US20210095921A1

US20210095921A1 - Integrated methods and configurations for propane recovery in both ethane recovery and ethane rejection

Info

Publication number: US20210095921A1
Application number: US17/054,195
Authority: US
Inventors: John Mak; James Shih; Dave Schulte
Original assignee: Fluor Technologies Corp
Current assignee: Fluor Technologies Corp
Priority date: 2018-05-22
Filing date: 2018-05-22
Publication date: 2021-04-01
Also published as: WO2019226156A1

Abstract

A natural gas liquids (NGL) plant, the NGL plant comprising an absorber configured to provide an absorber overhead and an absorber bottoms, a stripper configured to produce a stripper overhead and a stripper bottoms, wherein the stripper is positioned downstream from the absorber and fluidly connected therewith such that the absorber bottoms can be introduced into the stripper, and a multi-pass heat exchanger configured to provide at least one reflux stream to the absorber, wherein the absorber and stripper are configured, in an ethane rejection arrangement, to provide the stripper overhead to a top of the absorber, and wherein the absorber and stripper are configured, in an ethane recovery arrangement, to provide the stripper overhead to a bottom of the absorber.

Description

TECHNICAL FIELD

The present disclosure relates to natural gas liquids plants; more particularly, the present disclosure relates to systems and methods whereby natural gas liquids plants can be operated with either ethane rejection or ethane recovery; still more particularly, the present disclosure relates to systems and methods for processing natural gas, whereby a natural gas liquid (NGL) plant can be operated to various levels of ethane recovery, from fully rejecting ethane to fully recovering ethane, under a switching sequence, while maintaining over 98% propane recovery in either operation.

BACKGROUND

Natural gas liquids (NGL) may describe heavier gaseous hydrocarbons: ethane (C2H6), propane (C3H8), normal butane (n-C4H10), isobutane (i-C4H10), pentanes, and even higher molecular weight hydrocarbons, when processed and purified into finished by-products. Systems can be used to recover NGL from a feed gas using natural gas liquids plants.
Typical natural gas streams, conventional gas or unconventional gas may contain 10% to 20% ethane, 10% to 15% or higher in propane and heavier hydrocarbons, with the balance methane. The propane and heavier hydrocarbons liquids can be sold as transportation fuel which can generate significant revenue for the gas processing plants, and therefore, high propane recovery is highly desirable. On the other hand, ethane value traditionally fluctuates with the petrochemical market demands. Ethane is a more efficient feedstock than naphtha or propane in ethylene production and is highly valued for petrochemical production.
Most NGL technologies are developed based on cooling natural gas with refrigeration and turbo expander for recovery of the Y-grade NGL product, which must meet the maximum of 1.5 volume % methane in the ethane, and the vapor pressure is limited to 600 psi at 100° F. This specification would allow recovery of almost all the ethane in the feed gas. Where there is a contractual requirement, maximum ethane recovery is most profitable. However, in the open market, the ethane price is lower than natural gas price, on a Btu basis. When there is no demand of ethane, or the NGL facility is located distant to an NGL pipeline, ethane must be rejected to the sales gas.
Most conventional NGL technologies are configured for recovery of ethane, and are not designed for rejecting ethane in an efficient way. With conventional NGL technologies, ethane rejection operation would result in a loss of propane, as propane is also rejected together with ethane to the residue gas. Typically, conventional ethane rejection operation will result in reducing propane recovery from 95% to between 85% to 90%, which represents a significant loss of plant revenues.
Numerous separation processes and configurations can be used to recover the NGL fractions from natural gas. In a typical NGL recovery process, high pressure feed gas stream is cooled by heat exchangers, propane refrigeration and turbo expansion. As the feed gas is cooled under pressure, the hydrocarbon liquids are condensed and separated from the chilled gas. The cooled vapor is expanded and fractionated in distillation columns (e.g., deethanizer or demethanizer) to produce a residue gas to the sales gas pipeline overhead and an ethane plus bottoms (Y-grade NGL).
Almost all the prior designs are configured for either ethane recovery or propane recovery. When required to operate in off-design ethane recovery modes, recoveries and energy efficiencies will drop. For example, Rambo et al. describe in U.S. Pat. No. 5,890,378 a system in which the absorber is refluxed, in which the deethanizer condenser provides refluxes for both the absorber and the deethanizer while the cooling duties are supplied by turbo-expansion and propane refrigeration. In this process, the absorber and the deethanizer operate at essentially the same pressure. Although the configuration of Rambo can recover 98% of the propane and heavier hydrocarbons during propane recovery operation, high ethane recovery (e.g., over 80%) is difficult even with additional refluxes.
To circumvent at least some of the problems associated with low ethane recoveries, Sorensen describes in U.S. Pat. No. 5,953,935 a plant configuration in which an additional fractionation column and reflux condenser are added to increase ethane recovery using cooling with turbo expansion and Joule Thompson expansion valves of portions of the feed gas. Although Sorensen's configuration can achieve high ethane recoveries, it fails to maintain high propane recovery when operated in ethane rejection.
To circumvent at least some of the problems associated with ethane recovery in a propane recovery process, a twin reflux process (e.g., as described in U.S. Pat. Nos. 7,051,553 and 9,103,585 to Mak et al.) employs configurations in which a first column receives two reflux streams: one reflux stream comprising a vapor portion of the NGL and the other reflux stream comprising a lean reflux provided by the overhead of the second distillation column. Even with the incorporation of recycle streams in these improvements, high ethane recovery (over 90%) is not practical.
A forced approach to achieve 98% propane recovery during ethane rejection is recycling a portion of the high pressure residue gas. The letdown of the residue gas generates cryogenic temperature refrigeration that can recover most of the propane component in the residue gas. While the residue gas recycle process, which is similar to the industrial standard gas subcooled process (GSP), is very efficient in recovery ethane, it is not energy efficient in the ethane rejection operation.
The residue gas recycle process can be used to recover 98% of the ethane from the feed gas, which is one of the most efficient processes for ethane recovery. However, if this process were used for ethane rejection, the methane rich reflux would create internal recycle of the ethane component in the deethanizer. In that effect, residue gas recycle is thermodynamically not efficient for ethane rejection and would consume power by the residue gas compressor.
Thus, although various configurations and methods are known to recover natural gas liquids, known configurations and methods suffer from one or more deficiencies and disadvantages. For example, while some known methods and configurations can be employed for ethane recovery, ethane rejection will typically result in a loss in propane recovery. Other drawbacks include that the prior designs and methods are complex, inefficient, and not easily amenable to changing recovery mode, from ethane rejection to ethane recovery and vice versa. Therefore, there is a need for methods and configurations for an NGL recovery plant that can recover over 98% propane during ethane rejection and can also recover over 98% of ethane during ethane recovery mode.

