This invention relates to removing and recovering methane and higher boiling hydrocarbons from a natural gas stream which contains large quantities of inert gases, may contain acidic components such as C0 ₂ and H ₂ S, and may vary in moisture content from dry to saturated. It specifically relates to the upgrading of heating values of natural gas streams having heating values below desired specifications. It further relates to adapting the extractive flashing and extractive stripping versions of the Mehra Process for processing of nitrogen-rich natural gas streams.

Many hydrocarbon gases, such as natural gas, are contaminated with one or more inert gases which lower their heat content or otherwise impair their marketability. Such inert gases include nitrogen, helium, and argon.

During recent years, there has been strong emphasis on the secondary and tertiary methods of recovering oil from formations where the primary oil-producing methods are no longer productive. Nitrogen injection for reviving these oil wells is not useful in most formations, but in some formations such as in the central and north Texas areas of the United

States, nitrogen injection has been successfully utilized for the recovery of additional oil.

After several years of nitrogen injections at high pressure, approximately 14,000 Kpa, the nitrogen seems to have broken through the formations in many instances. In other words, nitrogen is coming out with the oil and it is separated from the oil at the separator. Previously, the associated gases were rich in hydrocarbons heavier than methane, along with substantial quantities of methane. The present dilution effect of nitrogen has caused the same associated wellhead gas to have an extremely low heat content, thereby making it unsuitable for pipeline shipments. If the natural gas contains more than 3% of nitrogen, it is off-specification for most of the world's pipelines. This situation has caused the oil-producer to curtail oil production because government regulations prevent him from burning the nitrogen-rich associated gas, and both environmental laws and a desire to preserve valuable resources prohibit him from venting the associated hydrocarbons. The oil producer is thus limited by the choice of technology available to him for properly processing the associated gases from an oil well. The prior art technology, which involves cryogenic principles, cannot economically process the natural gas streams which contain more than 3% nitrogen even after subsidization with the revenues from oil production.

Natural gas is a mixture of hydrocarbons, including, methane, ethane, propane, and various amounts of higher molecular weight hydrocarbons together with nitrogen and acid gases, such as CO-

and/or E S. A "dry" gas is one containing predominantly methane with some ethane, propane, and butane and having a very low hydrocarbon dew point. The heavier the hydrocarbons, such as pentane and higher homologs, that are present in the gas, the higher the hydrocarbon dew point. For pipeline transmission, enough of the heavier hydrocarbons must be removed to lower the dew point without losing too many of the calories needed to meet specifications. In the past, gases with large quantities of high molecular weight hydrocarbons have been passed through gasoline extraction plants and/or dew point control stations to lower the dew point. Also, frequently the gas has required conditioning to remove sulfur compounds and carbon dioxide.

Inability to change the composition of this liquid in accordance with market conditions has often been a handicap. The extractive flashing version of the Mehra Process, as described in U.S. Patents 4,421,535, 4,511,381, 4,526,594, and 4,578,094, has provided a solution for this problem.

The extractive flashing version of the Mehra Process comprises extracting a natural gas stream with a preferential physical solvent to produce a residue gas stream suitable for pipeline shipment, flashing the rich solvent, compressing, cooling, and condensing the C,-lean flashed gases, and stripping the condensed hydrocarbons. It provides selective recoveries of ethane in amounts ranging from 2-98%, propane in amounts ranging from 2-99%, butanes in amounts ranging from 2-100%, and pentanes and higher

molecular weight hydrocarbons in amounts ranging up to 100%. Under the heading, "New NGL Extraction Process", the extractive flashing version of the Mehra Process is described on pages 7 and 8 of the October 14, 1985 issue of the Gas Processors Report, P.O. Box 33002, Tulsa, Oklahoma 74153, United States of Ame ica.

A process that can remove an inert gas from an inert-rich natural gas stream is accordingly needed by oil producers who have been using nitrogen injection and by natural gas producers whose wells contain nitrogen, helium, and/or argon. In addition, there is a need for a process that can both produce an acceptable hydrocarbon gas product and a natural liquids product from an inert-rich hydrocarbon gas stream and selectively adjust the heat content of the gas product and the hydrocarbon contents of the liquids product in accordance with market economics. An example of pertinent market economics occurs 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. At such times, the operator of a natural gas liquids extraction plant, for example, is limited as to operating choice because he is unable to minimize ethane recovery and maximize propane recovery in response to market conditions.

Prior art processes for treating inert-rich natural gas and for extractive stripping of gas streams are disclosed in U.S. Patents 1,768,521;

2,237,386; 2,325,379; 2,357,028; 2,433,286; 2,455,803;

2,521,233; 2,559,519; 2,570,066; 2,596,785; 2,663,169 2,814,359; 3,097,924; 3,202,482; 3,255,572; 3,280,206 3,349,145; 3,455,116; 3,616,271; 4,158,556; 4,276,057 4,414,004; and 4,466,946. It is accordingly an object of this invention to provide a process for treating an inert-rich natural gas stream, including methane, that separates the inert gas from the hydrocarbon gases and then isolates methane from the remainder of the gases. A further object is to provide a means for processing a natural gas stream that is rich in one or more inert gases by utilizing a preferential physical solvent for selectively extracting ethane and heavier hydrocarbons from both methane and the inert gas and then again utilizing a preferential physical solvent for extracting methane from the inert gas, thereby forming three separate product streams.

An additional object is to extract C-+ hydrocarbons selectively in accordance with daily changing market conditions in order to provide a specification-grade inert gas product, a specification-grade hydrocarbon gas having a selected composition, and a hydrocarbon liquids product having a selected composition. It is another object to provide a process for treating an inert-rich natural gas stream with a preferential physical solvent in order to upgrade the specific heat value thereof.

It is also an object to recover desired hydrocarbon gas liquids from nitrogen-rich gas streams at minimum capital cost and minimum operating expense

while simultaneously producing specification grades of methane and nitrogen product streams.

These objectives are achieved, according to the principles of this invention, with a continuous process for treating an inert-rich natural gas stream containing more than 3 mole percent of an inert gas by contacting the gas stream with a stream of a preferential physical solvent and recovering a hydrocarbon gas product meeting desired inert-gas specifications. The contacting is at a solvent flow rate which is selectively varied from 0.1 to 70 cubic meters of solvent per thousand normal cubic meters of th.e natural gas stream. The solvent is selective toward ethane and heavier hydrocarbon components of the natural gas stream over methane ^' such that: ^"

1) the relative volatility of methane over ethane is at least 5.0 and the hydrocarbon loading capacity of the solvent, defined as solubility of ethane in solvent, is at least 1.77 normal cubic meters of ethane per cubic meter of solvent, or

2) its preferential factor, which is determined by the multiplication of relative volatility of methane over ethane by the solubility of ethane in solvent, in normal cubic meters of ethane per cubic meter of solvent, is at least 8.85.

However, the ideal preferential physical solvent would have a selectivity toward ethane over methane of at least 10.0 and would simultaneously possess a hydrocarbon loading capacity of at least 21.2 normal cubic meters of ethane per cubic meter of solvent, so that its preferential factor is at least

224. This combination of minimum relative volatility and minimum solubility enables solvent flow rate variations and operating pressure variations to be selectively utilized for flexibly producing liquid products having selected hydrocarbon compositions.

