Process and system for recovering natural gas liquids (NGL) from flare gas using joule-thomson (J-T) cooling and membrane separation

Abstract

A process and system for recovering natural gas liquids (NGL) using a combination of J-T cooling and membrane separation. The process involves compressing, separating, and cooling a flare gas stream comprising at least methane and C.sub.3+ hydrocarbons prior to being introduced to a J-T valve. The cooled stream exiting the J-T valve is further separated, producing a NGL product stream and an uncondensed gas stream. The uncondensed gas stream is directed to a membrane separation step, which results in a C.sub.3+ hydrocarbon enriched stream and a C.sub.3+ hydrocarbon depleted stream. The C.sub.3+ hydrocarbon enriched stream may be recycled back to the process to recover more NGL.

Claims

1. A process for treating a flare gas stream, the flare gas stream comprising at least methane and C.sub.3+ hydrocarbons, and the process comprising the following steps: (a) compressing the flare gas stream with a compressor to produce a compressed gas stream; (b) separating the compressed gas stream in a first separation unit into a first hydrocarbon liquid stream enriched in C.sub.3+ hydrocarbons relative to the compressed gas stream and a first gas stream depleted in C.sub.3+ hydrocarbons relative to the compressed gas stream; (c) cooling the first gas stream in a heat-exchange unit to produce a cooled first gas stream; (d) directing the cooled first gas stream through a Joule-Thomson valve to produce an expanded gas stream, wherein the expanded gas stream is at a temperature no lower than 10 C.; (e) routing the first hydrocarbon liquid stream and the expanded gas stream to a second separation unit to separate a second hydrocarbon liquid stream enriched in C.sub.3+ hydrocarbons relative to the expanded gas stream and a second gas stream depleted in C.sub.3+ hydrocarbons relative to the expanded gas stream; (f) heating the second gas stream by heat-exchange against the first gas stream in the heat-exchange unit of step (c) to generate a heated gas stream; (g) passing the heated gas stream as a feed stream across a membrane selective in favor of methane over C.sub.3+ hydrocarbons to produce a permeate stream enriched in methane relative to the heated gas stream and a residue stream depleted in methane relative to the heated gas stream; and (h) recycling the residue stream back to the flare gas stream prior to step (a).

2. The process of claim 1, wherein the second separation unit is a distillation column.

3. The process of claim 1, further comprising the steps of: (i) directing the second hydrocarbon liquid stream to a third separation unit to separate a third hydrocarbon liquid stream enriched in C.sub.3+ hydrocarbons relative to the second hydrocarbon liquid stream and a third gas stream depleted in C.sub.3+ hydrocarbons relative to the second hydrocarbon liquid stream; and (j) combining the third gas stream with the heated gas stream of step (f) prior to step (g).

4. The process of claim 3, wherein the third separation unit is a distillation column.

5. The process of claim 1, wherein the membrane comprises a polymer having the formula: ##STR00005## where x and y represent the relative proportions of the dioxole and the tetrafluoroethylene blocks, respectively, such that x+y=1, and where x>0 and y>0.

6. The process of claim 1, wherein the permeate stream is sent as fuel to a fuel user.

7. The process of claim 6, wherein the fuel user comprises power generation equipment.

8. The process of chum 6, wherein the fuel user is a gas engine.

9. The process of claim 6, wherein the fuel user drives the compressor in step (a).

10. The process of claims 1 or 3, further comprising the step of passing the flare gas stream to a dehydration unit prior to step (a).

11. The process of claim 10, wherein the dehydration unit is a molecular sieve.

12. The process of claim 1 or 3, further comprising the step of injecting a hydrate inhibiting chemical into the first gas stream prior to step (c).

13. The process of claim 12; wherein the hydrate inhibiting chemical is methanol.

14. A process for treating a flare gas stream, the flare gas stream comprising at least methane and C.sub.3+ hydrocarbons, and the process comprising the following steps: (a) compressing the flare gas stream with a compressor to produce a compressed gas stream; (b) separating the compressed gas stream in a first separation unit into a first hydrocarbon liquid stream enriched in C.sub.3+ hydrocarbons relative to the compressed gas stream and a first gas stream depleted in C.sub.3+ hydrocarbons relative to the compressed gas stream; (c) cooling the first gas stream in a heat-exchange unit to produce a cooled first gas stream; (d) directing the cooled first gas stream through a Joule-Thomson valve to produce an expanded gas stream, wherein the expanded gas stream is at a temperature no lower than 10 C.; (e) routing the first hydrocarbon liquid stream and the expanded gas stream to a second separation unit to separate a second hydrocarbon liquid stream enriched in C.sub.3+ hydrocarbons relative to the expanded gas stream and a second gas stream depleted in C.sub.3+ hydrocarbons relative to the expanded gas stream; (f) heating the second gas stream by heat-exchange against the first gas stream in the heat-exchange unit of step (c) to generate a heated gas stream; (g) passing the heated gas stream as a feed stream across a membrane selective in favor of C.sub.3+ hydrocarbons over methane to produce a permeate stream enriched in C.sub.3+ hydrocarbons relative to the heated gas stream and a residue stream depleted in C.sub.3+ hydrocarbons relative to the heated gas stream; and (h) recycling the permeate stream back to the flare gas stream prior to step (a).