SUMMARY

Herein disclosed is a natural gas liquids (NGL) plant, the NGL plant comprising: an absorber configured to provide an absorber overhead and an absorber bottoms; a stripper configured to produce a stripper overhead and a stripper bottoms, wherein the stripper is positioned downstream from the absorber and fluidly connected therewith such that the absorber bottoms can be introduced into the stripper; and a multi-pass heat exchanger configured to provide at least one reflux stream to the absorber, wherein the absorber and stripper are configured, in an ethane rejection arrangement, to provide the stripper overhead to a top of the absorber, and wherein the absorber and stripper are configured, in an ethane recovery arrangement, to provide the stripper overhead to a bottom of the absorber.
Also disclosed herein is a method of operating a natural gas liquids (NGL) plant to produce an NGL product, the method comprising: operating the NGL plant in an ethane rejection mode, wherein operating in the ethane rejection mode comprises: producing, with an absorber, an absorber overhead stream and an absorber bottoms stream, introducing the absorber bottoms stream into a stripper; producing, with the stripper, a stripper overhead stream and a stripper bottoms stream while operating the stripper at a higher pressure than the absorber, wherein the to stripper bottoms stream comprises the NGL product; and chilling the stripper overhead stream to produce a chilled stripper overhead stream; passing the chilled stripper overhead stream to a top of the absorber to reflux the absorber; operating the NGL plant in an ethane recovery mode, wherein operating in the ethane recovery mode comprises: producing, with the absorber, the absorber overhead stream and the absorber bottoms stream; introducing the absorber bottoms stream into the stripper; producing, with the stripper, the stripper overhead stream and the stripper bottoms stream, wherein the stripper bottoms stream comprises the NGL product; and passing the stripper overhead stream to a bottom of the absorber.
Further disclosed herein is a multi-pass heat exchanger configured to provide reflux to an absorber of a natural gas liquids (NGL) plant comprising the absorber and a stripper, wherein the NGL plant is configured to selectively operate in an ethane recovery arrangement or an ethane rejection arrangement, wherein the multi-pass heat exchanged comprises: a first pass fluidly connected with a separator liquid line of a cold separator, wherein the cold separator is configured to separate a separator liquid from a two-phase separator feed, wherein the first pass is configured, in the ethane rejection arrangement, to heat the separator liquid prior to introduction of the separator liquid into the stripper; a second pass fluidly connected with the separator liquid line of the cold separator, wherein the second pass is configured, in the ethane recovery arrangement, to chill a portion the separator liquid prior to introduction of the portion of separator liquid into the absorber; and a third pass fluidly connected with an overhead vapor from the stripper and the absorber, wherein the third pass is configured, in the ethane rejection arrangement, to chill the overhead vapor from the stripper prior to passing the overhead vapor to a top of the absorber.
Also disclosed herein is a method of operating a natural gas liquids (NGL) plant to produce an NGL product, the method comprising: effecting ethane rejection from the NGL product by: producing an absorber overhead and an absorber bottoms in an absorber from an absorber feed, wherein the absorber overhead is propane depleted and the absorber bottoms is ethane rich; introducing the absorber bottoms into a stripper and producing a stripper overhead and a stripper bottoms comprising the NGL product. wherein the stripper is located downstream of the absorber and fluidly connected therewith such that the absorber bottoms can be introduced into the stripper, wherein the stripper is operated at a higher pressure than the absorber and is operated as a deethanizer to fractionate the absorber bottoms into an ethane rich stripper overhead and a stripper bottoms comprising less than 2 or 1 mole percent ethane; and utilizing the stripper overhead to reflux the absorber subsequent passage of the stripper overhead through a first pass of a multi-pass heat exchanger.
Further disclosed herein is a method of operating a natural gas liquids (NGL) plant to produce an NGL product, the method comprising: effecting ethane recovery in the NGL product by: producing an absorber overhead and an absorber bottoms in an absorber from an absorber feed; introducing the absorber bottoms into the stripper and producing a stripper overhead and a stripper bottoms comprising the NGL product in a stripper located downstream of the absorber and fluidly connected therewith such that the absorber bottoms can be introduced into the stripper, wherein the stripper is operated at substantially the same pressure as the absorber and is operated as a demethanizer to fractionate the absorber bottoms into a methane rich stripper overhead and an ethane rich stripper bottoms comprising less than 1 mole percent methane; and directing the stripper overhead to the absorber feed; separating an NGL feed comprising predominantly C1-C6 hydrocarbons, nitrogen, and other inert compounds into a separator vapor and a separator liquid; expanding a portion of the separator vapor in an expander and introducing the expanded vapor into a bottom of the absorber as the absorber feed; utilizing another portion of the separator vapor to reflux the absorber subsequent passage of the another portion through a first pass of a multi-pass heat exchanger; utilizing a portion of a residue gas obtained by compressing and heat exchanging the absorber overhead as additional reflux of the absorber after passage of the at least a portion of the residue gas through a second pass of the multi-pass heat exchanger; and introducing the separator liquid into the stripper without passing same through the multi-pass heat exchanger.
While multiple embodiments are disclosed, still other embodiments will become apparent to those skilled in the art from the following detailed description. As will be apparent, certain embodiments, as disclosed herein, are capable of modifications in various aspects without departing from the spirit and scope of the claims as presented herein. Accordingly, the detailed description hereinbelow is to be regarded as illustrative in nature and not restrictive.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures illustrate embodiments of the subject matter disclosed herein. The claimed subject matter may be understood by reference to the following description taken in conjunction with the accompanying figures, in which:

FIG. 1, which is a schematic of an NGL system 100, according to embodiments of this disclosure;

FIG. 2A is a schematic of an ethane rejection configuration 100A, according to embodiments of this disclosure;

FIG. 2B is a simplified schematic of an ethane rejection configuration 100A′, according to embodiments of this disclosure;

FIG. 3 is a schematic of an ethane recovery configuration 100B, according to embodiments of this disclosure;

FIG. 4 is a schematic of an ethane recovery operation of a conventional MRU (Mechanical Refrigeration Unit);

FIG. 5 is a heat recovery curve composite diagram for ethane rejection according to the inventive subject matter; and

FIG. 6 is a heat recovery curve composite diagram for ethane recovery according to the inventive subject matter.

Various objects, features, aspects and advantages of the present invention will become more apparent from the following detailed description of embodiments of the invention.