The inert gas in the inert-rich natural gas stream is nitrogen, helium, and/or argon, or mixtures thereof, the remainder being hydrocarbons. The inert-rich natural gas stream can also be sweet or sour, wet or dry. This process is also operable at the wellhead, whereby the natural gas product is suitable for pipeline shipment.

The contacting of the inert-rich natural gas stream with the physical solvent stream is at 1,500-9,100 Kpa absolute. The flow rate of the physical solvent stream is selectively adjusted in response to market conditions.

The inert-rich natural gas stream is selected from the group consisting of A. natural gas saturated with water;

B. natural gas at less than saturation with wate ;

C. sour natural gas;

D. sour natural gas which is pre-sweetened in gas phase with an aqueous amine solution; Ξ. sweet natural gas; and F. dry natural gas. This process has a selective capability for recovering, in addition to the hydrocarbon gas product:

A. an inert gas product and

B. a hydrocarbon liquids product having a selected composition that is selectively adjustable to substantially any selected degree in accordance with market conditions.

The hydrocarbon liquids product is consistent with the recovery capability of C,+ hydrocarbons from the inlet natural gas stream as follows:

1) specification amounts of methane, 2) ethane in amounts ranging from 2-98%,

3) propane in amounts ranging from 2-99%,

4) butanes in amounts ranging from 2-100%, and

5) pentanes and higher molecular weight hydrocarbons in amounts ranging up to

100%. This invention process produces a hydrocarbon liquids product having a composition which is selectively versatile rather than fixed, as in prior art processes. It should be understood, however, that this versatility is manifested in relation to a homologous series within the C,-C,-+ hydrocarbons. Specifically, when ethane, propane, or butane is selected as the key component whose recovery is to be controlled with the range of 2-98%, 2-99%, or 2-100%, respectively, the next lower-molecular weight hydrocarbon is always recovered in a lower percentage, and the next higher-molecular weight hydrocarbon is always recovered in a higher percentage. Only the key component can be selectively recovered.

In consequence, the composition of this hydrocarbon product can be readily adjusted in

accordance with market conditions so that profitability of the extraction operation can be maximized at all times and on short notice. Such versatility is achieved by flexibility in operating conditions and steps in both the extractive flashing (EF) and extractive stripping (ES) versions. Specifically, the operator must consider and selectively change or vary the flow rate of the preferential solvent with respect to the flow rate of the inert-rich hydrocarbon gas stream in both versions. The operator must additionally selectively vary the temperature at the bottom of the stripping section in the ES column in the extractive stripping version and in the stripping column of the EF version.

According to one variation, herein termed partial hydrocarbon extraction, that is useful in either version, the first gas-contacting step is employed for selective removal by extraction of all component materials except the inert gas and methane, plus minor quantities of ethane and propane that may be selectively left with the methane, according to the specification requirements for the hydrocarbon gas product, thereby selectively isolating an inert/C, + gas stream from the C_+ fraction. The remaining gas-contacting step is utilized for extraction of the C + hydrocarbons from the inert/C + gas stream to produce the hydrocarbon gas product and the inert gas product. The pressures of these extractions can vary between 1,500 Kpa and 9,100 Kpa absolute.

According to another variation, herein termed total hydrocarbon extraction, the first gas-contacting step is employed for separating substantially all hydrocarbons from the inert gas, thereby producing the inert gas product and a rich solvent stream which is regenerated to produce a stream of C,+ hydrocarbons and a lean solvent stream. The total hydrocarbon extraction stage is therefore considered to be a C. + extraction. The stream of C-.+ hydrocarbons is again extracted with a second preferential solvent stream to produce a residue gas stream (selectively, C, or l ^+C 2 ^{or C} l ^+C 2 ^+C 3' ^C 2 ^{and C} 3 ^be:* - ⁿ 9 present in minor quantities when economically feasible or if required by specifications for the hydrocarbon gas product) and a second rich solvent stream which is treated to separate the solvent from the extracted hydrocarbons (selectively, C ₂ +).

Extraction and separation, in combination, are accomplished by extractive flashing and extractive stripping versions of the Mehra Process. In extractive flashing, a hydrocarbon gas stream is continuously and countercurrently extracted with a stream of a preferential physical solvent to produce a residue gas stream meeting pipeline specifications and a rich solvent stream which is flashed to produce a stream of flashed-off gases which are compressed, cooled, and condensed and then stripped to remove low-molecular weight hydrocarbons which are recycled to the extracting step, and a hydrocarbon liquids product, such as natural gas liquids, having a selected composition.

Preferably, the flashing is conducted in at least two stages to produce a stream of C,-rich flashed gases, which are also recycled to the extracting step, and a stream of C,-lean flashed gases which are condensed to form the feed for the stripping step. The selected flashing pressures of the successive flashing stages may vary between 9,100 Kpa and 15 Kpa abs. The bottoms stream from the flashing step is regenerated to form the lean solvent for recycling to the extracting step.

The recycle solvent stream that is produced by flashing is split into a main solvent stream, containing less than 15 mole percent hydrocarbons, and a solvent slipstream which is regenerated to form a lean-and-dry solvent stream, which is lean with respect to C,+ hydrocarbons and dry with respect to water, for recycling to the extracting step. The lean-and-dry solvent stream contains less than 1 wt.% of water (equivalent to less than 118 kg of water per million normal cubic meters in the residue natural gas stream) and less than 1 volume % of C-.+ hydrocarbons. Stripping the condensed C-,-lean flashed gases produces a stream of C,-C. rejected gases, which are recycled to the extracting step, and the liquid product. The bottoms temperature of the stripping operation is varied between -18°C and 150°C. The stripping operation selectively demethanizes, de-ethanizes, depropanizes, or debutanizes the condensed natural gas liquids to produce a hydrocarbon liquids product having a composition which is selectively adjustable,

substantially to any selected degree, in response to market demands. It should be understood that the name given to the stripping operation (e.g., depropanizing) indicates that the lower-molecular weight hydrocarbons are removed along with the named hydrocarbon. For example, "depropanizing" signifies the removal of c ₁₊ c ₂₊ c ₃ .