15. The process of claim 14, wherein the second separation unit is a distillation column.

16. The process of claim 14, further comprising the steps of: (i) directing the second hydrocarbon liquid stream to a third separation unit to separate a third hydrocarbon liquid stream enriched in C.sub.3+ hydrocarbons relative to the second hydrocarbon liquid stream and a third gas stream depleted in C.sub.3+ hydrocarbons relative to the second hydrocarbon liquid stream; and (j) combining the third gas stream with the heated gas stream of step (f) prior to step (g).

17. The process of claim 16, wherein the third separation unit is a distillation column.

18. The process of claim 14, wherein the membrane includes a selective layer that comprises a rubbery elastomeric polymer.

19. The process of claim 14, farther comprising the step of passing the flare gas stream to a dehydration unit prior to step (a).

20. The process of claim 19, wherein the dehydration unit is a molecular sieve.

21. The process of claim 14, further comprising the step of injecting a hydrate inhibiting chemical into the first gas stream prior to step (c).

22. The process of claim 21, wherein the hydrate inhibiting chemical is methanol.

23. The process of claim 14, wherein the residue stream is sent as fuel to a full user.

24. The process of claim 23, wherein the fuel user comprises power generation equipment.

25. The process of claim 23, wherein the fuel user is a gas engine.

26. The process of claim 23, wherein the fuel user drives the compressor in step (a).

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) FIG. 1 is a schematic drawing showing a conventional NGL recovery process using refrigeration and without membrane separation (not in accordance with the invention).

(2) FIG. 2 is a schematic drawing showing a basic embodiment of the invention using a membrane having a selective layer comprising a glassy polymer.

(3) FIG. 3 is a schematic drawing showing an alternative embodiment of the invention of FIG. 2 with the addition of a third separation unit.

(4) FIG. 4 is a schematic drawing showing an alternative embodiment of the invention of FIG. 3 with the addition of a dehydration unit.

(5) FIG. 5 is a schematic drawing showing an alternative embodiment of the invention of FIG. 4, but the membrane has a selective layer comprising a rubbery polymer.

(6) FIG. 6 is a schematic drawing showing a basic embodiment of an NGL recovery system of the present invention that includes a dehydration unit, a compressor, a first separation unit, a heat exchanger, a J-T valve, a second separation unit, a third separation unit, and a membrane.

DETAILED DESCRIPTION OF THE INVENTION

(7) The term natural gas liquids refers to hydrocarbon liquids recovered from natural gas and including C.sub.3+ hydrocarbons.

(8) The terms C.sub.3+ hydrocarbon and heavier hydrocarbon mean a hydrocarbon having at least three carbon atoms.

(9) The terms lighter and leaner mean reduced in C.sub.3+ hydrocarbon content.

(10) The invention relates to an improved process for recovering NGL from a flare gas comprising at least methane and C.sub.3+ hydrocarbons. The process uses J-T cooling through an expansion valve in combination with membranes having a selective layer comprising either a glassy or rubbery polymer that is selective for methane or C.sub.3+ hydrocarbons, respectively. The process provides that a stream withdrawn from the membrane enriched in C.sub.3+ hydrocarbons may be recycled to recover more NGL. The process can be used to replace existing processes at field facilities or gas processing plants that use expensive turboexpanders and mechanical refrigeration operations to recover NGL.

(11) A basic process according to the invention is shown in FIG. 2.

(12) It will be appreciated by those of skill in the art that FIG. 2 and the other figures showing process schemes herein are very simple block diagrams, intended to make clear the key unit operations of the embodiment processes of the invention, and that actual process trains may include many additional steps of standard type, such as heating, chilling, compressing, condensing, pumping, various types of separation and/or fractionation, as well as monitoring of pressures, temperatures, flows, and the like. It will also be appreciated by those of skill in the art that the details of the unit operations may differ from process to process.

(13) A flare gas, 201, is combined with a recycled C.sub.3+ hydrocarbon stream, 224, to produce a gas mixture stream, 202. The flare gas typically contains at least methane and C.sub.3+ hydrocarbons and may contain additional gas components, such as nitrogen and acid gases, and in some cases, water vapor.

(14) Gas mixture stream 202 is routed to compression step, 203, the goal of which is to compress the stream to a pressure in which the gas mixture may be partially condensed in the subsequent process steps. The compression step may be carried out using compressor equipment of any convenient types, and may be performed in more than two steps or in a compression train of multiple sub-steps, depending on the degree of compression needed.