DETAILED DESCRIPTION

The present disclosure provides systems and methods for the recovery of ethane, propane and heavier hydrocarbons from a natural gas stream. The present disclosure provides methods and configurations of an ethane rejection process that can also be operated in ethane recovery, consisting of an absorber and a stripper that are closely coupled with a feed gas/residue gas/refrigeration/expander reflux system. In some embodiments, as detailed hereinbelow, the absorber/stripper system serves as a deethanizer during ethane rejection and a demethanizer during ethane recovery. In some embodiments, the herein-disclosed NGL recovery system (also referred to herein as an NGL recovery ‘plant’) and method can be utilized to condition a feed gas to meet sales gas heating value specifications of a resulting sales gas and/or to produce on-specification NGL products.
Herein disclosed is a natural gas liquids (NGL) plant, which is also referred to herein as an ‘NGL system’. The herein disclosed system comprises two columns, including an absorber and a stripper, and can be utilized for ethane recovery or ethane rejection, as desired. An NGL recovery plant or system will now be described with reference to FIG. 1, which is a schematic of an NGL system 100, according to embodiments of this disclosure. System 100 comprises an integrated ethane recovery/ethane rejection system.
An NGL recovery system according to this disclosure comprises a multi-pass heat exchanger, such as multi-pass heat exchanger 54 (which may also be referred to herein as a ‘feed exchanger’ 54) of the embodiment of FIG. 1, and an absorber and a stripper, such as absorber 59 and stripper 62 of the embodiment of FIG. 1. As indicated in FIG. 1, an NGL recovery system 100 according to this disclosure can further comprise an acid gas removal (AGR) unit 50, a dehydration unit 51, a feed chiller 52, a propane chiller 53, a separator 55, a turbo expander 56, a pump 60, a reboiler 63, one or more residue gas compressors 64/65, and/or a residue gas chiller 66, each of which will be described in more detail hereinbelow. System 100 further comprises associated piping and valves to control the flow throughout and/or alter pressure, for example when switching from ethane rejection to ethane recovery, as detailed hereinbelow. For example system 100 can comprise one or more of valves 70-82 and 57-58, in some embodiments. Each component of an NGL recovery system according to this disclosure will be described in more detail hereinbelow.
NGL recovery system 100 can comprise an acid gas removal or AGR unit 50. When present, AGR unit 50 is operable to produce a substantially acid-gas free gas from a feed gas introduced thereto via feed gas inlet line 1. As used herein, “Acid-gas free” is utilized to mean substantially free, or less than about 4 ppmv hydrogen sulfide (H₂S), less than about 500 ppmv carbon dioxide (CO₂), or both. AGR unit 50 serves to remove carbon dioxide, to avoid freezing of the CO₂in the downstream cryogenic process. An acid-gas free line 2 may be configured for the removal of acid-gas free feed gas from AGR unit 50. AGR 50 can be any AGR unit known in the art, for example, in some embodiments AGR 50 is selected from amine units operable via, without limitation, methyldiethanolamine (MDEA), aminoethoxyethanol (diglycolamine) (DGA), monoethanolamine (MEA) or a combination thereof
NGL recovery system 100 can further comprise a dehydration unit 51. When, present, dehydration unit 51 is operable to remove water from a gas introduced thereto. For example, dehydration unit 51 can be fluidly connected with AGR unit 50 via line 2, whereby acid-gas free feed gas (i.e., feed gas substantially free of acid gas) can be introduced into dehydration unit 51 from AGR unit 50. Dehydration unit 51 can be any apparatus known to those of skill in the art to be suitable for the removal of water from a gas stream introduced thereto. By way of example, in some embodiments, dehydration unit 51 is selected from molecular sieve dehydration units that utilize molecular sieves operable to remove water to the ppm levels. Dried, acid-gas free feed gas can be produced from dehydration unit 5 lvia dried, acid-gas free feed gas line 3. While described herein as comprising an AGR unit 50 and dehydration unit 51, such units may be optional and may not be present if the feed gas has an acid gas content below a threshold as required to avoid carbon dioxide freezing and is dried to the ppm levels of water content to meet the processing specifications.
NGL recovery system 100 can further comprise a feed gas chiller (also referred to herein as a feed gas exchanger) 52 and a multi-pass heat exchanger 54. The feed gas in line 3 can be split between two paths. First feed gas line 4 can be configured to introduce a first portion of the dried, acid-gas free feed gas from dried, acid-gas free feed gas line 3 into multi-pass heat exchanger 54, and second feed gas line 5 can be configured to introduce a second portion of the dried, acid-gas free feed gas from dried, acid-gas free feed gas line 3 into exchanger 52. A valve 77 may be positioned on second feed gas line 5 and a valve 78 positioned on first feed gas line 4 to control the flows therethrough.
Feed gas chiller or exchanger 52 is operable to chill the second portion of the dried, acid-free feed gas in second feed gas line 5 introduced thereto (e.g., via valve 77). Chiller 52 may be any heat exchanger known to those of skill in the art, and may utilize any suitable coolant. Coolant may be introduced into chiller 52 via coolant line 22A. In some embodiments, coolant line 22A is fluidly connected with a side draw stream line 22 from stripper 62, whereby at least a portion of a side draw stream in side draw stream line 22 can be utilized for heat exchange in chiller 52. A heated coolant line 23A may be fluidly connected with stripper 62, whereby the heated coolant stream can be reintroduced into stripper 62 via side draw return line 23. A chilled second portion feed gas line 6 may be configured for the removal of chilled feed gas from exchanger 52.
System 100 can further comprise a chiller 53. Chilled second portion feed gas line 6 may be configured to introduce the chilled second portion of the feed gas into the chiller 53, wherein the chilled second portion of the feed gas can be further trimmed, and a trimmed second portion feed gas line 7 can be configured for the removal of the trimmed second portion of the feed gas from chiller 53. Any suitable refrigerant can be used in the chiller 53 including hydrocarbon refrigerants. In some embodiments, chiller 53 can use propane as all or a portion of the refrigerant.
NGL recovery system or plant 100 comprises a multi-pass feed exchanger 54. Multi-pass heat exchanger 54 can be any heat exchanger known in the art that is suitable to provide the various streams described herein. In some embodiments, multi-pass heat exchanger is a brazed aluminum exchanger. Multi-pass heat exchanger 54 comprises a plurality of passes or ‘cores’, and can, in some embodiments, comprise at least five (5), six (6), or seven (7) cores. The plurality of cores may include one or more of a separator liquids core C1, a feed gas core C2, a stripper overhead or separator vapor/liquid core C3 (which may be referred to simple as a ‘stripper overhead core C3’ during ethane rejection, or a ‘separator vapor/liquid core C3’ during ethane recovery), a high pressure residue gas core C4, an absorber overhead core C5, an absorber bottoms core C6, and a refrigerant liquid core C7. Multi-pass heat exchanger 54 can utilize refrigeration content of a residue gas (e.g., high pressure residue gas in high pressure residue gas line 29, described hereinbelow), cold separator liquid (e.g., separator liquid in separator liquid line 11C, described hereinbelow), absorber bottoms (e.g., absorber bottoms in absorber bottoms line 20A described hereinbelow), external refrigerant (e.g., refrigerant, which may be propane (C3), in refrigerant line 31) and/or recycled residue gas (e.g., high pressure residue gas in high pressure residue line 29, described hereinbelow) to cool a stripper overhead (e.g., stripper overhead vapor in stripper overhead line 21A described hereinbelow) during ethane rejection or to cool the feed gas (e.g., a first portion of the separator vapor in first vapor line 13, described hereinbelow) and/or a high pressure residue gas (e.g., high pressure residue gas in high pressure residue gas recycle reflux line 16) during ethane recovery, to provide refluxes (e.g., in reflux line 17 and/or 18, described hereinbelow) to the absorber (e.g., absorber 59 described hereinbelow) for recovery of the desired components.
First feed gas line 4 may be configured to introduce the first portion of the feed gas into feed gas core C2 of multi-pass heat exchanger 54, wherein the first portion of the feed gas can be cooled. In some embodiments, system 100 comprises a high pressure residue gas line 29 fluidly connecting a cooled, compressed residue gas line 28 with first feed gas line 4, whereby a portion of the cooled, compressed residue gas in cooled, compressed residue gas line 28 can be combined with the feed gas in first feed gas line 4 for passage through feed gas core C2. Valve 79 can, in embodiments, be used to recycle the residue gas to the feed circuit, for example, during plant turndown or plant startup operation when the required feed gas flow is not available to operate turbo expander 56. Typical turndown of a turbo expander is limited to 50% of design flow. A valve 79 may be positioned on high pressure residue gas line 29 to control the flow therethrough. A cooled, first portion feed gas line 8 may be fluidly connected with trimmed second portion feed gas line 7 such that a cooled first portion of the feed gas extracted from multi-pass heat exchanger 54 via cooled, first portion feed gas line 8 can be combined with the trimmed second portion of the feed gas in trimmed second portion feed gas line 7 to provide a separator feed stream in separator feed line 9.