When the inert-rich natural gas stream contains water and more than 2 mole percent of C-.+ hydrocarbons, it is preferably extracted in three stages to remove the water and produce the C ₂ + hydrocarbons as the hydrocarbon liquids product, such as natural gas liquids, and the hydrocarbon gas product, such as C,-rich gas product. More specifically, this wet, inert-rich natural gas ^" stream is extracted with a selected portion of the main solvent stream to produce a partially extracted hydrocarbon gas stream and a rich solvent stream containing the water and the C-+ hydrocarbons. Then the partially extracted hydrocarbon gas stream is extracted with a second selected portion of the main solvent stream and with a selected portion of the lean-and-dry solvent stream to produce the residue hydrocarbon gas stream and an enriched solvent stream. This enriched solvent stream may be added to the second portion of the main solvent stream for extracting the inert-rich natural gas stream containing more than 2 mole percent of C-+ hydrocarbons, whereby the rich solvent stream is produced. Then the rich solvent stream is flashed to produce the stream of C,-rich flashed gases, the

stream of C,-lean flashed gases, and a wet stripped solvent stream. Alternatively, the enriched solvent stream may be fed directly to the flashing operation. As another alternative, when the inert-rich natural gas stream contains C_+ hydrocarbons but is lean with respect to C ₅ + hydrocarbons, it may be extracted in a first stage with the physical solvent to remove the C_+ hydrocarbons and produce a residue hydrocarbon gas stream, primarily comprising the inert gas and methane, for final extracting in a second stage with a selected portion of the lean-and-dry solvent in sufficient quantity to produce the inert gas product and a rich solvent stream containing the hydrocarbon gas product. The inert gas is then injected into the ground, vented to the atmosphere, or utilized for any other purpose. The methane-rich solvent is flashed to a significantly lower pressure, sufficient to release the methane from the solvent. The solvent may then be sent to the regeneration operation, in whole or in part, or may be re-used, because of its dryness and leanness, for the extraction of the residue natural gas from the C-,+ extraction. When the dry stripped solvent stream from the second extraction contains less than 1 mole percent of C5+ hydrocarbons, it is split into a second solvent slipstream, which is regenerated to form a part of the lean-and-dry solvent stream, and a remaining portion which is selectively combined with the lean-and-dry solvent stream from the regenerating operation.

The solvent which is separated in the flashing stage from the C ₂ + extracting is partially regenerated, as the lean-and-dry solvent stream, in a solvent regenerator where any water, if present in the inlet gas stream, is discarded. The same solvent regenerator can serve both the C ₂ + and the C-+ extractions.

The C _~ + extraction operation may be single stage or dual stage, but the residual hydrocarbon gas meets pipeline specifications with respect to water content and acid gas content after even a single C ₂ + stage. Two-stage C ₂ + extraction, using a selectively lean-and-dry solvent for the second stage, is less expensive, however. The determining factor is generally the C__+ content of the inlet natural- gas stream; if greater than 2 mole %, two sequentially operated C ₂ + extraction stages are preferred.

Selectively rejecting methane (C,), methane plus ethane (C,+C ₂ ), methane plus ethane plus propane (C,-r-C ₂ +C.,) , or methane plus ethane plus propane plus butanes (C,+C ₂ -r-C-,+C ₄ ) takes place within the stripping column of the extractive flashing/stripping units of the extractive flashing version or within the extractive stripping units of the extractive stripping (ES) version. Depending upon the liquid product specifications and the inlet natural gas composition, the rejecting of undesirable hydrocarbons occurs in accordance with the temperatures at the bottom of the stripping column. Essentially, the stripping section of the ES column functions much like the demethanizing or stripping

step of the extractive flashing (EF) version but with different emphasis, because in the EF stripping, emphasis is placed on keeping undesired lighter hydrocarbons from coming down the column. In extractive stripping, however, emphasis is placed upon keeping the desired heavier components from continuing up the column and exiting as a part of the residue gas.

In contrast to extractive flashing, extractive stripping may or may not utilize a flashing step for separating C -rich gases from the rich solvent. Separating C-.+ hydrocarbons from the inert gas product by total hydrocarbon extraction requires no more than one extractive stripping (ES) column and a hydrocarbon product (HP) column, but separating the hydrocarbon gas product (generally, as the C,-rich product) from the C ₂ + hydrocarbons, as hydrocarbon liquids product, requires an additional extractive stripping column which must be preceded by a solvent regenerating column.

Both gas-contacting steps are performed in at least one Extractor-Stripper (ES) column on a hydrocarbon gas stream comprising an inert gas. Each ES column comprises an extraction section and a stripping section therebelow. The sections may be operated in separate columns if their gas and liquid streams are flow connected.

The hydrocarbon gas enters the ES column at the bottom of the extraction section and flows upwardly while countercurrently contacting lean preferential physical solvent which enters the top of

the extraction section. The contact takes place over mass transfer surfaces, such as packing or distillation trays. The solvent leaving the bottom of the extraction section is rich in methane and heavier C-+ hydrocarbons.

This downwardly flowing C, -rich solvent enters the stripping section of the ES column and continues to flow downwardly, while coming in contact with the upward-flowing stripped hydrocarbons from the reboiler at the bottom of the ES column. The stripped hydrocarbons consist primarily of undesired hydrocarbons, such as C. if the desired objective is recovery of C-+ hydrocarbons, or C,+C ₂ if the desired objective is the recovery of C-.+ hydroc&rbons, and so forth, depending upon the desired recovery objectives.

Separating C_+ hydrocarbons from a mixture of the inert gas and the methane (C, ) by partial hydrocarbon extraction requires one ES column plus a hydrocarbons product column to produce the hydrocarbon liquids product and to regenerate the solvent. Then the inert gas-and-methane mixture must be extracted with a preferential physical solvent in a second ES column. Its rich solvent may be regenerated in a flash vessel which also produces the hydrocarbon gas product (i.e., C, -rich gas product).

Alternatively, if economically desirable, the combined inert gas and methane stream leaving the

ES column can leave the process as a desired product for potential recycling to the natural gas field.

When two ES columns are used sequentially for extractive stripping of the inlet gas stream by partial or total hydrocarbon extraction, the- second ES column may be operated with a preferential physical solvent that differs from the preferential physical solvent used in the first column. Each solvent may flow in a closed cycle, so that there are two rich solvent streams. Alternatively, both ES columns may be operated with the same solvent.

The preferred process for using the same solvent in two ES columns is to operate the first ES column to obtain, as its bottoms, a solvent stream rich in C ₂ + hydrocarbons and to produce, as its overhead stream, a gas stream of inert gas plus methane which forms the feed for the bottom of the extraction section of the second column. Preferably, the second ES column is at a higher pressure than the first ES column, and the overhead gas stream from the first column is compressed to that higher pressure. The process can be operated with the solvent flowing sequentially through both columns or with the solvent flowing in a closed cycle for each column. In the latter situation, the closed cycles may be operated with different solvents.

In either situation, the second ES column is operated to produce the inert gas as the overhead stream and a C,+ -rich solvent stream as bottoms which may be flashed to the desired pressure to produce methane as overhead and a flashed solvent

stream which is returned to the top of the second ES column. The methane may pass through a power recovery turbine which may be axially connected to the compressor for the inert gas stream. As an alternative to two ES columns, a single ES column, having a top section and a bottom section which are separated by a gas flow-through dividing plate, also known as the chimney tray, can be built. The rich solvent from the bottom of the upper section is sent to a flash vessel. This vessel is operated at a selected pressure to produce the C,-rich gas product and a solvent stream which is pumped to the pressure of the bottom section and fed to its top, just beneath the dividing plate. In this arrangement, the bottom column operates essentially at the same pressure as the top section.

The rich solvent leaving the bottom of the single ES column is let down in pressure to a pressure level consistent with the operation of the hydrocarbon product (HP) column. This pressure level, which is always lower than the pressure level in the ES column, also obviates the need for a downstream compressor or pump. The rich solvent may be economically heated by heat exchanging before entering the HP column in order to lower the reboiler heat load and improve separation of hydrocarbons from the physical solvent.