(15) The stream emerging from compression step 203 is a compressed stream, 204. This stream is sent through the compressor aftercooler (not shown in the figure) to a first separation step, 205. This step separates gas from liquids in a phase separator, a knock-out drum or the like to yield a first hydrocarbon liquid stream, 207, enriched in C.sub.3+ hydrocarbons and a first gas stream, 206, depleted in C.sub.3+ hydrocarbons. In this step, lighter hydrocarbons are removed from heavier hydrocarbons, which otherwise could not pass through the subsequent heat exchange and J-T expansion steps without clogging or fouling these operations.

(16) Stream 206 is then directed to a heat exchange step, 208. Because stream 206 is at a relatively warm temperature, such as about 40 C., it is desirable that the stream be cooled prior to entering a J-T expansion step, 210. Pre-chilling the natural gas before it flows into the J-T valve results in a considerably lower temperature and produces significantly more natural gas liquids. Cooling of stream 206 may be accomplished in any way, but preferably by heat exchange against other on-site process streams. In FIG. 2, the heat exchange occurs between cooled overhead stream, 218, and stream, 206.

(17) Cooled gas stream, 209, passes to a J-T expansion step, 210. Expansion of the gas at the J-T valve results in significant cooling, and brings expanded gas stream, 211, to a temperature at which a substantial fraction of the C.sub.3+ hydrocarbon content will condense out of the stream. Preferably this temperature is below 0 C., and in the range 0 to 10 C. Very cold temperatures are not required, as any uncondensed gas fraction will be further treated in the subsequent membrane separation step. While sub-zero temperatures are preferred, it can be seen from the Examples section that some useful NGL recovery is possible even at relatively high temperatures after expansion, such as 10 C. or even above.

(18) In a next step, the expanded gas stream, 211, and the first hydrocarbon liquid stream, 207, are sent to a second separation step, 212. This second separation yields a second hydrocarbon liquid stream, 213, enriched in C.sub.3+ hydrocarbons and a second gas stream, 218, depleted in C.sub.3+ hydrocarbons. In FIG. 2, the second separation step, 212, may be a distillation column or a simple phase separator.

(19) The second gas stream, 218, is removed from the second separation step, 212, and sent back to the heat-exchange step, 208, where it is used to cool incoming stream 206. Heat transfer between streams 218 and 206 produces warmed stream, 219 and cooled stream 209. Heating of stream 218 in this way prior to membrane separation is beneficial in that it helps to alleviate any condensation of heavier hydrocarbons on the membrane surface during the following membrane separation step, 221.

(20) Stream 219 is sent as a feed stream to a membrane separation step, 221. Any membrane with suitable performance properties may be used in the membrane separation step. The membrane may take the form of a homogeneous film, an integral asymmetric membrane, a multi-layer composite membrane, a membrane incorporating a gel or liquid layer or particulates, or any other form known in the art.

(21) Membranes for use in separation step 221 may comprise a selective layer, 222, that may comprise any polymer that will preferentially permeate methane over C.sub.2+ hydrocarbons. Preferred membrane materials are glassy polymers, such as, for example and without limitation, polyamides, polyimides, polysulfones, polyvinyl alcohol, polypropylene oxide, cellulose derivatives, polyvinylidene fluoride and polymers having repeating units of fluorinated dioxoles, fluorinated dioxolanes, and fluorinated cyclically polymerizable alkyl ethers. Particularly preferred membranes have selective layers made from a hydrophobic fluorinated glassy polymer or copolymer.

(22) Specific most preferred materials are copolymers of tetrafluoroethylene with 2,2,4-trifluoro-5-trifluoromethoxy-1,3-dioxole having the structure:

(23) ##STR00002##
where x and y represent the relative proportions of the dioxole and the tetrafluoroethylene blocks, such that x+y=1.

(24) Such materials are available commercially from Solvay Solexis, Thorofare, N.J., under the trade name Hyflon AD. Different grades are available varying in proportions of the dioxole and tetrafluoroethylene units, with fluorine:carbon ratios of between 1.5 and 2, depending on the mix of repeat units. For example, grade Hyflon AD 60 contains a 60:40 ratio of dioxole to tetrafluoroethylene units, has a fractional free volume of 0.23, a density of 1.93 g/cm.sup.3 and a glass transition temperature of 121 C., and grade Hyflon AD 80 contains an 80:20 ratio of dioxole to tetrafluoroethylene units, has a fractional free volume of 0.23, a density of 1.92 g/cm.sup.3 and a glass transition temperature of 134 C.

(25) The fluorinated polymer is preferably heavily fluorinated, by which we mean having a fluorine:carbon ratio of atoms in the polymer of at least about 1:1. Most preferably, the polymer is perfluorinated

(26) Other specific highly preferred materials include the set of polyperfluoro (alkenyl vinyl ethers) including polyperfluoro (allyl vinyl ether) and polyperfluoro (butenyl vinyl ether) that are cyclically polymerizable by the formation of repeat units of ether rings with five or six members in the ring.

(27) A particular preferred material of this type has the structure:

(28) ##STR00003##
where n is a positive integer.

(29) This material is available commercially from Asahi Glass Company, of Tokyo, Japan, under the trade name Cytop. Cytop has a fractional free volume of 0.21, a glass transition temperature of 108 C., and a fluorine:carbon ratio of 1.7.

