while conserving energy usage, the pressure in line 1 5 is let down in a plurality of sequential stages, such as from 4410 kPa to 2760 kPa in medium pressure flash tank 21, then to 2070 kPa in low pressure flash tank 31, and finally to 35 kPa in vacuum flash tank 71, whereby vapor streams 22, 32, 72 are separated from liquid streams 25, 35, 75. The vapor streams in lines 22, 32, 72 respectively contain about 88, 86, 40 MOL% methane.The vapor stream in line 22 contains about 30% less methane and about 94% of the ethane present in stream 1 5. The liquid stream in line 25 contain about 30% less methane and about 94% of the ethane present in line 1 5. The stream in line 32 contains about 51 % less methane than the amount of methane present in the stream in line 1 5.

The liquid stream in line 75 leaving vacuum flash tank 71 contains about 1.5 MOL% hydrocarbons and water, with the rest being solvent, and is pumped into solvent regenerator 51 where it is heated to about 150"C at about 1 38 kPa to completely remove water and is finally cooled to about 50"C in cooler 57.

The operation of the process as described in this example can be more clearly understood by studying the compositions of the various streajms in kg/-mols per hour. Eleven components of 15 streams are given in the following Tables Ill and IV.

TABLE III MATERIAL BALANCE FOR ILLUSTRATIVE EXAMPLE 1

Stream in Line No. 13 55 12 15 28 22 25 Components, Kg-Mols/Hr Nitrogen 3.75 -3.75 .19 .19 .12 .07 Methane 149.27 - 148.90 43.46 43.09 12.97 30.49 Ethane 17.93 - .91 20.40 3.37 1.27 19.13 Propane 8.94 - Trace 9.45 .51 .25 9.19 Iso-Butane .93 - - .96 .03 .02 .94 N-Butane 2.68 - - 2.75 .07 .03 2.72 Iso-Pentane .56 - - .56 - - .56 N-Pentane .69 - - .69 - - .69 Hexane Plus .49 - - .49 - - .49 Water .66 - - .66 - - .66 Solvent - 253.17 - 253.17 - - 253.17 TOTAL Kg-Mols/Hr 185.90 253.17 153.56 332.88 47.26 14.66 318.11 TABLE IV MATERIAL BALANCE FOR ILLUSTRATIVE EXAMPLE 1

Stream in Line No. 32 35 72 75 92 93 68 62 Components, Kg-Mols/Hr Nitrogen .03 .03 - - .03 - - Methane 9.10 21.40 21.40 .15 21.03 .37 - .15 Ethane 1.20 17.94 17.94 .74 .91 17.03 - .74 Propane .25 8.94 8.94 .86 Trace 8.94 - .86 Iso-Butane .02 .93 .93 .15 - .93 - .15 N-Butane .03 2.68 2.68 .52 - 2.68 - .52 Iso-Pentane - .56 .56 .17 - 56 - .17 N-Pentane - .69 .69 .25 - .89 - .25 Hexane Plus - .49 .49 .22 - .49 - .22 Water - .66 - .66 - - .66 Trace Solvent - 253.17 - 253.17 - - Trace TOTAL Kg-Mols/Hr 10.63 307.49 53.63 256.89 21.97 31.69 .66 3.06 If only propane plus heavier hydrocarbons are desired as a liquid product, such as for Case II, for example, up to 98% of ethane and about 1 % of propane entering the process through line 1 3 could leave the process via line 1 2 while easily recovering 99% of propane with about 2% of ethane from the stream in line 1 3 as components of the stream in line 95 containing 100% of the butanes and heavier hydrocarbons.These desirable recoveries can be achieved by changing the operating conditions, such that the solvent-to-fresh feed molar ratio would be significantly lowered to about 0.95, the pressure in the medium pressure tank would be around 1 725 kPa, and the low pressure tank would operate at about 1035 kPa, while the demethanizer would operate as a de-ethanizer at about 1 900 kPa.

Similarly, by changing the solvent flow rate to the first extractor, by changing the pressure in the subsequent flashing stages, and by adjusting the pressure and temperature in the demethanizing unit, propane or butanes could be rejected to any selected degree in order to produce C4 + or C5 + liquid products for Cases Ill or IV, respectively.

Example 2 Extraction of C2 and C4 + Liquids From Sweet Inlet Natural Gas and Rejection of Propane (Case V) The process, as described under Example 1, is operated quite similarly to remove C2 + hydrocarbons from the inlet natural gas, with the exception that only.the vapors from flash tank 21 are recycled directly to first extractor 11 via lines 112, 92, and 28. All other streams either flow directly to line 1 37 or via stripper 91, operating as a depropanizer, to line 1 37.