The HP column is a typical fractionation-type column in which the selectively extracted hydrocarbons are separated from the preferential physical solvent. The desired

hydrocarbons are recovered from the top of the HP column while the hot, lean solvent is taken off from its bottom. The temperature at the bottom of the HP column is selected to ensure the recovery of all desirable hydrocarbons and is no higher than the boiling point of the physical solvent at the operating pressure. In order to minimize the loss of the physical solvent with the C,+ or C ₂ + hydrocarbons, the upper part of the column is refluxed with the condensed hydrocarbons.

In order to minimize energy consumption, the hot, lean physical solvent, leaving the bottom of the

HP column, is effectively utilized for heating the rich solvent feed to the HP column and for reboiling the ES column before returning to the top of the extraction section of the ES column as cool, lean preferential physical solvent.

When the solvent flows through a separate closed cycle for each ES column, the first ES column may be operated for partial hydrocarbon extraction to produce an overhead mixture of the inert gas and methane and a rich solvent containing a mixture of C ₂ + hydrocarbons. The second column, to which the overhead mixture from the first column is fed, may be operated to split the mixture into inert gas and methane.

As an alternative process when the solvent flows through a closed cycle for each ES column, the first ES column may be operated for total hydrocarbon extraction to isolate the inert' gas as overhead from the first column. The rich solvent contains the

C,+ hydrocarbons recovered as bottoms. It is fed to a hydrocarbon product column that regenerates the solvent as its bottoms and produces C,+ hydrocarbons as its overhead which is partially condensed. The condensate is returned to the product column as reflux. If desired, the C,+ hydrocarbons may leave the process as gas product.

The uncondensed gases are fed to the second ES column for extraction or extractive stripping with a lean solvent which may be a different solvent. The overhead is C, gas product, and the bottoms are rich solvent containing the C ₂ + hydrocarbons. The rich solvent is fed to a hydrocarbon product column that produces lean solvent as its bottoms and an overhead which is partially condensed. The condensate is returned to the column as reflux; the uncondensed gases, which may be condensed, if so desired, are the C ₂ + hydrocarbon liquids product. The C-. + hydrocarbons may alternatively be fed to a C ₂ + extractive flashing recovery plant, as disclosed in U.S. Patent 4,511,381, in U.S. Patent 4,526,594, and in U.S. Patent No. 4,578,094 which can be operated with a solvent recycling system. The solvent may be the same solvent as in the first system or a different solvent having desired preferential characteristics as to k-value and loading capacity.

It is important to note that in the process described so far for the extractive stripping version of the Mehra Process, there is no external recycle of any streams. Although extractive stripping is

generally described and is preferred for this invention, it is satisfactory to use extractive distillation as the unit operation by means of which the hydrocarbons are separated from the inert gas and from each other. Furthermore, this process has been essentially reduced to a two-step process. Thus, the capital requirements of this process are substantially reduced over the earlier version of the Mehra process, as described in U. S. Patents Nos. 4,421,535, 4,511,381, 4,526,594, and 4,578,094.

This two-step version of the Mehra Process necessitates that the rich solvent, leaving the bottom of the ES column in which desired hydrocarbon extraction is performed, contains only the specified amounts of the undesirable lighter components, such as C-, in C ₂ + products or N ₂ in C,+ products, in order to meet the hydrocarbon gas product specifications and/or the hydrocarbon liquid ^' s product specifications. In the extractive flashing version, such specifications have been effectively achieved by selective extraction, by selective flashing, by selective recycle of flashed streams, and by selecting the operating pressure and temperature at the bottom of the demethanizing or stripping step. In the extractive stripping version, such a purity requirement has been combined with selectivity in a single ES column. In this column, the selection capability of operating pressure is relatively unavailable because it is generally determined by the delivery pressure of the residue gas. Only temperature flexibility at the bottom of the column

is generally available for meeting the required specification as to undesirable components because the other flexibility of flow rate of preferential physical solvent to the ES column is effectively utilized in meeting the selective recovery levels of desired C,+ hydrocarbon components of the raw gas stream. However, if feasible, it is preferred to operate the ES column, at as low a pressure as economically practical since the process of this invention does not require unusually high pressures for extraction of desirable components.

However, the selective recovery of C ₂ + components may be controlled to some extent by variations in flow rates of lean preferential physical solvents within the extraction section of the ES column. Additional selectivity of this invention is provided by the reboiler and the stripping section in the bottom portion of the ES column. The selected reboiling temperature enables the column to produce the rich solvent stream, consisting essentially of only the economically desired hydrocarbons, and to reject the economically undesired hydrocarbons. Instead of a reboiler, a stripping stream of inert gas or methane may be utilized for selective rejection of the undesirable hydrocarbons.

The rejected undesirable hydrocarbon stream, flowing upwardly through the stripping section of the ES column, includes some of the desirable hydrocarbons, which have been boiled off from the rich solvent in the reboiler, as the stream flows

over the packing or trays of the ES column. The hydrocarbons leave the stripping section of the ES column and join the incoming raw gas stream to form a mixed gas stream which flows upwardly in the extraction section of the ES column, where lean physical solvent preferentially recovers any contained desired hydrocarbons according to mass transfer principles developed for distillation.

In summary, the extraction section of each ES column is used for extracting desired hydrocarbon components from the hydrocarbon gas stream to form an extracted liquid at the bottom of the ES column, and the stripping section of each ES column is used for rejecting the undesired components from the extracted liquid. Under certain operating conditions and for certain hydrocarbon liquids product specifications, it may become necessary to operate the ES column bottoms at temperatures high enough to become relatively energy inefficient. It may thus be economically viable and preferred to allow additional quantities of undesirable hydrocarbons to be present in the rich solvent leaving the bottom of the ES column. These contained undesirable hydrocarbons tend to lower the temperature at the bottom of the ES column and thus allow for an effective energy recovery loop composed of rich/lean solvent streams. In such a situation, the contained undesirable hydrocarbons can be effectively removed by providing a single-stage intermediate flashing vessel, operating at a pressure consistent with the operating pressure of the HP column. The separated

vapor stream contains all of the undesirable components along with some desirable hydrocarbons. If desired, this stream is compressed to the pressure levels consistent with the operating pressure of the ES column. The compressed vapors may be economically recycled to the ES column for additional recovery of desirable hydrocarbons or sent to the hydrocarbon gas product stream.

The operating pressure and the temperature conditions of the ES column can vary from 1,500 to 9,100 Kpa absolute and -18°C to 320°C, respectively, 2,200-4,200 Kpa abs. being a preferred operating pressure range for the first ES column and 2,900-6,300 Kpa abs. being a preferred operating pressure for the second ES column if utilized.-

Similarly, the operating pressure and temperature at the bottom of the HP column can vary from 200 to 3,600 Kpa abs. and 66° to 430°C, respectively. The preferred range of pressure for the HP column is 1,100 to 2,500 Kpa abs. The operating temperature at the top of the HP column is determined by the equilibrium conditions for the desired composition of the hydrocarbon liquid product that are consistent with the market conditions and the operating pressure of the column. The operating pressure of the HP column is selected such that the desired hydrocarbon can be condensed by reasonably available cooling media such as ambient air, cooling water, or warm level refrigerant. The bottoms temperature of the HP column is preferred to be equivalent to the boiling point of the physical solvent at the operating pressure in order to ensure maximum recovery of desirable hydrocarbons.