(30) A third group of materials that is believed to contain useful selective layer materials under some circumstances is:

(31) ##STR00004##
where x and y represent the relative proportions of the dioxole and the tetrafluoroethylene blocks, such that x+y=1.

(32) Such materials are available commercially from DuPont of Wilmington, Del., under the tradename Teflon AF.

(33) The polymer chosen for the selective layer can be used to form films or membranes by any convenient technique known in the art, and may take diverse forms. If super-glassy membranes are used, they may be formed as integral asymmetric or composite membranes.

(34) Because the polymers are glassy and rigid, an unsupported film, tube, or fiber of the polymer is usable as a single-layer membrane. However, single-layer films will normally be too thick to yield acceptable transmembrane flux however, and, in practice, the separation membrane usually comprises a very thin selective layer that forms part of a thicker structure, such as an integral asymmetric membrane or a composite membrane.

(35) The preferred form is a composite membrane. Modern composite membranes typically comprise a highly permeable, but relatively non-selective, support membrane that provides mechanical strength, coated with a thin selective layer of another material that is primarily responsible for the separation properties. Typically, but not necessarily, such a composite membrane is made by solution-casting the support membrane, then solution-coating the selective layer. Preparation techniques for making composite membranes of this type are well known.

(36) The membranes may be manufactured as flat sheets or as fibers and housed in any convenient module form, including spiral-wound modules, plate-and-frame modules, and potted hollow fiber modules. The making of all these types of membranes and modules is well-known in the art. Flat-sheet membranes in spiral-wound modules are the most preferred choice.

(37) The membrane separation steps disclosed herein may be carried out using a single membrane module or a bank of membrane modules or an array of modules. A single unit or stage containing on or a bank of membrane modules is adequate for many applications. If either the residue or permeate stream, or both, requires further C.sub.3+ hydrocarbon removal, it may be passed to a second bank of membrane modules for a second processing step. Such multi-stage or multi-step processes, and variants thereof, will be familiar to those of skill in the art, who will appreciate that the membrane separation step may be configured in many possible ways, including single-stage, multistage, multistep, or more complicated arrays of two or more units, in serial or cascade arrangements.

(38) The membrane separation steps disclosed herein can be operated by any mechanism that provides a driving force for transmembrane permeation. Most commonly, this driving force is provided by maintaining a pressure difference between the feed and permeate sides, or by sweeping the permeate side continuously with a gas that dilutes the permeating species, both of which techniques are well known in the membrane separation arts.

(39) Referring back to FIG. 2, a residue stream, 224, which is depleted in methane and enriched in C.sub.3+ hydrocarbons relative to stream 219, is withdrawn from the feed side of the membrane. Residue stream 224 represents a significant source of C.sub.3+ hydrocarbons that may be recovered if recycled back to the process. Thus, in a preferred embodiment, residue stream 224 is sent back to the process prior to compression step 203.

(40) A permeate stream, 223, enriched in methane compared to stream 219, is withdrawn from the permeate side of the membrane. Permeate stream 223 represents a source of fuel gas that may be used for on-site fuel users. The fuel user is typically a gas engine or other device used to generate power or drive a compressor, such as the compressor in compression step 203, but may alternatively be used for a generator set. The gas stream being treated using the process of the invention is typically a high-pressure gas stream created by a compressor driven by a gas engine, and one aspect of the process typically involves using the membrane permeate stream enriched in methane as fuel for the gas engine. The membrane permeate stream may be routed to the fuel user through a pressure control valve at an appropriate pressure point.

(41) Another embodiment of the NGL recovery process is shown in FIG. 3. This embodiment is similar to that of FIG. 2 with the addition of a third separation step, 315.

(42) The principal purpose of step 315 is to stabilize the raw NGL stream to reduce or remove light hydrocarbons that may remain dissolved therein. Such stabilization is desirable if the NGL product is to be transported or stored for later use, for example. In the embodiment depicted in FIG. 3, the second separation step, 212, is carried out in a simple phase separator or the like and the third separation step, 315, is carried out in a distillation column, generally operated as a deethanizer or demethanizer. Third separation step 315 produces an overhead third gas stream, 317, depleted in C.sub.3+ hydrocarbons and a bottom third hydrocarbon liquid stream, 316, which forms the stabilized NGL product.

(43) Third gas stream 317 may be combined with stream 219 as second gas mixture stream, 320, which forms the feed stream to membrane separation step 221. A residue stream, 224, that is enriched in C.sub.3+ hydrocarbons relative to stream 320, is withdrawn from the feed side of the membrane. A permeate stream, 222, depleted in C.sub.3+ hydrocarbons compared to stream 320, is withdrawn from the permeate side of the membrane.

(44) Another embodiment of the NGL recovery process is shown in FIG. 4. This embodiment is similar to that of FIG. 3, except that an upstream dehydration step has been included as an explicit step in the process. (In the embodiments of FIGS. 2 and 3, dehydration was assumed to have taken place upstream of the process, or to be unnecessary for some reason).