Line 137, entering second extractor 151, contains C1 + C2 + C3. The ratio of solvent flow, through line 141 and valve 143, to gas flow, through line 1 37, is sufficient that the overhead stream from second extractor 1 51 contains primarily methane with some ethane. This ratio varies from 0.14 to 28 cubic meters per thousand normal cubic meters.

The overhead stream from single flash tank 1 61 flows to splitter 171, operating as a deethanizer, wherein pressure and temperature are controlled by flow through recirculating line 1 78 and reboiler 1 79 so that ethane leaves as overhead through line 1 72 to join line 95 while propane leaves through line 1 75, pump 176, and valve 1 77 to join line 12. The combined liquid hydrocarbon product from lines 1 72 and 95 is therefore C2 and C4 + and leaves the process via lines 97 and 84 since the gases are sweet and the product meets specifications. The residue natural gas contains C1 and C3 and may be useful for dehydrogenation processing.

Example 3 Extraction of C2, C3, and C5 + Liquids From Sweet Inlet Natural Gas and Rejection of Butanes (Case VIJ The process is operated as in Example 2 except that stripper 91 is operated as a debutanizer, so the stream in line 92 consists of C1, C2, C3, and C4, the stream in line 1 52 consists of C1, and the stream in line 155 consists of C2, C3, and C4. Splitter 171 is operated as a depropanizer, so that the stream in line 1 75 consists of C4, and the stream in line 1 72 consists of C2 and C3, thereby augmenting the C5 + liquid product. The residue natural gas consists primarily of C and C4 and may be useful for dehydrogenation in addition to its fuel value.

Similarly, the conditions can be altered to produce other liquid hydrocarbon products and/or residue natural gases of different compositions, as outlined under Cases VII and VI II.

Even though only a few schematic arrangements have been illustrated and described hereinbefore, it should be recognized that the process steps are important and that they can be arranged in a multitude of combinations consistent with the operational objectives and given market conditions. The invention process is extremely flexible and cannot be limited to the schematic arrangements described in the examples or even as shown in the drawings.

It is very important to note that the high ethane plus heavier hydrocarbon recoveries are achieved by clean separation of components in stripping unit 90 and splitting unit 1 70 and by closing the loop around the process by means of recycling to the first extractor; as such, any C2 + components leaving in the overhead streams of medium, low, atmospheric, and vacuum flash tanks and in the stripper overhead get a second chance at recovery for all eight Cases I through VIII. When second extracting unit 150 is utilized for selective rejection of an intermediate component, the second extractor overhead in line 1 52 may contain desirable hydrocarbons which get a second chance at additional recovery by recycling to first extractor 11, thereby closing another loop, as in Cases V through VIII. This concept of recycle is one key factor that allows the achievement of unusually high recoveries. This second chance at recovery for desirable hydrocarbons, while simultaneously rejecting intermediate-boiling hydrocarbons, provides another degree of freedom in process design that is not available in any of the natural gas liquids extraction processes described earlier.

Another important feature that is novel to this invention is that the rich solvent leaving second extractor 151 in stream 155 does not contain more than the specification amounts of lighter undesirable hydrocarbons that are permitted in the final liquid product stream 84. Even though it is preferred to maximize recovery of desirable hydrocarbons at the bottom of second extractor 151 in line 155, it is perhaps more economical to recycle any unrecovered desirable heavier hydrocarbons to first extracting unit 10.for additional yield, while insuring that the lighter components present in the rich solvent stream 1 55 are within the specification for stream 84.

This result can be easily achieved by selecting the operating pressure of second extracting unit 1 50 and adjusting the solvent flow rate in line 141.

Another important element that is unique to this invention is the ability to select and set a pressure in each of the intermediate flashes from medium to vacuum tanks, based on economic objectives for a given stream. The pressures are chosen such that all undesirable components, after adjusting the solvent rate to first extractor 11 through line 55, are flashed off and directly recycled back to first extractor 11 or further processed in second extractor 1 51 while bypassing stripper 91 in order to recover desirable components in high yield. The feed-forward streams to stripper system 90 are composed primarily of desirable components for stream 95.