Returning to the preferential physical solvent, the relative volatility for methane with respect to ethane in the presence of dimethyl ether of polyethylene glycol (DMPEG) is 6.4, indicating that it is more selective toward ethane than many other absorption liquids. As other examples, N-methyl pyrrolidone (NMP) and dimethyl formamide (DMF) have relative volatilities of methane/ethane of 5.3 and 8.5, respectively. However, the solubility of hydrocarbons in NMP is 0.2 normal cubic meters per liquid cubic meter and in DMF is 0.28 normal cubic meters per liquid cubic meter; these values are low when compared to 7.0 normal cubic meters per liquid cubic meter for DMPEG. It is the combination of these factors that determines the effectiveness of physical solvents. In general, if a choice must be made, it is better to have a high relative volatility than a high solubility or loading factor, although high levels of both indicators are needed for really good performance in the Mehra Process.

Combined preferential factors are given in the following Table I for a common lean oil, NMP, DMF, esitylene, a hypothetical solvent having minimum requirements for Mehra Process applications, DMPEG, and a hypothetical ideal solvent in the Mehra Process. These preferential factors are important because they inversely indicate the amount of solvent which is required, in terms of solvent flow rate, for a given recovery level of desirable hydrocarbons. In other words, as 48 is much greater than 1.1, the amount of NMP required is approximately 40 times the amount of DMPEG required for the same performance.

TABLE I

Preferential Factors Defining Preferential

Physical Solvents for Mehra Process Applications

LEAN MESIT- MIN. FOR

SOLVENT NMP DMF OIL MIN. DMPEG YLENE IDEAL

Relative volatility

(α ) 5.3 8.5 2.5-4.8 6.0 6.4 6.9 10

Solubility, I m- ³ i/ /mm- ³ 5, V γ n 0.2 _ n 0.2 _ R8 1 l . Δ4--i7. n0 77. n0 77. n0 29.7 22 IO

- - 7 n σ.

Preferential factor

(α x γ) 1.1 2.4 3.5-34 42 45 205 220

Suitable preferential physical solvents include dialkyl ethers of polyalkylene glycol, N-methyl pyrrolidone, dimethyl formamide, propylene carbonate, sulfolane, glycol triacetate, and streams rich in C ₈ -C, _η aromatic compounds having methyl, ethyl, or propyl aliphatic groups and specifically constituting a sub-group consisting of mesitylene, n-propyl benzene, n-butyl benzene, o-xylene, m-xylene, p-xylene, and mixtures thereof, and aromatic streams rich in mixed xylenes, CQ alkylaromatics, and other C ₈ -C, _Q aromatics, rich being defined with respect to the solvent as more than 15% by weight of the aromatic compound. These compounds boil in the range of 130-220°C These compounds are stable at the process temperatures used in separating mixtures into useful fractions and/or components, such as in distillation, extractive stripping, and extractive distillation operations. Moreover, they are also hydrocarbons which can be left in the liquid products in trace amounts, without interfering with use of such products in gasoline, for example, so that purification of the liquid products is not needed.

Figure 1 is a schematic flow sheet illustrating an extractive flashing process, in which some of the unit operations are shown as block diagrams, comprising two extraction columns for an inert-rich hydrocarbon gas containing less than two

mole % of C_+ hydrocarbons, plus an additional extraction column for use as the initial stage when the inlet gas contains more than two mole % of C_+ hydrocarbons. Figure 2 is a schematic flow sheet for a two-column extractive stripping process in which a preferential physical solvent extracts C,+ hydrocarbons from a hydrocarbon gas containing an inert gas and then strips C-,+ hydrocarbons from the rich solvent while producing an inert gas product, such as ₂ , He ₂ , and the like, and a C,+ hydrocarbons gas product.

Figure 3 is a schematic flow sheet for an extractive stripping process in which the first column separates the inert gas and methane from the remainder of the hydrocarbon gas and the second ES column separates the inert gas from the methane.

Figure 4 is a schematic flow sheet showing the extractive stripping process in which the first ES column, as in Figure 2, separates the inert gas from all of the hydrocarbons and the second ES column separates the methane from the C ₂ + hydrocarbon gases.

Figure 5 is a schematic flow sheet illustrating an extractive stripping process in which the first ES column, as in Figure 3, separates the inert gas plus ^' the methane from the remaining hydrocarbons in the rich solvent. The second ES column separates the inert gas from the methane in its C,-rich solvent which is fed to a flash vessel and therein is flashed to separate the methane from the solvent which is pumped to the top of the first ES column.

Figure 6 is a partial schematic flow sheet showing the two ES columns in Figure 5 built as a single ES column having a top section and a bottom section which are separated by a gas flow-through plate.

With reference to the figures, it should be understood that pipelines are in fact being designated when streams are identified hereinafter and that streams are intended, if not stated, when materials are mentioned. Moreover, flow-control valves, temperature regulatory devices, pumps, and the like are to be understood as installed and operating in conventional relationships to the major items of equipment which are shown in the drawings and discussed hereinafter with reference to the continuously operating process of this invention. All of these valves, devices, and pumps, as well as heat exchangers, accumulators, condensers, and the like, are included in the term, "auxiliary equipment". The term, "absorber", is conventionally employed for a gas/solvent absorbing facility, but when it is utilized in the process of this invention with a preferential physical solvent, it is considered to be an "extractor" . The process shown schematically in Figure 1 is a partial hydrocarbon extraction process that comprises extraction units 10, 20, 30, a flashing unit 40 having at least one flashing stage, a stripping unit 50, a solvent regenerating unit 60, and a methane flashing unit 70, consisting of at least one flashing stage. Extraction units 10 and 20 are the C ₂ +

extraction stages, which may be combined in a single vessel but which are shown in the drawing as two vessels for illustrating their functions. These are a first vessel 11 and a second vessel 21. Referring to Figure 1, an inert-rich inlet gas stream in line 5, normally saturated with water but in some circumstances completely dry, enters extraction stage 10 or 20, depending upon its content of C-.+ hydrocarbons. This gas stream, which typically may be a sweetened natural gas, is joined by a stream of flashed gases in line 26, mostly C, through C.. If the C-.+ content of the natural gas stream in line 5 is greater than 2 mole %, extraction unit 10 may be included in the process by sending the N ₂ -rich inlet gas stream (including the gas in line 26) through line 14 to vessel 11; if the C ₅ + content is less than 2 mole %, stage 10 may be omitted from the process by sending the N_-rich gas stream through line 5 to vessel 21. EXAMPLE I

Inlet Gas Stream Containing More than 2 Mol % C--+

The inert-rich hydrocarbon gas stream in line 5, containing at least 3 mole % of inert gas and more than 2 mole % C-.+, enters the bottom of first extraction stage vessel 11 through line 14. A main solvent stream in line 13, containing less than 15 mole % C-.+ hydrocarbons, enters the top of vessel 11 and may be augmented by enriched solvent entering the top of vessel 11 through line 28. The solvent flows downwardly and countercurrently to the upwardly flowing gas. A stream of rich solvent in line 17

leaves the bottom of vessel 11 to enter flashing unit 40.