(45) Flare gas, 201, frequently contains a significant amount of water vapor or hydrates. These contaminants must be removed prior to the separation steps, to enable these steps to be operated at below freezing temperatures without clogging. In the embodiment shown in FIG. 4, flare gas 201 is directed to a dehydration step, 425, which removes a water-enriched stream, 428. Any type of dehydration unit known in the art may be used in this step. In a preferred embodiment, the dehydration unit is a molecular sieve.

(46) A dehydrated gas stream, 426, is withdrawn from the dehydration unit of step 425 and is then combined with the recycled residue stream, 224, to produce a first gas mixture stream, 427. First gas mixture stream 427 is then sent through compression step 203.

(47) A further embodiment of the NGL recovery process is shown in FIG. 5. This embodiment is similar to that of FIG. 4, but uses a methane-rejecting, rather than a methane-selective membrane.

(48) Stream 320 is sent as a feed stream to a membrane separation step, 521. Any membrane with suitable performance properties may be used in the membrane separation step. The membrane may take the form of a homogeneous film, an integral asymmetric membrane, a multi-layer composite membrane, a membrane incorporating a gel or liquid layer or particulates, or any other form known in the art.

(49) Membranes for use in separation step 521 may comprise a selective layer, 522, that may comprise any polymer that will preferentially permeate C.sub.3+ hydrocarbons over methane. Preferably, these polymers are made from an elastomeric or rubbery polymer, examples of which include, but are not limited to, nitrile rubber, neoprene, polydimethylsiloxane (silicone rubber), chlorosulfonated polyethylene, polysilicone-carbonate copolymers, fluoroelastomers, etc. Silicone rubber is the most preferred material for separating C.sub.3+ hydrocarbons from methane.

(50) A residue stream, 524, that is depleted in C.sub.3+ hydrocarbons relative to stream 320, is withdrawn from the feed side of the membrane. This stream can be used as fuel gas or flared. A permeate stream, 523, enriched in C.sub.3+ hydrocarbons compared to stream 320, is withdrawn from the permeate side of the membrane. This stream represents a significant source of C.sub.3+ hydrocarbons that is recycled back to the process prior to compression step 203. Stream 523 is combined with dehydrated stream 426 to produce a first gas mixture stream, 427, that is fed into the compressor of compression step, 203.

(51) FIG. 6 is a schematic drawing of a system for recovering NGL and methane. The system comprises a dehydration unit, 638, that includes a flare gas inlet, 639, a dehydrated stream outlet, 640, and a water-enriched stream outlet, 641.

(52) In operation, a flare gas stream, 601, comprising at least methane and C.sub.3+ hydrocarbons enters into a dehydration unit, 638, through a flare gas inlet, 639. A water-enriched stream 648, is withdrawn from the dehydration unit, 638, via the water-enriched stream outlet, 641. A dehydrated stream, 642, exits the dehydration unit, 638, from the dehydrated stream outlet, 640.

(53) The compressor, 603, includes a gas mixture stream inlet, 604, that is in gas communication with the dehydration stream outlet, 640, and a residue stream outlet, 635. The dehydrated stream flows from the dehydration unit, is mixed with a residue stream, 637, and enters the compressor as gas mixture stream 602 through the gas mixture stream inlet, 604. The compressor, 603, also includes a compressed gas outlet, 605, that allows a compressed gas stream, 607, to be withdrawn.

(54) The first separation unit, 608, includes a compressed gas stream inlet, 609, a first gas stream outlet, 610, and a first hydrocarbon liquid stream outlet, 611. The compressed gas stream inlet, 609, is in gas communication with compressed gas outlet, 605. The compressed gas stream inlet, 609, allows the compressed gas, 607, to enter the first separation unit, 608. The compressed gas, 607, is then separated into a first gas stream, 612, which is withdrawn from the first gas stream outlet, 610, and a first hydrocarbon liquid stream, 627, which is withdrawn from the first hydrocarbon liquid stream outlet, 611.

(55) The heat-exchanger, 613, includes a first gas stream inlet, 614, a cooled gas stream outlet, 615, a second gas stream inlet, 616, and a heated gas stream outlet, 617. The first gas stream inlet, 614, is in gas communication with the first gas stream outlet, 610. The first gas stream inlet, 614, allows the first gas stream, 612, to enter into heat-exchanger 613, where it is cooled against a second gas stream, 629. The cooled gas stream outlet, 615, allows a cooled gas stream, 618, to exit the heat-exchanger, 613. The second gas stream inlet, 616, and the heated gas outlet, 617, are described in further detail below.

(56) The J-T valve, 619, includes a J-T inlet, 620, and a J-T outlet, 621. The J-T inlet is in gas communication with the cooled gas stream outlet, 615. The cooled gas stream, 618, enters the J-T valve, 619, through J-T inlet 620. The J-T valve expands cooled gas stream, 618, to produce an expanded gas stream, 622, which is withdrawn via J-T outlet, 621.