NGL recovery system 100 can further comprise separator 55 (also referred to herein as a ‘cold separator 55’. Separator 55 is any vapor/liquid separator known to those of skill in the art to be suitable to separate a separator feed stream introduced thereto via separator feed line 9 into a vapor stream and a liquid stream. In some embodiments, the separator 55 can be a flash tank. Vapor line 10 may be configured to remove, from separator 55, vapor separated from the separator feed, and liquid line 11 can be configured to remove, from separator 55, liquid separated from the separator feed. As discussed in more detail hereinbelow, a separator liquid line 11A may be configured to introduce (e.g., during ethane recovery) separator liquid in separator liquid line 11 into first vapor line 13 (described hereinbelow); a separator liquid line 11B may be configured to introduce (during ethane recovery) separator liquid in separator liquid line 11 into a downstream stripper 62 via stripper feed line 12; a separator liquid line 11C may be configured to pass (e.g., during ethane rejection) separator liquid in separator liquid line 11 through separator liquids core C2 of multi-pass heat exchanger 54 prior to introduction thereof into stripper 63 via stripper feed line 12. A valve 71 may be positioned on separator liquid line 11C and a valve 72 positioned on separator liquid line 11B may be configured such that, during ethane recovery, cold separator liquid in separator liquid line 11 can partially or totally bypass multi-pass heat exchanger 54 and be introduced directly into stripper 62 by closing valve 71 and opening valve 72. The extent of bypass may be dependent on the feed gas composition, as described further hereinbelow. A valve 70 may be positioned on separator liquid line 11A and configured such that, during ethane recovery, separator liquid can be introduced into absorber 59 as a component of the absorber reflux stream in absorber reflux line 17. For example, for a feed gas rich in heavy hydrocarbons (e.g., comprising greater than 5 wt % hexane and heavier), valve 70 can be partially opened to introduce separator liquid into absorber 59 and provide a sponging effect with heavy hydrocarbons for absorption of the ethane components to increase ethane recovery.
NGL recovery system 100 can comprise a first vapor line 13, and a second vapor line 14 fluidly connected with separator 55 via vapor line 10. A valve 80 may be positioned on first vapor line 13 and a valve 81 positioned on second vapor line 14 to control the flows therethrough. First vapor line 13 is configured such that vapor separated from the separator feed in separator 55 can (during ethane recovery) be passed through stripper overhead or separator vapor/liquid core C3 for chilling and introduced as reflux into absorber 59 via chilled absorber reflux line 17. Second vapor line 14 fluidly connects separator vapor line 10 with turbo expander 56, such that, during ethane rejection, all of the separator vapor in separator vapor line 10 can be introduced into turbo expander 56, and, during ethane recovery, a portion of the separator vapor in separator vapor line 10 can be introduced into turbo expander 56. As noted above, a separator liquid line 11A may fluidly connect separator liquid line 11 with first vapor line 13, whereby (during ethane recovery) separator liquid in separator liquid line 11 can be introduced into first vapor line 13 prior to passage thereof through separator vapor/liquid core C3 of multi-pass heat exchanger 54. As described in more detail hereinbelow, stripper overhead line 21A may be configured to, during ethane rejection, pass the stripper overhead vapor in stripper overhead line 21 through stripper overhead or separator vapor/liquid core C3 for chilling prior to introduction as reflux into absorber 59 via chilled absorber reflux line 17.
NGL recovery system 100 can comprise turbo expander 56. Turbo expander 56 is configured to reduce the pressure of the vapor introduced thereto via vapor line 10 and second vapor line 14 and provide an expander discharge stream. Turbo expander 56 is any expander known in the art to be operable to provide the expansion described herein while producing work. An absorber inlet line 15 can fluidly connect turbo expander 56 and absorber 59, whereby the expander discharge stream produced in turbo expander 56 can be introduced into absorber 59. A stripper overhead line 21B can fluidly connect stripper 62 with absorber inlet line 15, via stripper overhead line 21, such that (during ethane recovery) substantially all of the stripper overhead in stripper overhead line 21 can be combined with the expanded second portion of the separator vapor in second vapor line 14 via absorber inlet line 15 and introduced into absorber 59.
NGL recovery system 100 comprises absorber 59. Absorber 59 comprises any suitable column known in the art to be operable to provide the separations noted hereinbelow. Absorber inlet or feed line 15 (also referred to as ‘expander discharge line 15’) is configured to introduce an absorber feed gas comprising separator vapor from separator vapor lines 10 and/or 14 and (during ethane recovery) stripper overhead in stripper overhead line 21B into absorber 59. In some embodiments the absorber feed gas is introduced into absorber 59 at the bottom of absorber 59, e.g., at a location in the bottom one third of the absorber 59 column. Absorber reflux lines 17 and 18 are configured to introduce absorber reflux into absorber 59. Absorber reflux line 17 can introduce chilled absorber reflux in line 17 (comprising, during ethane rejection, stripper overhead passed via stripper overhead lines 21 and 21A through stripper overhead or separator vapor/liquid core C3 of multi-pass heat exchanger 54 for cooling/condensing, and comprising, during ethane recovery, the first vapor portion in first vapor line 13 and optionally the separator liquid in separator liquid line 11A passed through stripper overhead or separator vapor/liquid core C3 of multi-pass heat exchanger 54 for cooling/condensing) into a top portion of absorber 59, e.g., at a location in the top one third of the absorber 59. A cooled, high pressure residue recycle absorber reflux line 18 (also referred to herein as a ‘top’ reflux which can be introduced, during ethane recovery, above the separator vapor/liquid-derived reflux introduced via line 17) may fluidly connect multi-pass heat exchanger 54 with absorber 59 such that, during ethane recovery, following passage through high pressure residue gas core C4 of multi-pass heat exchanger 54 for cooling/condensing, the components of the high pressure residue gas recycled in high pressure residue gas recycle line 16 can be introduced into absorber 59 as reflux. A valve 82 may be positioned on high pressure residue gas recycle line 16 to control the flow therethrough. A valve 57 may be positioned on cooled, high pressure residue recycle absorber reflux line 18 to control the flow therethrough and/or adjust the pressure of the chilled absorber reflux extracted from multi-pass heat exchanger 54 via high pressure residue recycle absorber reflux line 18. A valve 58 may be positioned on absorber reflux line 17 to control the flow therethrough and/or adjust the pressure of the chilled absorber reflux extracted from multi-pass heat exchanger 54 via absorber reflux line 17. Valve 57 and/or 58 may comprise a Joule Thompson valve, in some embodiments. As the herein-disclosed ethane recovery operation can utilize a portion of the high pressure residue gas that is subcooled in multi-pass heat exchanger 54 and letdown in pressure in valve 57 as a top reflux stream to absorber 59, absorber 59 can be constructed with two reflux nozzles or injection points, with a top nozzle N1 supplied by the high pressure residue gas liquid reflux in residue gas recycle absorber reflux line 18, and the second nozzle N2 supplied by the feed liquid from the flashed vapor (e.g., from the separator vapor from separator vapor line 10/13 from cold separator 55) condensed in stripper overhead or vapor/liquid core C3 of multi-pass heat exchanger 54.
An absorber overhead line 19 can be configured to extract absorber overhead from absorber 59 and pass the absorber through absorber overhead core C5 of multi-pass heat exchanger 54 for heat exchange. One or more residue gas compressors, such as first and second residue gas compressors 64 and 65 of the embodiment of FIG. 1 can be configured to compress the residue gas following heat exchange of the absorber overhead or ‘residue gas’ in absorber overhead core C5 of multi-pass heat exchanger 54. An inter-compressor line 27 may fluidly connect first residue gas compressor 64 and second residue gas compressor 65. A residue gas chiller or heat exchanger 66 may be configured to further adjust the temperature of the residue gas, and provide a high pressure residue gas in high pressure, cooled residue gas line 28. During ethane recovery, high pressure residue gas recycle reflux line 16 and high pressure residue gas line 29 may be configured to introduce portions of the high pressure, compressed residue gas in high pressure, cooled residue gas line 28 into high pressure residue gas core C4 and feed gas core C2, respectively, of multi-pass heat exchanger 54. Remaining high pressure residue gas may be removed from NGL recovery system 100 via residue or ‘sales’ gas product line 30.
An absorber bottoms line 20 can be configured for removal of absorber bottoms from absorber 59. A pump 60 may be utilized to pump the absorber bottoms in absorber bottoms line 20 to stripper 62. An absorber bottoms stream line 20A can be configured to, during ethane rejection, pass the absorber bottoms from absorber bottoms line 20 through absorber bottoms core C6 of multi-pass heat exchanger 54 for heating thereof prior to introduction into stripper 62 via stripper feed line 20B. Valve 73 may be positioned on absorber bottoms stream line 20 and valve 74 may be positioned on absorber bottoms stream line 20A, such that, during ethane recovery, valve 73 may be opened and valve 74 may be closed and the entirety of the absorber bottoms in absorber bottoms line 20 introduced into stripper 62 via stripper feed line 20B (e.g., without passing through multi-pass heat exchanger 54) and, during ethane rejection, valve 73 may be closed and valve 74 may be opened and the entirety of the absorber bottoms in absorber bottoms line 20 passed through absorber bottoms core C6 of multi-pass heat exchanger 54 for heating thereof prior to introduction into stripper 62 via stripper feed line 20B. In some embodiments, absorber feed line 20B is configured for feeding to a top tray of stripper 62.