Selecting the pressure within stripper 91 and its bottoms temperature to obtain a primary separation of consecutively lower molecular weight hydrocarbons, plus a secondary separation second in extractor unit 150, followed by a tertiary separation between desirable and undesirable hydrocarbons through splitting unit 1 70 by similarly selecting its pressure and temperature, enables specific undesirable components to be selectively rejected, even though the rejected hydrocarbon or hydrocarbons are sandwiched between desirable components. Such desirable components are ethane, propane, butanes, or C5 + depending upon the existing market conditions.The operating pressure of stripping unit 90 can also be varied at will, consistent with the operational objectives, thereby operating the same equipment as a demethanizer if C2 ± product is desired, as a de-ethanizer if C3 + product is desired, as a depropanizer if C4 + product is desired, or as a debutanizer if C5 + product is desired. The operating pressure in stripping unit 90 can vary from 345 to 3100 kPa.

Similarly, splitting unit 1 70 is operated as a de-ethanizer or as a depropanizer. The pressure of unit 1 70 can also be varied at will. However, if ethane is to be rejected, such as for Case VII, it is simpler to do so with stripper 91 so that for most purposes splitter 1 71 must merely separate C3 from C4, as shown in Table II.

Another factor that allows unusually high hydrocarbon recoveries and an extremely flexible degree of component selectivity is essentially the recognition of relative gas solubility and loading capacity characteristics of the various physical solvents, such as DMPEG. Due to significant departures among the relative solubilities of ethane, propane, iso and normal butanes, iso and normal pentanes, hexane, heptane, etc., relative to methane, the desired hydrocarbons can be selectively recovered from a natural gas stream by adjusting the solvent flow rate to extractor units 10 and 150, recycling flashed gas mixtures to extractor 11, adjusting the operating pressure levels in intermediate flash units 20, 30, 40, 70, and adjusting temperature and pressure levels in stripping unit 90 and splitting unit 1 70.

Claims (27)

1. In a continuous process for extracting water and hydrocarbons heavier than methane (C, +) from an inlet natural gas stream with a physical solvent, an improvement which produces: (1) a liquid hydrocarbon product having a composition which is selectively adjustable to substantially any selected degree in accordance with market conditions or alternatively a liquid hydrocarbon byproduct containing remaining components and, (2) a residue natural gas stream comprising remaining components or alternatively a natural gas product of a selected composition and having a pipeline quality, said improved process comprising:: A. as a first extraction step, extracting said water and said hydrocarbons heavier than methane from said natural gas stream with said physical solvent at pipeline pressures and at a solvent flow rate sufficient to produce at least a portion of said residue natural gas stream of pipeline quality which is returned a pipeline, a rich solvent stream containing said water, said solvent, and a C, + mixture of hydrocabons, said solvent flow rate being selectively varied with respect to the flow rate and composition of said natural gas stream during said first extracting in order to adjust the composition of said rich solvent stream relative to selected components of the group consisting of ethane (C2), propane (C3), iso and normal butanes (C4), and pentanes and heavier hydrocabons (C5 + );; B. successively flashing said rich solvent stream in a plurality of flashing stages at successively decreasing pressures in order to produce a plurality of successive C, + gas fractions, having successively lower methane contents, and liquid mixtures of said water, said solvent, and mixtures of hydrocarbons having successively lower methane contents, the flashing pressures of said successive flashing stages being varied in order to adjust the compositions of said successive gas fractions and of said successive liquid mixtures relative to said selected components; C. regenerating the liquid mixture from at least the last stage of said flashing stages of said step B in order to produce said physical solvent for said first extracting;; D. recycling at least the first of said successive flashed C, + gas fractions to said first extracting in order to extract maximum quantities of said ethane and heavier hydrocarbon components (C2 + ); and E. stripping at least the last of said successive C, + gas fractions in order to produce at least a portion of said liquid hydrocarbon product comprising C2 +, C3 +, C4 +, or C5 + components and the remaining components forming an overhead gas stream, comprising C,. C1 + C2, Ca + C2 + C3, or C, + C2 + C3 + C4, which may be recycled to said extracting, by: 1) selectively varying the pressure of said stripping and/or 2) selectively varying the bottoms temperature of said stripping.

2. The process of claim 1 wherein, in response to market conditions, a further improvement enables, to any selected degree, at least one intermediate component, selected from the group consisting of said C3 and said C4, to be combined with said residue natural gas stream, said further improvement comprising:: A. as a second extracting step, extracting an extract feed stream, selected from said overhead gas stream and/or said successive C, + gas fractions of said step B, with said physical solvent at a selected flow rate that controls the selected degree of recovery of said selected C2 + components in a second rich solvent stream, the unextracted portion of said extract feed stream being recycled to said first extracting of said inlet natural gas stream in said step A of clam 1; B. flashing said second rich solvent stream and producing a singly flashed-off gas stream, containing said selected C2 + components, and a bottoms solvent stream which is recycled to said regenerating of said step C of claim 1; and C. splitting said singly flashed-off gas stream and producing an overhead product stream, selected from the group consisting of C2, C3, and C2 + C3, and a bottoms stream selected from the group consisting of C3, C4, and C3 + C4, said bottoms stream being combined with said residue natural gas stream of said step A of claim 1 and said overhead product stream being combined with said liquid hydrocarbon product of said Step E of claim 1.