The partially extracted hydrocarbon gas leaves the top of vessel 11 through line 15 and enters the bottom of the second extraction stage in vessel

21. A stream of lean-and-dry solvent, containing less than 1 wt.% of water and less than 1 volume % of C-.+ hydrocarbons, enters the top of vessel 21 through line 23 and flows downwardly, countercurrently to the upwardly flowing gas, until it departs as enriched solvent through line 27 and either bypasses vessel 11 to enter flashing unit 40 or selectively enters the top of vessel 11 through line 28. The residue hydrocarbon gas, in equilibrium with the lean-and-dry solvent in line 23, leaves vessel 21 through line 25; it is very dry with respect to water and very lean with respect to C_+ hydrocarbons, depending upon the economically desired composition of the liquid product, but it contains nearly all of the methane and nitrogen in stream 5.

The enriched solvent in line 17 plus the rich solvent in line 27, if so directed, are flashed in flashing unit 40 in at least one stage and to at least an intermediate pressure. If a single stage is used, all flashed gases are sent to stripping unit 50. If two flashing stages are employed, the first stage releases C,-rich flashed gases which leave unit 40 through line 44 and are recycled to inlet gas line 5 via line 26 and a compressor. The second flashing stage releases C, -lean flashed gases which pass through line 45, another compressor, and a condenser for further treatment in stripping unit 50.

Stripping unit 50 may be operated as a de ethanizer, a de-ethanizer, a depropanizer, or a debutanizer, respectively removing all or selected portions of C-^, C,+C ₂ , C ₁ +C ₂ +C ₃ , or c ₁ +C ₂ -(-C ₃ -(-C ₄ hydrocarbons as overhead.

Stripping unit 50 comprises at least a stripping column, a recirculating line, and a reboiler. The selected C,-C. gases are removed from the incoming liquid in the stripping column and pass through line 55 and a compressor to join line 26 and ultimately line 5, whereby all or a portion of the C-,-C ₄ gases become a part of the inlet gas stream. Selected C ₂ -Cc+ natural gas liquids leave as liquid product through line 57. A stream of solvent, which has been stripped of C- _j + hydrocarbons and contains water and ho more than 15 mole % Ce+ hydrocarbons, leaves flashing unit 40 through line 47. After removal of a slipstream A thereof through line 49, the remainder, as the main solvent stream, flows through line 13 to enter the top of vessel 11 or through line 13A to join line 23 and enter the top of vessel 21.

Slipstream A in line 49 enters solvent regenerating unit 60, wherein circulation through a reboiler distills water and hydrocarbons from the solvent to form a condensed overhead stream containing both waste water and C-.+ hydrocarbons. These are separated by decantation. A stream of waste water leaves through line 65, and a trace stream of hydrocarbons also leaves solvent regenerating unit 60 through line 64 to enter stripping unit 50. The

v

lean-and-dry solvent produced by solvent regenerating unit 60 passes through lines 67 and 68 and a cooler to enter the second C ₂ + extracting stage 20 in vessel 21 through line 23 and the C-. extracting stage 30 in vessel 31 through line 69.

The process shown in Figure 1 and described hereinbefore is primarily designed for removing all of the Cc+ hydrocarbons in second C ₂ + extracting stage 20 and for removing major portions of water and C ₂ + hydrocarbons in first C ₂ + extracting stage 10. The respective volumes of the main and lean solvent streams for these two stages are determined by the respective quantities of water, C ₂ -C. hydrocarbons, C-.+ hydrocarbons, the loading capacities of the solvent for the hydrocarbons to be extracted, and relative solubilities in the solvent of the C_+ hydrocarbons with respect to methane.

The residue gas stream in line 25 still contains essentially all of the inlet nitrogen as it enters vessel 31 of C, extracting unit 30, while a lean-and-dry solvent stream in line 69 enters the top of vessel 31 to flow downwardly and countercurrently to the upward flow of the gas. The quantity of the solvent flow in line 69 is sufficient to extract substantially all of the methane and relatively little of the nitrogen.

Residual nitrogen leaves the top of unit 30 through line 35. It is at a pressure not far below its inlet pressure and can readily be compressed by a compressor and injected into the ground through suitable injection wells. Alternatively, if

economically justifiable, the nitrogen stream can be passed through a gas expansion turbine for power recovery before venting to the atmosphere.

The methane-rich solvent leaves extraction unit 30 through line 37 to enter flashing stage 70 wherein the pressure is reduced substantially to a level where all dissolved components are released in at least one flashing stage. Methane is released through line 75 as methane-rich gas product. Its pressure may be increased by a compressor, and the pressurized methane is discharged to a pipeline while meeting its pipeline specifications. However, in the event that it is economically beneficial to enrich the methane stream in line 75 with higher-molecular weight hydrocarbons, all or a portion of the flashed-off gases in line 55 can be diverted through line 56 to join line 75.

The stripped solvent leaves flashing stage 70 through line 77. If it is sufficiently lean that it will avidly absorb the methane and contains less than 1 vol. % of C _ς + hydrocarbons, all or a portion of the solvent stream in line 77 can be recycled to join the freshly regenerated solvent in line 67, if any is needed, for forming the lean-and-dry solvent feed stream in line 68 which is used for extraction units 20 and 30. The remaining solvent, if any, moves through line 79 as a slipstream B to join solvent slipstream A in line 49 that is to be regenerated in solvent regenerating unit 60.

EXAMPLE 2 Inlet Gas Stream Containing Less Than 2 Mol % C ₅ + It naturally follows that if the inlet inert-rich hydrocarbon gas stream is reasonably lean 5 with respect to C-.+ hydrocarbons, first extraction stage 10 can be omitted from the process. The hydrocarbon gas then flows from line 5 into vessel 21, wherein the main solvent stream that enters vessel 21 through line 23 via line 13A removes whatever C ₂ + τ_0 hydrocarbons that are present in the upwardly flowing gas in addition to the water and acidic impurities that are in the gas. Lines 13, 14, 15, 17, and 28, servicing vessel 11, become inoperative. The stripped gas that then enters vessel 31 through line 25

■ _] _5 contains essentially nothing but nitrogen and methane plus minor quantities of undesirable components. Flashing in flashing units 40, 70, stripping in unit ^' 50, and regenerating in unit 60 are then carried out in a similar manner, as described in Example 1.

20 However, if the content of heavier hydrocarbons in N ₂ -rich natural gas streams, for example, within line 5 is such that it is economically preferable not to extract these heavier hydrocarbons, the inlet natural gas stream can directly enter the

25 extracting vessel 31 via line 5a. Thus, all the heavier hydrocarbons would be extracted along with the methane from the N ₂ ~rich stream and would leave vessel 31 with the physical solvent in line 37 and form a combined hydrocarbon/gas product stream, rich

30 in methane, that would leave the process via line 75 after having been stripped from the solvent by flashing.

Any pressure drop and any number of flashing stages can be utilized, but it is preferred that at least two flashing stages be used in order to increase flashing efficiency and especially to be able to isolate and recycle to the extractor the stream of C,-rich flashed gases without having to additionally compress and condense these gases and then pass them through the de ethanizer. Flashing the enriched solvent stream in line 27, the rich solvent stream in' line 17, or a mixture of these solvent streams to approximately atmospheric pressure in at least two stages provides optimum efficiency for this improved Mehra process.