NGL recovery system 100 comprises stripper 62. Stripper 62 is any column known in the art to be operable to provide the streams described herein. In some embodiments, stripper 62 comprises a fractionation column. Stripper 62 is operable, in ethane recovery embodiments, as a demethanizer, and, in ethane rejection embodiments, as a deethanizer. Stripper 62 may be operable with a reboiler 63. An NGL product or ‘stripper bottoms’ line 25 is fluidly connected with a bottom of stripper 62 for the removal therefrom of a stripper bottoms comprising the NGL product. A heat source such as a hot medium, oil, or steam inlet line 24 may be configured to, in some embodiments (e.g., during ethane rejection) supplement the heat duty in reboiler/exchanger 63 for stripping the ethane content in the NGL product in NGL product or stripper bottoms stream 25 (e.g., to 1 to 2 mole percent (mol %) ethane). As mentioned hereinabove with reference to heat exchanger 52, a side draw stream line 22 can be configured for the removal of a side draw stream from stripper 62, and a side draw return stream line 23 can be configured for the reintroduction of the side draw stream to stripper 62 (e.g., after passage as coolant through heat exchanger 52 via coolant line 22A and heated coolant line 23A). Stripper overhead line 21 may be configured for the removal of stripper overhead from stripper 62. As noted previously, a stripper overhead line 21A can be configured to, during ethane rejection, pass the stripper overhead vapor in stripper overhead line 21 through stripper overhead or separator vapor/liquid core C3 for chilling prior to introduction as reflux into absorber 59 via chilled absorber reflux line 17, and a stripper overhead line 21B can fluidly connect stripper 62 with absorber inlet line 15 via stripper overhead line 21 such that (during ethane recovery) substantially all of the stripper overhead in stripper overhead line 21 can be combined with the expanded second portion of the separator vapor in second vapor line 14 and introduced into absorber 59. A valve 75 may be positioned on stripper overhead line 21A and a valve 76 may be positioned on stripper overhead line 21B to control the flow in stripper overhead lines 21A and 21B, respectively. During ethane rejection, valve 75 may be opened and valve 76 closed, such that the stripper overhead vapor in stripper overhead line 21 can be passed through stripper overhead or separator vapor/liquid core C3 for chilling prior to introduction as reflux into absorber 59 via chilled absorber reflux line 17. During ethane recovery, valve 75 may be closed and valve 76 opened, such that substantially all of the stripper overhead in stripper overhead line 21 can be combined with the expanded second portion of the separator vapor in second vapor line 14 and introduced into absorber 59.
In addition to systems or configurations for NGL recovery, the present disclosure further provides methods of operating an NGL recovery system whereby ethane rejection or ethane recovery can be effected. In some embodiments, via coupling of an absorber and a stripper with a feed gas/residue gas/refrigeration/expander reflux system, the coupled absorber/stripper can operate as a deethanizer during ethane rejection and a demethanizer during ethane recovery.
In some embodiments, during ethane rejection, the hereinbelow disclosed methods can be utilized to produce an ethane rich residue gas (e.g., residue gas in residue gas product line 30) and a propane plus NGL product (e.g., in NGL product line 25) comprising less than 1 volume percent ethane content, while during ethane recovery, the hereinbelow disclosed methods can be utilized to produce a Y-grade NGL product (e.g., in NGL product line 25) with less than 1 volume percent methane content.
A summary of the herein-disclosed methods for operating an NGL recovery plant or system will now be provided with reference to FIG. 1, and detailed descriptions of methods for ethane rejection and ethane recovery will then be made with reference to FIGS. 2A-2B and 3, respectively.
During NGL recovery, a dried feed gas (e.g., in dried acid-gas free feed gas line 3) can be split into two portions (e.g., a first portion of the feed gas in first feed gas line 4 and a second portion of the feed gas in second feed gas line 5). The feed gas in first and second feed gas lines 4 and 5 can then be chilled (e.g., in multi-pass heat exchanger 54 and in heat exchanger 52 and trimmer 53, respectively), recombined (e.g., in separator feed stream 9) and partially condensed (e.g., in vapor/liquid separator 55) forming a cold separator vapor (e.g., separator vapor in separator vapor line 10) and a cold separator liquid (e.g., separator liquid in separator liquid line 11).
The cold separator liquid can be let down in pressure (e.g., via valve 71), heated (e.g., in separator liquids core C1 of multi-pass heat exchanger 54), and fed to the stripper (e.g., introduced into stripper 62 via stripper feed line 12). During ethane rejection, 100% of the cold separator vapor (e.g., in separator vapor line 10) can be expanded in an expander (e.g., in turbo expander 56) and fed to the bottom of the absorber (e.g., to absorber 59 via absorber inlet line 15). During ethane recovery, between about 60% to 70%, on a volumetric basis, of the cold separator liquid may be sent to the expander (e.g., via second vapor line 14), and the remaining separator vapor (e.g., in first vapor line 13) can be cooled (e.g., via passage through stripper overhead or separator vapor/liquid core C3 of multi-pass heat exchanger 54) to provide reflux to the absorber (e.g., absorber reflux in absorber reflux line 17).
The absorber (e.g., absorber 59) can produce an absorber bottoms liquid (e.g., absorber bottoms in absorber bottoms line 20) that is pumped (e.g., via pump 60) and fed to the top of the stripper (e.g., to the top of stripper 62 via absorber bottoms line 20 and stripper feed line 20B). During ethane rejection, the stripper can be operated at a higher pressure than the absorber, and the stripper overhead (e.g., via stripper overhead lines 21 and 21A) can pass through the absorber reflux valve acting as a JT valve (e.g., valve 58 on absorber reflux line 17) to provide chilling for propane recovery. During ethane recovery, the stripper and absorber can be operated at about the same pressure, with the JT valve (e.g., valve 58 on absorber reflux line 17) fed by the feed gas and/or liquid (e.g., separator vapor in first separator vapor line 13 and/or separator liquid in separator liquid line 11A). Thus, during ethane rejection, the stripper overhead (e.g., via stripper overhead line 21/21A) can be chilled and partially condensed in the feed exchanger (e.g., via passage through the stripper overhead or separator vapor/liquid core C3 of multi-pass heat exchanger 54), forming a two-phase reflux to the absorber. During ethane recovery, the stripper overhead (e.g., via stripper overhead line 21/21B) can be routed to the bottom of the absorber for re-absorption of the ethane content.
During ethane rejection, the refrigerant content in the cold separator liquid (e.g., in separator liquid line 11C) and the absorber bottoms (e.g., in absorber bottoms stream line 20A) can be recovered (e.g., in multi-pass heat exchanger 54) in generating reflux for the absorber, thereby reducing the refrigeration horsepower consumption and the reboiler duty in the stripper (e.g., in stripper reboiler 63). During ethane recovery, the amount of these streams (e.g., of separator liquid stream in separator liquid line 11 and absorber bottoms in absorber bottoms line 20) introduced to the multi-pass heat exchanger (e.g., multi-pass heat exchanger 54) can be reduced or eliminated, with the majority sent directly to the stripper.
In some embodiments, the herein disclosed methods provide for ethane rejection that can achieve over 98 volume percent propane recovery while maintaining a low (e.g., less than or equal to about 1 vol %) ethane content in the propane product. The ethane content can also be adjusted by the deethanizer to meet an NGL product specification or a heating value specification of the residue gas.
In some embodiments, the herein disclosed methods provide for ethane recovery where a portion (e.g., 10 to 25 vol %) of the high-pressure residue gas (e.g., in cooled, high pressure residue gas line 28) can be recycled (e.g., via high pressure residue gas recycle line 16) and cooled (e.g., via passage through high pressure residue gas core C4 of multi-pass heat exchanger 54) to provide a top reflux (e.g., absorber reflux in high pressure residue recycle absorber reflux line 18) to the absorber. Via this operation, ethane recovery operation can provide over 98 vol % ethane recovery and at least 99 vol % propane recovery, in some embodiments.
Ethane rejection operation of the herein-disclosed NGL recovery plant or system will now be described with reference to FIG. 2A, which is a schematic of an ethane rejection configuration 100A, according to embodiments of this disclosure, and FIG. 2B which is a simplified depiction of an ethane rejection configuration 100A′. In FIG. 2A, (exclusive of within multi-pass heat exchanger 54, where all cores are indicated via dashed lines) non-operating lines are indicated via dash and closed valves via blackening of the valve symbol. As discussed further hereinbelow and depicted in FIG. 2A, during ethane rejection, lines 11A, 11B, 13, 16, 21B, and 29 may be non-operating lines; valves 57, 70, 72, 73, 76, 79, 80 and 82 may be closed and valves 58, 71, 74, 75, 77, 78 and 81 may be opened or partially opened.
Plant feed gas is introduced via plant feed gas line 1. The feed gas comprises methane, ethane, propane, and in some embodiments, heavier hydrocarbons. With respect to suitable feed gas streams, it is contemplated that different feed gas streams are acceptable, and especially feed gas streams may contain high level of ethane content. With respect to the gas compositions, it is generally suitable that the feed gas stream comprises predominantly C1-C6 and heavier hydrocarbons, and may further comprise nitrogen and/or other inert compounds. Suitable feed gas streams include conventional and unconventional gases, such as shale gases, associated and non-associated gases from oil and gas production. In some embodiments, the plant feed gas comprises ethane and hydrocarbons liquids content in a range of from about 6 to about 10 GPM (gallons of liquid per thousand standard cubic feet of gas). As utilized herein, the term “about” in conjunction with a numeral refers to that numeral +/−10, inclusive. For example, where a temperature is “about 100° F.”, a temperature range of 90-110° F., inclusive, is contemplated.