3. The process of claim 2, wherein said inlet natural gas stream is selected from the group consisting of: A. natural gas saturated with water; B. natural gas at less than saturation with water; C. sour natural gas; D. sour natural gas which is pre-sweetened in gas phase with an aqueous amine solution; and E. sweet natural gas.

4. The process of claim 3, wherein said physical solvent is selective toward ethane and heavier hydrocarbon components of said inlet natural gas stream over methane, such that the relative volatility of methane over ethane is at least 5.0 and the hydrocarbon loading capacity, defined as solubility of ethane in solvent, is at least 1.77 normal cubic meters of ethane per cubic meter of solvent.

5. The process of claim 4, wherein said physical solvent is selected from the group consisting of dialkyl ethers of polyalkylene glycol, N-methyl pyrrolidone, dimethyl formamide, propylene carbonate, tetramethylsulfonate, glycerol triacetate, triethanolamine, tributyl phosphate, and gamma butyrolactone.

6. The process of claim 5, wherein said solvent is selected from the group consisting of dimethyl ether of polyethylene glycol, dimethyl ether of polypropylene glycol, dimethyl ether of tetramethylene glycol, and mixtures thereof.

7. The process of claim 6, wherein said solvent is dimethyl ether of polyethylene glycol containing 3-10 ethylene units and having a molecular weight of 146 to 476.

8. In a continuous process for extracting water and hydrocarbons heavier than methane (C, +) from an inlet natural gas stream, with a physical solvent, an improvement which produces: (1) a liquid hydrocarbon product having a composition which is selectively adjustable to substantially any selected degree in accordance with market conditions or alternatively a liquid hydrocarbon byproduct, and (2) a residue natural gas stream comprising remaining components or alternatively a natural gas product of a selected composition and having pipeline quality, said improved process comprising the following steps: : A. as a first extraction step, extracting said water and said hydrocarbons heavier than methane from said natural gas stream with said physical solvent at pipeline pressures and at a solvent flow rate sufficient to produce at least a portion of said residue natural gas stream of pipeline quality which is returned to a pipeline, a rich solvent stream containing said water, and a C, + mixture of hydrocarbons, said solvent flow rate being selectively varied with respect to the flow rate and composition of said natural gas stream during said first extracting in order to adjust the composition of said rich solvent stream relative to selected components of the group consisting of ethane (C2), propane (C3), iso and normal butanes (C4), and pentanes and heavier hydrocarbons (C5 + );; B. successively flashing said rich solvent stream in a plurality of flashing stages at successively decreasing pressures in order to produce a plurality of successive C1 + gas fractions, having successively lower methane contents, and liquid mixtures of said water, said solvent, and mixtures of hydrocarbons having successively lower methane contents, the flashing pressures of said successive flashing stages being varied in order to adjust the compositions of said successive gas fractions and of said successive liquid mixtures relative to said selected components; C. recycling at least the first of said successive flashed C, + gas fractions to said first extracting in order to extract maximum quantities of said ethane and heavier hydrocarbon components (C2 + );; D. stripping at least the last of said successive C, + gas fractions in order to produce at least a portion of said liquid hydrocarbon product comprising C2 +, C3 +, C4 +, or C5 + components and the remaining components forming an overhead gas stream comprising C1, C1 + C2, C1 + C2 + C3, or C, + C2 + C3 + C4, which may be recycled to said first extracting, by:: 1) selectively varying the pressure of said stripping and/or 2) selectively varying the bottoms temperature of said stripping; E. as a second extracting step, extracting an extract feed stream, selected from said overhead gas stream and/or said successive C, + gas fractions of said step B with said physical solvent at a selected flow rate that controls the selected C2 + components in a second rich solvent stream, the unextracted portion of said extract feed stream being recycled to said first extracting of said inlet natural gas stream in said step A; F. flashing said second rich solvent stream and producing a singly flashed-off gas stream, containing said selected C2 + components, and a bottoms solvent stream;; G. regenerating the liquid mixture from at least the last stage of said flashing stages of said step B and said bottoms solvent stream of said step F in order to produce said physical solvent for said first extracting and said second extracting; and H. splitting said singly flashed-off gas stream of said step F to produce an overhead product stream, selected from the group consisting of C2, C3, and C3 + C3, and a bottoms reject stream, selected from the group consisting of C3, C4, and C3 + C4, said bottoms stream being combined with said portion of said residue natural gas stream of said Step A to produce said residue natural gas stream or alternatively said natural gas product, and said overhead product stream being combined with said portion of said liquid hydrocarbon product of said Step D to produce said liquid hydrocarbon product or alternatively said liquid hydrocarbon byproduct.