(57) The second separation unit, 623, includes an expanded gas inlet, 624, a second hydrocarbon liquid stream outlet, 625, a first hydrocarbon liquid stream inlet, 628, and a second gas stream outlet, 626. The expanded gas inlet, 624, is in gas communication with J-T valve 619 and the first hydrocarbon liquid stream inlet, 628, is in fluid communication with the first hydrocarbon liquid stream outlet, 611. The expanded gas stream, 622, and the first hydrocarbon liquid stream, 628, enter the second separation unit, 623, via inlets, 624, and 628, respectively. The second separation unit, 623, produces a second gas stream, 629, and a second hydrocarbon liquid stream, 638. The second gas stream, 629 exits unit 623 through second gas stream outlet, 626, and the second hydrocarbon liquid stream, 638, exits through the second hydrocarbon liquid stream outlet, 625.

(58) As discussed above, heat exchanger 613 also comprises second gas stream inlet, 616, and a heated gas stream outlet, 617. The second gas stream inlet, 616, is in gas communication with the second gas stream outlet, 626. This allows for the second gas stream, 629, to flow from the second separation unit, 623, back through heat exchanger, 613. Stream 629 is heated by heat exchange against first gas stream 612. A heated gas stream, 630, is withdrawn from the heat exchanger, 617, through heated gas stream outlet, 617.

(59) A third separation unit, 643, includes a second liquid hydrocarbon stream inlet, 649, a third hydrocarbon liquid stream outlet, 645, and a third gas stream outlet, 644. The second liquid hydrocarbon stream inlet, 649, is in fluid communication with second liquid hydrocarbon stream outlet, 625. The second liquid hydrocarbon stream, 638, enters the third separation unit, 643, through inlet, 649, and is separated into a third hydrocarbon liquid stream, 647, and a third gas stream, 646. The third gas stream, 646 exits unit 643 through third gas stream outlet, 644, and the third hydrocarbon liquid stream, 647, exits through the third hydrocarbon liquid stream outlet, 645.

(60) The membrane, 631, comprises a feed inlet, 634, a permeate outlet, 636, and a residue outlet, 635. The feed inlet, 634, is in gas communication with the heated gas outlet, 617 of heat exchanger, 613, and third gas stream outlet 644. The residue outlet, 635, is in gas communication with the gas mixture stream inlet, 604, of the compressor, 603.

(61) Feed inlet, 634, allows a mixture, 650, of the heated gas stream, 630, and the third gas stream, 646, to enter the membrane, 631, which comprises a selective layer, 632. In the embodiment shown in FIG. 6, the selective layer, 632, comprises a glassy polymer and preferentially removes methane from C.sub.3+ hydrocarbons. The permeate stream, 633, is enriched in methane and exits the membrane through permeate outlet 636. The residue stream, 637, is depleted in methane and is withdrawn from the membrane via residue outlet 635.

(62) In other embodiments, membrane selective layer 632 may comprise a rubbery polymer. In these cases, the membrane, 631, will comprise a permeate outlet, 633, that is in gas communication with the gas mixture stream inlet, 604, of compressor, 603.

(63) The invention is now further described by the following examples, which are intended to be illustrative of the invention, but are not intended to limit the scope or underlying principles in any way.

EXAMPLES

Example 1. NGL Recovery Process Using Refrigeration According to FIG. 1 (not in Accordance with the Invention)

(64) For comparison with the following examples, a calculation was performed in a low-temperature refrigeration process where none of the streams are treated by membrane separation. The process of FIG. 1 is described above. Feed stream 101 was assumed to have been dehydrated in step 102 using a molecular sieve, so that stream 103 contains essentially no water. The stream was assumed to be refrigerated to 40 F. in step 109.

(65) The calculation was performed using differential element membrane code written at MTR and incorporated into a computer process simulation program (ChemCad 6.3, ChemStations, Austin, Tex.).

(66) The results of the calculations are shown in Table 1:

(67) TABLE-US-00001 TABLE 1 Stream Number 103 118 119 Dry feed 105 107 108 110 112 115 117 Fuel gas NGL Temp F. 100 234 100 100 40 38 38 44 27 155 Pres psia 65 200 200 200 198 198 198 280 198 285 Total lbmol/h 129.79 129.79 128.56 1.23 128.56 36.78 93.01 13 106.01 23.78 Total lb/h 3619 3619 3527 91.37 3527 1628 1991 376 2366 1252 Total std L gpd 24920 24920 24500 420 24500 9443 15477 2833 18310 6609 Total std V MMscfd 1.18 1.18 1.17 0.01 1.17 0.33 0.85 0.12 0.97 0.22 Component mole % Nitrogen 8.78 8.78 8.86 0.24 8.86 0.38 12.1 1.08 10.75 0 Methane 50.23 50.23 50.67 3.77 50.67 9.61 66.29 27.2 61.5 0 Carbon Dioxide 0.58 0.58 0.58 0.1 0.58 0.37 0.66 1.05 0.71 0 Hydrogen Sulfide 0 0 0 0 0 0.01 0 0.01 0 0 Ethane 18.12 18.12 18.24 6.24 18.24 24.09 15.76 54.47 20.51 7.5 Propane 15.02 15.02 15.01 15.75 15.01 40.92 4.77 14.44 5.96 55.39 C4+ Hydrocarbons 7.26 7.26 6.62 73.89 6.62 24.60 0.4 1.73 0.56 37.11 Water 0 0 0 0 0 0 0 0.01 0 0

(68) With compression to 200 psia and refrigeration to 40 F., the process recovers about 80 mol % of the C.sub.3+ hydrocarbons from the flare gas feed stream.