The plant feed gas may be supplied at a pressure in the range of from about 600 to about 1000 psig (from about 4.1 to about 6.9 MPa), from about 650 to about 850 psig (from about 4.5 to about 5.9 MPa), or from about 800 to about 1100 psig (from about 5.5 to about 7.6 MPa), or a pressure of greater than or equal to about 600, 850, or 1100 psig (4.1, 4.5, or 5.5 MPa). The plant feed gas may be supplied at a temperature in the range of from about 60 to about 130° F. (from about 15 to about 54° C.), from about 50 to about 85° F. (from about 10 to about 29° C.), or from about 85 to about 130° F. (from about 29 to about 54° C.), or a temperature of greater than or equal to about 50, 85, or 120° F. (10, 29, or 49° C.), The feed gas may be treated for acid gas removal in AGR unit 50. The substantially acid-gas free feed gas may be introduced into dehydration unit 51, for example via acid-gas free feed line 2. Within dehydration unit 51, the feed gas can be dried to meet processing thresholds, thus producing a dried, acid-gas free gas to the NGL recovery unit. The dried, acid-gas free feed gas in dried, acid-gas free feed gas line 3 can be split into two portions, a first feed gas portion in first feed gas line 4 and a second feed gas portion in second feed gas line 5. The volumetric flow ratio between first and second feed gas lines 4 and 5 depends on the feed gas richness and supplied pressure. For rich gas (feed gas with 25% volume C3 and heavier liquids), more gas flow is directed to second feed gas line 5, and less flow is directed towards first feed gas line 4. This operation is to provide additional chilling in exchanger 52 and chiller 53 to condense the heavy hydrocarbons. In such embodiments, the flow ratio of the first feed gas portion in first feed gas line 4 to the total flow in dried, acid-gas free feed gas line 3 can be less than or equal to about 0.7. For lean gas (feed gas with 6% C3+liquid or lower), most of the feed gas will pass to first feed gas line 4, and less flow will pass to second feed gas line 5. In such embodiments, the flow ratio of the first portion of the feed gas in first feed gas line 4 to the total flow in dried, acid-gas free feed gas line 3 can be 0.9 or higher. As needed for processing the prospective feed gas, valves 77 and 78 can be operated to control the optimum flow rates through first and second feed gas lines 4 and 5, respectively.
The first feed gas portion in first feed gas line 4 can be chilled via passage through feed gas core C2 of multi-pass heat exchanger, providing a cooled first portion of the feed gas in line 8, while the second feed gas portion in second feed gas line 5 can be chilled by passage through exchanger 52. Heat exchanger 52 may utilize heat from a side draw stream 22 from stripper 62. From heat exchanger 52, cooled second portion of the feed gas passes, via chilled second portion feed gas line 6, into propane chiller 53. The second portion of the feed gas can be further trimmed by passage through propane chiller 53, forming a trimmed second portion of the feed gas in line 7. The trimmed second portion of the feed gas in trimmed second portion feed gas line 7 can be combined with the cooled first portion of the feed gas in cooled first portion feed gas line 8, to form separator feed stream in separator feed stream line 9. The separator feed stream may have a temperature of less than or equal to about 10, 20, or 35° F. (−12, −7, or −37° C.).
Within separator 55, the separator feed stream can be separated into a vapor stream, which can be extracted from separator 55 via separator vapor line 10, and a liquid stream, which can be extracted from separator 55 via separator liquid line 11. The vapor stream in separator vapor line 10 can be let down in pressure in turbo expander 56, for example, to less than or equal to about 250, 300, or 350 psia (1.7, 2.1, or 2.4 MPa), chilled to less than or equal to about −60, −80, or −100° F. (−51, −62, or −73° C.), prior to being introduced into absorber 59.
The separator liquid in separator liquid line 11 can be let down in pressure, for example, via valve 71, and chilled to, for example, less than or equal to about −40, −60, or −75° F. (−40, −51, or −59° C.). The separator liquid in separator liquid line 11C may be heated via passage through separator liquids core C1 of multi-pass heat exchanger 54 to, for example, greater than or equal to about 30, 50, or 70° F. (−1, 10, or 21° C.) prior to being introduced into stripper 62 via stripper feed line 12.
During the ethane rejection operation, the second column or stripper 62 acts as a deethanizer, and can operate at a higher pressure than absorber 59. For example, in some embodiments, stripper 62 can be operated at a pressure that is in the range of from 30 to 150 psi (0.2 to 1.05 MPa) or at least about 30, 75, or 150 psi (0.2, 0.5, or 1.05 MPa) higher than a pressure at which the absorber is operated. During ethane rejection, stripper 62 produces a stripper bottoms in stripper bottoms line 25 that comprises propane plus NGL, and an overhead vapor in stripper overhead line 21. In some embodiments, a heat medium such as hot oil or steam (indicated at line 24) can be utilized to supplement the heating duty in reboiler/exchanger 63, for stripping the ethane content in the NGL product in stripper bottoms line 25 to an ethane content in the range of from about 1 to about 2 mole percent (mol %), from about 2 to about 10 mol %, from about 10% to about 20 mol %, or less than or equal to about 1%, 2%, or 10% mol %. The extent of stripping and ethane content in the NGL are set by the NGL product specification and/or the sales gas heating value specification. For example, if there are no markets for the ethane product, stripping can be increased to produce an NGL with very low ethane content, such that the NGL can be sold as a liquid fuel product. However, if feed gas contains a significant amount of ethane, sufficient ethane can be removed from the residue gas such that the sales gas heating value can be met. In this case, more ethane will be contained in the NGL by operating the stripper at a lower bottom temperature.
During ethane rejection, the stripper overhead vapor stream in stripper overhead line 21 can be routed to multi-pass heat exchanger 54 via stripper overhead line 21A (via opening of valve 75 being open and closing of valve 76), whereby the stripper overhead vapor can be chilled via passage through stripper overhead or separator vapor/liquid core C3 of multi-pass heat exchanger 54, and let down in pressure via Joule Thompson (JT) valve 58, chilled (e.g., to a temperature of less than or equal to about −50, −75, or −95° F. (−46, −59, or −71° C.)) prior to feeding the absorber as reflux via absorber reflux line 17. Absorber 59 can be operated, during ethane rejection, to produce an ethane rich absorber bottoms extracted via absorber bottoms line 20 and a propane depleted absorber overhead vapor extracted via absorber overhead line 19. In some embodiments, the absorber bottoms in absorber bottoms line 20 can be pumped by pump 60 and absorber bottoms line 20A, heated via passage through absorber bottoms core C6 of multi-pass heat exchanger 54 to about −30° F., forming stripper feed in stripper feed line 20B prior to feeding to the top tray of the stripper. In some embodiments, the absorber bottoms stream extracted from absorber 59 via absorber bottoms line 20 has a temperature of less than or equal to about −50, −75, or −95° F. (−46, −59, or −71° C.).
Absorber overhead is produced from absorber 59 via absorber overhead line 19. The absorber overhead may be passed through absorber overhead core C5 of multi-pass heat exchanger 54. Following passage through multi-pass heat exchanger 54, the absorber overhead may be compressed, for example, via introduction of line 26 into first residue gas compressor 64, and introduction of the compressed residue gas from first residue gas compressor 64 into second residue gas compressor 65 via inter-compressor line 27. In embodiments, horsepower to residue gas compressor 64 is provided by the power generated from expander 56, such that the power consumption can be reduced. The compressed residue gas may be cooled via passage through residue gas chiller or heat exchanger 66, and a cooled, high pressure residue gas can be extracted from residue gas chiller 66 via cooled, compressed residue gas line 28. Residue gas may be removed from the process via a residue gas product line 30.
During ethane rejection, the herein-disclosed system and method can be utilized to reject ethane while maintaining over 98 vol % propane recovery.
As discussed in Example 1 hereinbelow, the heat recovery efficiency of the ethane rejection process is shown in FIG. 5, which is a heat recovery curve composite diagram for ethane rejection, and the overall heat and material balance table is shown in Table 2.
The ethane rejection operation can be compared to a conventional MRU (Mechanical Refrigeration Unit), as depicted in FIG. 4, which is a schematic of an ethane recovery operation of a conventional MRU 200, in terms of recoveries, refrigeration duty and power consumption, for the feed gas conditions as shown in Table 1 as follows. The comparison basis is for producing a y-grade NGL with 1 volume % methane content. Conventional MRU 200, as shown in FIG. 4, typically comprises feed exchangers 152A/152B (which may be downstream of a dehydrator 151), propane chiller 153, cold separator 155, JT valve 156, and a stripper 162 (with reboiler 163) that rejects the methane content back to the sales gas (which is compressed via compressor 164). In some embodiments of this disclosure, the application of turbo expander 56 is an efficient method as the expander cools the feed gas, and at the same time, produces power to operate the residue gas compressor 64, reducing the overall power consumption and the refrigeration requirement. With respective to the advantage of the stripper recycle operation, the herein disclosed process may be operable to achieve 98% propane recovery, compared to the conventional MRU system which may typically only be operable to achieve about 46% propane recovery.