9. The process of claim 8, wherein said inlet natural gas stream is selected from the group consisting of: A. natural gas saturated with water; B. natural gas at less than saturation with water; C. sour natural gas; D. sour natural gas which is pre-sweetened in gas phase with an aqueous amine-solution; and E. sweet natural gas.

10. The process of claim 9, wherein said physical solvent is selective toward ethane and heavier hydrocarbon components of said inlet natural gas stream over methane, such that the relative volatility of methane over ethane is at least 5.0 and the hydrocarbon loading capacity, defined as solubility of ethane in solvent, is at least 1 7.7 normal cubic meters of ethane per cubic meter of solvent.

11. The process of claim 10, wherein said physical solvent is selected from the group consisting of dialkyl ethers of polyalkylene glycol, N-methyl pyrrolidone, dimethyl formamide, propylene carbonate, tetramethylsulfone, glycerol triacetate, triethanolamine, tributyl phosphate, and gamma butyrolactone.

1 2. The process of claim 11, wherein said solvent is selected from the group consisting of dimethyl ether of polyethylene glycol, dimethyl ether of polypropylene glycol, dimethyl ether of tetramethylene glycol, and mixtures thereof.

1 3. The process of claim 12, wherein said solent is dimethyl ether of polyethylene glycol containing 3-10 ethylene units and having a molecular weight of 146 to 476.

1 4. A process for extracting selected hydrocarbons to any selected degree and at pipeline pressures from an inlet natural gas stream with a physical solvent, said process comprising: A. contacting an inlet natural gas stream with a physical solvent at a flow rate selected in relation to the flow rate of said gas stream to extract a residue natural gas stream as a first stream, and a solvent-rich stream comprising solvent, water, and a C, + mixture of hydrocarbons as a second stream; B. flashing said second stream to substantially atmospheric pressure to produce a C, + gas fraction as a third stream, and a liquid mixture comprising solent and water as a fourth stream;; C. compressing, cooling, condensing, and demethanizing said third stream to produce an off-gas stream consisting essentially of methane, and a liquid product stream comprising the remaining hydrocarbon components of said third stream; and D. regenerating said solvent-containing fourth stream and thereafter recycling regenerated solvent to contacting step A.

15. The process of claim 14, wherein said physical solvent is selective toward ethane and heavier hydrocarbon components of said inlet natural gas stream over methane such that the relative volatility of methane over ethane is at least 5.0 and the hydrocarbon loading capacity, defined as solubility of ethane in solvent, is at least 1.77 normal cubic meters of ethane per cubic meter of solvent.

1 6. The process of claim 15, wherein said physical solvent is selected from the group consisting of dialkyl ethers of polyalkylene glycol, N-methyl pyrrolidone, dimethyl formamide.

propylene carbonate, tetramethylsulfone, glycerol triacetate, triethanolamine, tributyl phosphate, and gamma butyrolactone.

1 7. The process of claim 16, wherein said solvent is selected from the group consisting of dimethyl ether of polyethylene glycol, dimethyl ether of polypropylene glycol, dimethyl ether of tetramethylene glycol, and mixtures thereof.

1 8. The process of claim 17, wherein said solvent is a dimethyl ether of polyethylene glycol containing 3-10 ethylene units and having a molecular weight of 146 to 476.

1 9. The process of claim 18, wherein said flashing of said step B is carried out in at least two stages to produce at least two C1 + gas fractions having successively decreasing methane content.

20. The process of claims 1 8 or 19, wherein said demethanizing is operated as deethanizing and said off-gas stream consists essentially of methane and ethane.

21. The process of claims 1 8 or 19, wherein said demethanizing is operated as depropanizing and said off-gas stream consists essentially of methane, ethane, and propane.

22. The process of claims 1 8 or 19, wherein said demethanizing is operated as debutanizing and said off-gas stream consists essentially of methane, ethane, propane, and butane.

23. A treatment process, substantially as hereinbefore described with reference to and as shown in the accompanying drawings.

24. A treatment process, substantially as described in Example 1.

25. A treatment process, substantially as described in Example 2.

26. A treatment process, substantially as described in Example 3.

27. Product(s) obtained by a process as claimed in any one of claims 1 to 26.