Example 2. NGL Recovery Process in Accordance with the Invention of FIG. 2 or 3

(69) A calculation was performed to model the performance of the process of FIG. 2 or FIG. 3 in recovering an NGL stream. For the purposes of this calculation, it was assumed that no dehydration is used, so that all streams must remain well above the temperature of ice or hydrate formation. Thus, the J-T expansion step was assumed to lower the pressure of the gas stream from about 600 psia by only about half, to 325 psia. As a result, the temperature of the expanded stream, 211, only fell to about 60 F. (about 15 C.). The results of the calculations are shown in Table 2.

(70) TABLE-US-00002 TABLE 2 Stream Number 201 213 316 223 Feed 204 209 211 207 NGL* NGL** 320 Fuel gas 224 Temp F. 100 100 90 61 100 63 100 84 79 76 Pres psia 65 600 598 325 600 325 275 320 65 286 Total lbmol/h 132 380 357 357 23 25 19 359 108 251 Total lb/h 3653 10785 9801 9801 985 1229 1048 9709 2497 7204 Total std L gpd 25015 77513 69976 69976 5538 6780 5436 7002 18936 51009 Total std V MMscfd 1.20 3.46 3.25 3.25 0.21 0.23 0.17 3.27 0.98 2.28 Component mole % Nitrogen 8.65 5.75 6.07 6.07 0.68 0.33 0 6.08 10.43 4.21 Methane 49.49 44.57 46.65 46.65 11.58 7.20 0 47.15 59.21 41.95 Carbon Dioxide 0.57 0.30 0.31 0.31 0.14 0.11 0 0.32 0.69 0.16 Hydrogen Sulfide 0 0 0 0 0 0 0 0 0 0 Ethane 17.86 23.42 23.70 23.70 18.96 17.08 7.0 24.40 19.84 26.37 Propane 14.80 19.92 18.91 18.91 35.98 41.26 48.99 18.46 8.78 22.64 C4+ Hydrocarbons 7.15 5.50 4.18 4.18 26.43 33.98 44.0 3.47 0.80 4.62 Water 1.48 0.54 0.18 0.18 6.23 0.04 0 0.10 0.24 0.04 *Unstabilized NGL product as in FIG. 2 **Stabilized NGL product as in FIG. 3

(71) Using the J-T valve and membrane combination, the process achieved about 65 mol % of heavier hydrocarbons recovery in the NGL product stream, 213, even though the gas was only cooled to about 15 C.

Example 3. NGL Recovery Process in Accordance with the Invention of FIG. 4

(72) A calculation was performed to model the performance of the process of FIG. 4 in recovering a NGL stream. The flare gas stream was assumed to be dehydrated, compressed to 1,200 psia and cooled to 21 F. (6 C.) by expansion to 325 psia. The results of the calculations are shown in Table 3.

(73) TABLE-US-00003 TABLE 3 Stream Number 201 204 206 207 209 211 218 219 223 Temp F. 100 441 100 100 70 11 21 90 79 Pres psia 65 1200 1200 1200 1198 325 325 323 65 Enth hp 1854 2148 1927 687 1971 1971 1848 1804 1306 Vapor mole frac. 1 1 1 0 1 1 1 1 1 Total lbmol/h 132 178 140 38 140 140 141 141 106 Total lb/h 3653 5015 3624 1391 3624 3624 3343 3343 2361 Total std L gpd 25015 35012 26264 8748 26264 26264 25327 25327 18270 Total std V MMscfd 1.2 1.62 1.27 0.35 1.27 1.27 1.28 1.28 0.96 Component mole % Nitrogen 8.65 7.07 8.25 2.78 8.25 8.25 8.85 8.85 10.76 Methane 49.49 47.16 52.15 28.92 52.15 52.15 57.15 57.15 61.43 Carbon Dioxide 0.57 0.43 0.45 0.37 0.45 0.45 0.49 0.49 0.71 Hydrogen Sulfide 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Ethane 17.86 22.06 21.39 24.52 21.39 21.39 21.80 21.80 20.53 Propane 14.80 17.02 14.11 27.65 14.11 14.11 10.45 10.45 6.15 C4+ Hydrocarbons 7.15 6.24 3.64 15.75 3.64 3.64 1.26 1.26 0.40 Water 1.48 0.01 0.01 0.00 0.01 0.01 0.01 0.01 0.01 Stream Number 224 314 316 317 320 425 427 428 Temp F. 71 21 171 67 87 100 83 100 Pres psia 316 325 325 320 320 65 65 65 Enth hp 714 810 519 217 2021 1775 2482 93 Vapor mole frac. 1 0 0 1 1 1 1 0 Total lbmol/h 49 38 23 14 155 130 178 2 Total lb/h 1411 1673 1244 430 3772 3618 5015 35 Total std L gpd 10200 9691 6545 3147 28474 24915 35012 100 Total std V MMscfd 0.45 0.34 0.21 0.13 1.41 1.18 1.62 0.02 Component mole % Nitrogen 2.50 0.47 0.00 1.25 8.15 8.78 7.07 0.00 Methane 38.94 10.02 0.00 26.47 54.31 50.23 47.16 0.00 Carbon Dioxide 0.05 0.23 0.00 0.60 0.50 0.58 0.43 0.00 Hydrogen Sulfide 0.00 0.00 0.00 0.01 0.00 0.00 0.00 0.00 Ethane 32.60 23.04 7.00 49.35 24.35 18.12 22.06 0.00 Propane 22.38 41.46 54.79 19.59 11.29 15.02 17.02 0.00 C4+ Hydrocarbons 3.53 24.77 38.22 2.72 1.39 7.26 6.24 0.00 Water 0.00 0.00 0.00 0.01 0.01 0.01 0.01 100