TABLE 1

Ethane Rejection Operation Comparison

	Conventional	Herein Disclosed NGL
	MRU	System/Method

Ethane recovery

	12%	15%
Propane recovery	46%	98%
Refrigeration duty, MMBtu/h	9.7	8.2
Refrigeration Horsepower	2,600	2,200
NGL production, BPD	9,800	15,000

Via the herein disclosed operation, the incremental increase in NGL recovery amounts to 5,200 barrel per day. Even with a conservative estimate of liquid valued at $30 per barrel, the economic incentive may be about $57 MM per year. The herein-disclosed process may thus provide a significant income to the gas plant. The power consumption and hot oil duty are slightly less than the MRU design, which would reduce the capital and operating costs of the plant.
It should be noted that the feed gas liquid composition as shown in Table 1 is about 5.6 GPM C2+. If the feed gas were richer, as most shale gas liquid content can be as high as 10 GPM, the increase in y-grade NGL production may further increase, providing a concomitant increase the production revenue from the gas plant.
Ethane recovery operation of the herein-disclosed NGL recovery plant or system will now be described with reference to FIG. 3, which is a schematic of an ethane recovery configuration 100B, according to embodiments of this disclosure. In FIG. 3, (exclusive of within multi-pass heat exchanger 54, where all cores are indicated via dashed lines) non-operating lines are indicated via dash and closed valves via blackening of the valve symbol. As discussed further hereinbelow and depicted in FIG. 3, during ethane recovery, lines 11C, 20A, and 21A may be non-operating lines; valves 71, 74, and 75 may be closed and valves 57, 58, 70, 72, 73, 76, 77, 78, 79, 80, 81, 82 may be opened or partially opened.
Operating an NGL recovery plant of this disclosure via the ethane recovery method provided herein may enable recovery of at least about 98 vol % of the ethane in the feed stream while maintaining a recovery of propane from the feed stream that is at least about 97, 98, or 99 vol %. During ethane recovery operation, the stripper 62 can be operated as a demethanizer to provide a stripper bottoms product in stripper bottoms line 25 comprising the ethane plus NGL, and a stripper overhead gas in stripper overhead line 21, with the stripper overhead being routed to the bottom of the absorber via stripper overhead line 21B (via opening of valve 76 being open and closing of valve 75).
Operation of the front section of the herein-disclosed NGL recovery system during ethane recovery remains the same as described hereinabove for the ethane rejection operation. However, the separator vapor fed to expander 56 via second vapor line 14, is reduced to between about 60 vol % to 70 vol % of the separator vapor in separator vapor line 10, with the remainder or first portion of the separator vapor being introduced into multi-pass heat exchanger 54 via first vapor line 13. During ethane recovery, the first separator vapor stream in first vapor line 13 is further cooled via passage through stripper overhead or separator vapor/liquid core C3 of multi-pass heat exchanger 54, to supply a subcooled reflux to the absorber via absorber reflux line 17. During ethane recovery, absorber 59 can produce an absorber overhead extracted via absorber overhead line 19 and an absorber bottoms stream extracted via absorber bottoms line 20. In some embodiments, during ethane recovery, the absorber overhead has a temperature of less than or equal to about −60, −85, −135° F. (−51, −65, 93° C.) and/or the absorber bottoms has a temperature of less than or equal to about −60, −85, −135° F. (−51, −65, −93° C.).
During the ethane recovery operation, the cold separator liquid in separator liquid line 11 is partially or totally bypassed around multi-pass heat exchanger 54 and directed to the stripper by closing valve 71 and opening valve 72. The extent of bypass is dependent on the feed gas composition. For a feed gas rich in heavy hydrocarbons (e.g., comprising greater than about 5 vol % hexane and heavier), valve 70 can be partially opened to provide a sponging effect with heavy hydrocarbons for absorption of the ethane components to increase ethane recovery. That is, when the feed gas contains more hexane, heptane, octane and/or heavier hydrocarbons, most of these heavy hydrocarbons will drop out in separator 55, and can be used for the absorption of ethane from the feed gas. This can be referred to as a ‘sponging effect’ which can further increase the overall ethane recovery, without concomitantly increasing power consumption.
The absorber bottoms stream in absorber bottoms line 20 can be partially or totally bypassed around multi-pass heat exchanger 54 and directed to the top of stripper 62 by closing valve 74 and opening valve 73. The extent of bypass can depend on the feed gas composition.
For ethane recovery of greater than or equal to 98%, from about 15 vol % to about 25 vol % of the high-pressure residue gas in high pressure residue gas line 28 may be recycled via high pressure residue gas recycle reflux line 16. The high pressure residue gas recycled as reflux can be cooled and condensed via passage through high pressure residue gas core C4 of multi-pass heat exchanger 54, and introduced as reflux via cooled, high pressure residue recycle absorber reflux line 18, to generate a methane rich (e.g., comprising less than 0.3, 0.2, or 0.1% ethane, based on the amount of ethane and methane in the reflux) lean reflux to the top of absorber 59. In some embodiments, the amount of residue gas recycled via residue gas recycle reflux line 16 and/or high pressure residue gas line 29 during ethane recovery is less than or equal to about 10 vol %, 15 vol %, 20 vol %, or 25 vol % of the total residue flow in residue gas line 28.
During ethane recovery operation, stripper 62 can fractionate the absorber bottoms introduced thereto via absorber bottoms line 20 and 20B into an ethane rich bottoms stream in stripper bottoms line 25, and an overhead vapor stream in stripper overhead line 21. Via closing of valve 75 and opening of valve 76, the stripper overhead vapor in stripper overhead line 21 can be mixed with the expander discharge in expander discharge line 15 and fed to the bottom of absorber 59. Ethane recovery as per this disclosure may provide a stripper bottoms or NGL product comprising ethane plus NGL and less than or equal to about 1, 0.5, or 0.25 mole % methane. This ethane recovery product may thus meet the specification for Y-grade NGL.
During plant turndown operation (e.g., during ethane recovery operation when a first portion of the feed gas is diverted away from expander 56 via first vapor line 13), a portion of the high-pressure residue gas in high pressure residue gas line 28 can diverted by opening valve 79 so that some of the residue gas is introduced via high pressure residue gas line 29 to the feed gas pass or core C2 of multi-pass heat exchanger 54 such that a minimum flow to the expander 56 can be maintained. For example, in some embodiments, to operate expander 56, a minimum flow of 50 vol % of the design flow may be needed.
During ethane recovery, the herein-disclosed system and method can be utilized to achieve at least 98 vol % ethane recovery and at least 99 vol % propane recovery.
As discussed in Example 2 hereinbelow, the heat recovery efficiency of the ethane recovery process is shown in heat composite curve in FIG. 6, which is a heat recovery curve composite diagram for ethane recovery, and the overall heat and material balance table is shown in Table 3.
With respect to switching the operation from ethane rejection (as depicted in and described with reference to the embodiments of FIGS. 2A and 2B), to the ethane recovery operation (as depicted in and described with reference to the embodiment of FIG. 3), FIG. 3 shows the lines and valves that are to be closed during the ethane recovery operation. The switching operation can, in embodiments, provide an innovative method that allows a seamless transition sequence from ethane rejection mode with intermediate ethane recovery to a high ethane recovery mode using residual gas reflux to achieve over 98% ethane recovery.
With reference again to FIG. 3, introduction of the stripper overhead vapor in stripper overhead line stream 21 from stripper 62 into absorber 59 via stripper overhead line 21A is effected by opening valve 76 and closing valve 75, thus stopping the flow of stripper overhead vapor to multi-pass heat exchanger 54 via stripper overhead line 21A. Cold separator liquid in cold separator liquid line 11 is directed to stripper 62 via separator liquid line 11B by opening valve 72 and closing valve 71, thus stopping the flow of separator liquid to multi-pass heat exchanger 54 via separator liquid line 11C and bypassing the multi-pass heat exchanger. Valve 70 may be open, to provide a sponging effect for ethane, as noted above, or may be closed. In some embodiments, such as for feed gas with lower C6+content, separator liquid line 11A and valve 70 are absent. Via opening of valve 80 (and maintaining open or opening valve 81) separator vapor in separator vapor line 10 from cold separator 55 is split into two portions: first portion or vapor stream 13 flows to multi-pass heat exchanger 54 for use as absorber reflux, while the remaining separator vapor flow is routed, via second portion or vapor line 14, to expander 56 for cooling. In some embodiments, the second portion in second vapor line 14 comprises from about 50 to 70 vol % of the separator vapor, while the first portion in first vapor line 13 comprises the remainder of the separator vapor flow in vapor line 10. For ethane recovery, valve 82 may be opened, allowing a portion of the high pressure residue gas in high pressure residue gas line 28 to pass through high pressure residue gas core C4 of multi-pass heat exchanger 54 prior to introduction as a top reflux to absorber 59 via top reflux line 18. In some embodiments, from about 10 vol % to about 25 vol % of the residue gas in high pressure residue gas line 28 is utilized as reflux for the absorber during ethane recovery.
Conversely, with respect to switching the operation from ethane recovery (as depicted in and described with reference to the embodiment of FIG. 3), to the ethane rejection operation (as depicted in and described with reference to the embodiment of FIGS. 2A and 2B), FIG. 2A shows the lines and valves that are to be closed during the ethane rejection operation. With reference again to FIG. 2A, introduction of the stripper overhead vapor in stripper overhead line stream 21 from stripper 62 into absorber 59 via stripper overhead line 21A is effected by opening valve 75 and closing valve 76, thus stopping the flow of stripper overhead vapor to absorber inlet line 15 via stripper overhead line 21A, and directing the stripper overhead vapor to stripper overhead or separator vapor/liquid core C3 of multi-pass heat exchanger 54. Cold separator liquid in cold separator liquid line 11 is directed to stripper 62 via separator liquid line 11C by opening valve 71 and closing valve 72, thus introducing the flow of separator liquid to separator liquid core C1 of multi-pass heat exchanger 54. By closing valve 80 and keeping valve 81 open, the entirety of the separator vapor flow in separator vapor line 10 from cold separator 55 can be directed, via second portion or vapor line 14, to expander 56 for cooling during ethane rejection.
Although the methods described herein utilize a turbo expander and refrigeration for chilling of a feed gas that can use propane, other cooling methods may be utilized, in some embodiments, and such methods are within the scope of this disclosure.
The NGL recovery methods and configurations disclosed herein can be utilized in a new grass-root installation and/or in retrofitting existing plants for high ethane and/or propane recovery. In some embodiments, portions of the herein-disclosed NGL recovery systems and methods are applied to retrofitting NGL recovery plants for high propane and ethane recovery. For example, retrofitting may include the use of the herein-disclosed multi-pass heat exchanger 54 to allow closer temperature approaches among different cooling and heating streams. In some embodiments, multi-pass heat exchanger 54 of this disclosure comprises a refrigerant core or pass C7. In some embodiments, the refrigerant comprises propane, such that the multi-pass heat exchanger provides a propane chiller pass. Such a chiller pass can open up the temperature approaches among heat curves, resulting in lowering the reflux liquid temperature to the absorber 59, in some embodiments. As noted hereinabove, the close temperature approaches are shown in FIG. 5 and FIG. 6.
Systems and methods for producing a natural gas liquids stream as disclose herein provide a plant comprising two columns, an absorber and a stripper, that can be utilized for ethane recovery and/or ethane rejection. In some embodiments, the stripper operates as a deethanizer during ethane rejection and a demethanizer during ethane recovery. In some embodiments, ethane rejection according to this disclosure comprises diverting the stripper overhead vapor to reflux the absorber, and ethane recovery according to this disclosure comprises routing the stripper overhead vapor to the bottom of the absorber and splitting portions of the feed gas to the turbo expander, with addition of a residue gas recycle stream to provide additional reflux to the absorber.
In some embodiments, during ethane recovery, the herein-disclosed process can provide at least 98% ethane recovery and at least 99% propane recovery, and, during ethane rejection, the herein-disclosed process can be utilized to reject ethane while maintaining over 98% propane recovery. In some embodiments, the herein-disclosed system and method employ turbo expander and propane refrigeration for chilling. The herein-disclosed system and method can enable and/or employ re-routing the stripper overhead vapor to switch from ethane rejection to ethane recovery: for ethane rejection, the herein-disclosed system and method can comprise diverting the stripper overhead vapor to reflux the absorber to increase the absorption of propane during ethane rejection; for ethane recovery, the herein-disclosed system and method can comprise rerouting the stripper overhead vapor for combination with the expander discharge to the bottom of the absorber, to increase ethane absorption, optionally with the addition of a residue gas recycle stream for additional reflux to the absorber.
In some embodiments, the herein-disclosed ethane recovery operation utilizes a portion of the high pressure residue gas that is subcooled and letdown in pressure to the absorber as a top reflux stream to the absorber. The absorber can thus be constructed with two reflux nozzles, with the top nozzle supplied by the high pressure residue gas liquid, and the second nozzle supplied by the feed liquid from the flashed vapor condensed from the cold separator.
With regards to turndown capability, the integrated solution provided via the herein-disclosed system and method allows plant feed gas flow to be reduced, in some embodiments to below that of a typical expander plant. Typical expander plants are limited to 50 vol % turndown due to machinery aerodynamics; below the 50% point, expander operation may be stopped and bypassed, and consequently, NGL recoveries may be reduced. Via the herein-disclosed system and method, the residue gas recycle (e.g., high pressure residue gas line 29) can be utilized (e.g., by opening valve 79) to increase the feed gas flow to the expander (e.g., turbo expander 56) allowing the expander to operate at the optimum conditions. With such configuration, NGL recoveries can, in some embodiments, be higher than that obtained with conventional designs.
With respect to the switching operation, it provides, in embodiments, an innovative method that allows a seamless transition sequence from ethane rejection mode with intermediate ethane recovery to a high ethane recovery mode using residual gas reflux to achieve over 98% ethane recovery. As such, the ethane recovery levels can be varied from 1% to up to 98%, while maintaining propane recovery to over 98% in any operation. The methods and configurations are application for various feed gas compositions and conditions, particularly for the unconventional gas with high liquid contents.