Nevertheless, there are some small plants which have insufficient throughput, such as approximately 28,000 cubic meters of raw natural gas per day, to justify a compressor for the C,-rich flashed gases. For such small plants, it is economically preferable to use a single flashing stage 40 which produces a single flashed gas stream 45 of C_+ hydrocarbons (plus possibly substantial amounts of methane) for feeding to the demethanizer. This modification of the Mehra process imposes a heavier load on demethanizer 50 and necessitates higher operating costs for demethanizing, but it saves on capital expenditures.

The pressure drop in the single flashing stage should reduce the pressure from wellhead or line pressure of up to 9,000 Kpa to a pressure as low as 15 Kpa abs., but the exemplary terminal pressure after flashing may be 700 Kpa abs., 400 Kpa abs., atmospheric

pressure, or, rarely, a vacuum, depending upon plant conditions which may include piggy-back utilization of existing plant equipment. In contrast, plants having a very large throughput may utilize as many as eight flashing stages, having a ratio of absolute pressure for successive flashing stages of at least 2.0, in order to minimize energy consumption.

Whether the inlet nitrogen-rich hydrocarbon gas stream, for example, is sweet or sour, the C- _j -lean flashed gases must be treated to prevent hydrate formation if they are to be condensed and the natural gas liquids are to be retrieved as a product. A preferred method for preventing hydrate formation is to inject methanol into the C,-lean flashed gases, preferably before the condensing step and definitely before the hydrate formation temperature is reached.

If, however, the hydrocarbon gas liquids are to be left in gaseous form with a major absorbed component* e.g., methane, as is often necessary for plants located in isolated areas or with quite small throughputs, such treatment to prevent hydrate formation is not necessary. Further, if the nitrogen-rich inlet hydrocarbon gas stream is dry, from a water-content standpoint, and if hydrocarbon gas liquids are desired as a product, methanol injection will not be needed to prevent hydrate formation but may be needed to remove traces of solvent in order to meet specifications for gumming compounds in the hydrocarbon gas liquids leaving the process through line 57.

If the nitrogen-rich gas stream in line 5 contains both C-+ hydrocarbons and acidic compounds such as C0 ₂ and H ₂ S, the acidic compounds will be extracted with the hydrocarbons and released from flashing unit 40 with the selected hydrocarbon gas liquids that are discharged as product through line 57. In order for these liquids to meet product specifications, they must then be sent through line 59 to a liquid sweetening unit 80 which removes the acidic compounds and produces a sweetened hydrocarbon gas liquid product discharged through line 82.

If an acidic inert-rich gas stream is lean in C ₂ + hydrocarbons, it is preferably sweetened before entering line 5. Alternatively, however, it may flow through line 5a to join line 25 and enter C, extracting vessel 31, wherein C-,+ hydrocarbons, the acidic compounds, and water are removed by a sufficient volume of adequately lean-and-dry solvent in line 69, thereby releasing the inert gas through line 35. The acidic compounds remain with the solvent and C,+ hydrocarbons in line 37 and continue to remain with the C,-rich gas product in line 75. If this necessarily gaseous product is to be sold as a sweet gas, it must then pass through line 79 to a gas phase aqueous amine treating unit 90 for discharge through line 92.

As shown in Figures 2-6, the extractive stripping embodiment of this invention for selective extraction of hydrocarbon liquids from an inert-rich hydrocarbon gas stream, as exemplified by the extraction of natural gas liquids from a stream of

dried and sweetened raw natural gas containing nitrogen, comprises combined extraction and stripping within at least one Extractor-Stripper (ES) column to form a rich solvent and a residue gas. Both total and partial hydrocarbon extraction are illustrated in Figures 2-6.

If the former, the residue gas is the inert gas product, the rich solvent as C ₂ + liquid product and lean solvent for recycling, and the hydrocarbon gas overhead stream may again be extractively stripped to produce the hydrocarbon gas product (typically identified as C, gas product) and rich solvent which is distilled to produce the hydrocarbon gas liquids. If the latter, the rich solvent is distilled to produce C ₂ + liquid product, lean solvent for recycling, and the residue gas is again extractively stripped to produce the inert gas product and rich solvent which is distilled to produce the C, gas product. As specifically shown in Figure 2, the basic process for separation of inert gases (such as nitrogen) utilizes an Extractor-Stripper (ES) column assembly 110 and a hydrocarbon product column assembly 120. This process utilizes total hydrocarbon extraction. ES column assembly 110 comprises an ES column 112, a reboiler 116, a rich/lean solvent exchanger 117, and a solvent cooler 119. By definition, an extraction section of ES column 112 extends upwardly from the connection with line 111, and a stripping section extends downwardly therefrom.

A raw and sweetened inlet inert-rich hydrocarbon gas is fed into ES column 112 slightly below its middle through line 111. The liquid at the bottom of column 112 circulates through line 115 and is heated in reboiler 116. Hot, lean solvent, which has been partly cooled in heat exchanger 117, passes through line 118 and reboiler 116 to heat the liquid in line 115, is cooled in solvent cooler 119, and enters the top of ES column 112. An overhead stream, containing nitrogen, for example, as the inert gas, leaves the top of column 112 through line 114. Rich solvent leaves the bottom of column 112 through line 113 and comprises solvent plus C,+ hydrocarbons.

This stream passes through rich/lean solvent exchanger 117 and enters column 122 slightly below its middle through line 121. Liquid in the bottom of column 122 is heated by circulating through line 125 and reboiler 126 and returns to column 122. Liquid bottoms leave column 122 through line 123 and pump 127 to be cooled in exchanger 117.

An overhead vapor stream in line 124 is condensed in condenser 131 and is fed to reflux accumulator 132 from which condensed liquid leaves through line 133 and is returned as reflux by reflux pump 137 to the top of column 122. Uncondensed hydrocarbon gases leave reflux accumulator 132 through line 134 and are compressed by compressor 135 to form the C,+ hydrocarbons gas product.

Alternatively, complete condensation of hydrocarbon vapors in condenser 131 is feasible, but use of energy is optimized by partial condensation.

At the operating pressure, the low boiling (C +C )

_-_ -J portion of the hydrocarbon vapors in line 124 determine what the condensation temperature will be. The more C ₂ it is desired to recover, the lower the condensation temperature must be.

Figure 3 shows an inert gas separation process that is more complicated and more selective than the process of Figure 2. The process of Figure ^' 3 utilizes first ES column assembly 140, hydrocarbon product column assembly 150, second ES column assembly 170, and methane product stripper assembly 180. This process utilizes partial hydrocarbon extraction in its first extraction stage.

An inert-rich hydrocarbon gas, which has been sweetened and dried, enters column 142 slightly below its middle through line 141. Liquid at the bottom of column 142 circulates through line 145 and reboiler

146 to be heated. Hot, lean solvent, which has been cooled in rich/lean solvent exchanger 147, passed through line 148, cooled in reboiler 146, and cooled again in solvent cooler 149, enters the top of first ES column 142 to flow downwardly and countercurrently to the rising inlet raw gas. Bottoms leave the column through line 143 and are heated in rich/lean solvent exchanger 147. An overhead gas mixture of inert gas and methane leaves the top of column 142 through line 144.