(74) In this case, the process of the invention recovers an NGL product containing about 77 mol % of the heavier hydrocarbons from the flare gas.

Example 4. NGL Recovery Process in Accordance with the Invention of FIG. 5

(75) A calculation was performed to model the performance of the process of FIG. 5 in recovering a NGL stream. In this case, it was assumed that a membrane selective in favor of heavier hydrocarbons over methane was used. The results of the calculations are shown in Table 4.

(76) TABLE-US-00004 TABLE 4 Stream Name 201 204 206 207 209 218 219 314 Temp F. 100 451 100 100 75 17 85 17 Pres psia 65 1200 1200 1200 1198 350 348 350 Enth hp 1854 3488 3813 392 3887 3219 3145 1059 Vapor mole frac. 1 1 1 0 1 1 1 0 Total lbmol/h 132 285 263 22 263 233 233 52 Total lb/h 3653 7697 6929 768 6929 5583 5583 2114 Total std L gpd 25015 56108 51092 5017 51092 43232 43232 12881 Total std V MMscfd 1.20 2.59 2.39 0.20 2.39 2.12 2.12 0.47 Component mole % Nitrogen 8.65 5.28 5.54 2.17 5.54 6.36 6.36 0.39 Methane 49.49 46.44 47.94 28.70 47.94 54.33 54.33 10.73 Carbon Dioxide 0.57 0.99 1.00 0.83 1.00 1.08 1.08 0.56 Hydrogen Sulfide 0.00 0.01 0.01 0.01 0.01 0.01 0.01 0.01 Ethane 17.86 29.54 29.26 32.80 29.26 28.73 28.73 33.22 Propane 14.80 13.64 12.86 22.91 12.86 8.57 8.57 36.57 C4+ Hydrocarbons 7.15 4.09 3.37 12.58 3.37 0.90 0.90 18.51 Water 1.48 0.01 0.01 0.01 0.01 0.01 0.01 0.01 Stream Name 316 317 320 426 427 428 523 524 Temp F. 160 53 77 100 82 100 65 53 Pres psia 305 300 300 65 65 65 65 296 Enth hp 567 397 3542 1775 4026 94 2274 1268 Vapor mole frac. 0 1 1 1 1 0 1 1 Total lbmol/h 26 26 259 130 285 2 157 102 Total lb/h 1341 773 6357 3618 7697 35 4121 2236 Total std L gpd 7115 5766 48997 24914 56108 101 31509 17484 Total std V MMscfd 0.23 0.23 2.36 1.18 2.59 0.02 1.43 0.93 Component mole % Nitrogen 0.00 0.79 5.80 8.78 5.28 0.00 2.35 11.09 Methane 0.00 21.45 51.05 50.23 46.44 0.00 43.27 62.97 Carbon Dioxide 0.00 1.12 1.09 0.58 0.99 0.00 1.33 0.71 Hydrogen Sulfide 0.00 0.02 0.01 0.00 0.01 0.00 0.01 0.00 Ethane 7.50 58.92 31.74 18.12 29.54 0.00 39.10 20.47 Propane 57.31 15.85 9.30 15.02 13.64 0.00 12.49 4.42 C4+ Hydrocarbons 35.19 1.85 1.00 7.26 4.09 0.00 1.44 0.32 Water 0.00 0.02 0.01 0.00 0.01 100.00 0.02 0.00

(77) Using a dehydration unit with a J-T valve and a membrane with a selective layer comprising a rubbery polymer achieves about 80 mol % recovery of heavier hydrocarbons in the NGL product stream.