The rich solvent heated in solvent exchanger

147 passes through line 151 to column 152 wherein the vapors rise through the rectification portion of this column, countercurrently to refluxed hydrocarbons fed

to the top of the column. Liquid in the bottom of column 152 circulates through line 155 and reboiler 156. Bottoms in column 152 move through line 153 and solvent circulation pump 157 to rich/lean solvent exchanger 147 and then into line 148. An overhead stream of light hydrocarbons leaves the top of column 152 through line 154, is partially condensed in condenser 161, accumulates in reflux accumulator 162, and is split into a liquid fraction and a vapor fraction. The liquid fraction leaves the bottom of reflux accumulator 162 through line 163 and pump 167 to return to the top of column 152 as reflux. Uncondensed hydrocarbons (the vapor fraction), which entered through line 154 with the condensed hydrocarbons, leave accumulator 162 through line 164 and pass through condenser 165 to become C-+ liquid hydrocarbon product.

The overhead stream of nitrogen and methane in line 144 enters second ES column 172, slightly below its middle, to flow upwardly in countercurrent contact with a stream of lean solvent in its extraction section. Liquid in the bottom of column 172 circulates through line 175 and reboiler 176 to be heated. A stream of solvent and methane leaves the bottom of column 172 through line 173 to enter solvent exchanger 177 to be heated. Cooled lean solvent from this exchanger passes through line 178 and solvent cooler 179 to enter the top of column 172. Overhead from column 172 leaves through line 174, passes through optional turbine compressor 171, and becomes the inert gas product.

The heated rich solvent leaves solvent exchanger 177 through line 181 to enter column 182, and liquid in the bottom of column 182 circulates through line 185 and reboiler 186 to be heated. Bottoms in column 182 leave through line 183 and solvent circulation pump 187 to enter solvent exchanger 177 and line 178, to be further cooled in solvent cooler 179 and enter the top of second ES column 172 as lean solvent. The gas flashed or stripped within column 182 from the incoming liquid in line 181 leaves as overhead through line 184 and optional compressor 188 to become C, gas product.

Figure 4 illustrates a two-column process for total first-stage hydrocarbon extraction, in which there is initial separation of the inert gas from all of the hydrocarbon components within the first ES column, as in the process of Figure 2. This process utilizes a first ES column assembly 190, a solvent regenerator assembly 200, a second ES column assembly 210, and a hydrocarbon product column assembly 220.

Sweet, dry, inert-rich hydrocarbon gas enters column 192, slightly below the middle, through line 191. Liquid in the bottom of column 192 circulates through line 195 and reboiler 196 to be heated. Bottoms in column 192 leave through line 193 and solvent exchanger 197. Overhead from column 192 leaves through line 194 as inert gas product.

The heated rich solvent in exchanger 197 passes through line 201 to enter column 202, slightly below its middle. Liquid in the bottom of column 202 circulates through line 205 and reboiler 206 to be

heated. Bottoms from column 202 leave through line 203 and pump 207 to enter heat exchanger 197 and pass through line 198, reboiler 196, and solvent cooler 199 to enter the top of first ES column 192 as lean solvent.

An overhead stream leaves column 202 through line 204, is cooled in reflux condenser 204a, enters accumulator 208, and separates into uncondensed and condensed hydrocarbons. The latter leave through line 209a, are pumped by reflux pump 209 to the pressure of column 202, and enter the top of column 202. The uncondensed hydrocarbons leave accumulator 208 through line 211 to enter column 212, slightly below its middle. Liquid in the bottom of column 212 circulates through line 215 and reboiler 216 to be heated.

Bottoms leave column 212 through line 213 to enter rich/lean solvent exchanger 217 for heating therein. An overhead stream of C-, gas product leaves the top of column 212 through line 214. Heated solvent leaves exchanger 217 through line 221 and enters column 222, slightly below its middle. Liquid in the bottom of column 222 circulates through line 225 and reboiler 226 to be heated. Bottoms leave column 222 through line 223, are cooled in exchanger 217, pass through line 218 and reboiler 216, and are further cooled in solvent cooler 219 before entering the top of ES column 212. An overhead stream leaves the top of column 222 through line 224 and is partially condensed in condenser 231 before entering reflux accumulator 232. Condensed liquid in accumulator 232 leaves through line 233 and is pumped

by reflux pump 237 to the top of column 222. Uncondensed hydrocarbons in reflux accumulator 232 leave through line 234 to become C ₂ + hydrocarbons product. Figure 5 illustrates an inert gas separation process for an inert gas-containing gas which has been sweetened and dried. The process utilizes a first or bottom ES column assembly 240, a second or top ES column assembly 250, a flash vessel assembly 260, and a hydrocarbon product column assembly 270.

The inlet gas stream in line 241 enters column 242, slightly below its middle, and passes upwardly to meet downwardly descending lean solvent. Liquid in the bottom of column 242 circulates through line 245 and reboiler 246 to be heated. Bottoms in column 242 leave through line 243 to enter and be heated in rich/lean solvent exchanger 247. An overhead stream in line 244 leaves the top of column 242, passes through optional compressor 255 and line 251, and enters column 252, slightly below its middle.

Bottoms leave column 252 through line 253 to enter flash vessel 262, wherein the bottoms are separated into a C-, gas product, which leaves vessel 262 through overhead line 264, and a bottoms which leaves column 262 through line 263 and solvent pump 267 before entering the top of column 242. An overhead stream leaves the top of column 252 through line 254 and passes through optional power recovery turbine 256 to leave as inert gas product. Hot lean solvent leaves exchanger 247 through line 248, passes

through reboiler 246, is cooled in solvent cooler 249, and enters the top of column 252.

Heated rich solvent leaves exchanger 247 through line 271 and enters column 272, slightly below its middle. Liquid in the bottom thereof circulates through line 275 and reboiler 276 to be heated. Bottoms leave column 272 through line 273 and are cooled in exchanger 247. An overhead stream leaves through line 274, is condensed by condenser 281, and enters reflux accumulator 282, wherein it is separated into liquid and vapor portions. The liquid portion leaves through line 283 and is pumped by reflux pump 287 to enter the top of column 272. The vapor portion leaves through line 284 to become C ₂ + hydrocarbon product.

Figure 6 illustrates an alternative embodiment for the two ES columns shown in Figure 5. These columns are shown to be joined as a single column having a top section and a bottom section. The alternative embodiment comprises two-sectioned column assembly 290 and flash vessel assembly 300. Column assembly 290 comprises column 292 having a top section 292a, a bottom section 292b, and a reboiler 296.

An inert gas-containing raw inlet gas, which has been sweetened and dried, enters the stripping section of bottom section 292b through line 291. Liquid in the bottom of section 292b circulates and is heated by passing through line 295 and reboiler 296. Rich solvent, as bottoms in section 292b, leaves through line 293 to become rich solvent for downstream processing, as in Figure 5. Rich solvent, as bottoms

in top section 292a, leaves through line 299 to enter flash vessel 302 in which it is separated into a C-. gas product which leaves through line 304 and bottoms which leave through line 303 and solvent pump 307 to enter the top of bottom section 292b. Lean solvent enters the top of top section 292a through line 298. An overhead stream of inert gas product leaves the top of top section 292a through line 294.