EXAMPLES

The embodiments having been generally described, the following examples are given as particular embodiments of the disclosure and to demonstrate the practice and advantages thereof. It is understood that the examples are given by way of illustration and are not intended to limit the specification or the claims in any manner.

Example 1

Heat recovery Efficiency During Ethane Rejection

The heat recovery efficiency of the ethane rejection process was determined by modeling (using Aspen Hysys V9 or ProMax simulation software), and the results of the model are shown in the heat composite curves of FIG. 5, with the hot composite indicated with squares and the cold composite indicated with triangles. The overall heat and material balance table for ethane rejection, calculated by the model, is shown in TABLE 2.

TABLE 2

Heat and Material Balance for Ethane Rejection

Mole %	Feed	Residue Gas	NGL

N2	0.81	0.92	0.00
CO2	1.51	1.70	0.00
C1	74.64	84.23	0.00
C2	12.83	13.05	11.06
C3	6.30	0.09	54.59
IC4	0.85	0.00	7.45
NC4	1.91	0.00	16.80
IC5	0.38	0.00	3.30
NC5	0.41	0.00	3.56
C6+	0.37	0.00	3.25
Pressure, psia (MPa)	897 (6.2)	394 (2.7)	358 (2.5)
Temperature, ° F. (° C.)	121 (49.4)	154 (67.8)	166 (74.4)
MMscfd	300	265	34
Barrel per day (BPD)			23,459

Example 2

Heat recovery Efficiency During Ethane Recovery

The heat recovery efficiency of the ethane recovery process was determined by Aspen Hysys V9, and is shown in the heat composite curves of FIG. 6, with the hot composite indicated with squares and the cold composite indicated with triangles. The overall heat and material to balance table for ethane rejection, calculated by Aspen Hysys V9, is shown in TABLE 3.

TABLE 3

Heat and Material Balance for Ethane Recovery

	Mole %	Feed	Recycle	Residue Gas	NGL

N2	0.85	1.08	1.08	0.00
CO2	0.01	0.01	0.01	0.02
C1	77.78	98.45	98.45	0.73
C2	13.01	0.47	0.47	59.77
C3	5.79	0.00	0.00	27.39
iC4	0.66	0.00	0.00	3.14
NC4	1.37	0.00	0.00	6.47
iC5	0.20	0.00	0.00	0.96
NC5	0.20	0.00	0.00	0.93

TABLE 3

Heat and Material Balance for Ethane Recovery

Mole %	Feed	Recycle	Residue Gas	NGL

C6+	0.12	0.00	0.00	0.58

Pressure, psia (MPa)	899	(6.2)	1,220	(8.4)	1,220	(8.4)	487	(3.4)
Temperature, ° F. (° C.)	122	(50.0)	120	(48.9)	120	(48.9)	105	(40.6)

MMscfd

300

55

237

63

Barrel per day							39,424

Having described various systems and processes herein, specific embodiments or aspects can include, but are not limited to:
A: A natural gas liquids (NGL) plant, the NGL plant comprising: an absorber configured to provide an absorber overhead and an absorber bottoms; a stripper configured to produce a stripper overhead and a stripper bottoms, wherein the stripper is positioned downstream from the absorber and fluidly connected therewith such that the absorber bottoms can be introduced into the stripper; and a multi-pass heat exchanger configured to provide at least one reflux stream to the absorber, wherein the absorber and stripper are configured, in an ethane rejection arrangement, to provide the stripper overhead to a top of the absorber, and wherein the absorber and stripper are configured, in an ethane recovery arrangement, to provide the stripper overhead to a bottom of the absorber.
B: A method of operating a natural gas liquids (NGL) plant to produce an NGL product, the method comprising: operating the NGL plant in an ethane rejection mode, wherein operating in the ethane rejection mode comprises: producing, with an absorber, an absorber overhead stream and an absorber bottoms stream, introducing the absorber bottoms stream into a stripper; producing, with the stripper, a stripper overhead stream and a stripper bottoms stream while operating the stripper at a higher pressure than the absorber, wherein the stripper bottoms stream comprises the NGL product; and chilling the stripper overhead stream to produce a chilled stripper overhead stream; passing the chilled stripper overhead stream to a top of the absorber to reflux the absorber; operating the NGL plant in an ethane recovery mode, wherein operating in the ethane recovery mode comprises: producing, with the absorber, the absorber overhead stream and the absorber bottoms stream; introducing the absorber bottoms stream into the stripper; producing, with the stripper, the stripper overhead stream and the stripper bottoms stream, wherein the stripper bottoms stream comprises the NGL product; and passing the stripper overhead stream to a bottom of the absorber.
C: A multi-pass heat exchanger configured to provide reflux to an absorber of a natural gas liquids (NGL) plant comprising the absorber and a stripper, wherein the NGL plant is configured to selectively operate in an ethane recovery arrangement or an ethane rejection arrangement, wherein the multi-pass heat exchanged comprises: a first pass fluidly connected with a separator liquid line of a cold separator, wherein the cold separator is configured to separate a separator liquid from a two-phase separator feed, wherein the first pass is configured, in the ethane rejection arrangement, to heat the separator liquid prior to introduction of the separator liquid into the stripper; a second pass fluidly connected with the separator liquid line of the cold separator, wherein the second pass is configured, in the ethane recovery arrangement, to chill a portion the separator liquid prior to introduction of the portion of separator liquid into the absorber; and a third pass fluidly connected with an overhead vapor from the stripper and the absorber, wherein the third pass is configured, in the ethane rejection arrangement, to chill the overhead vapor from the stripper prior to passing the overhead vapor to a top of the absorber.
D: A method of operating a natural gas liquids (NGL) plant to produce an NGL product, the method comprising: effecting ethane rejection from the NGL product by: producing an absorber overhead and an absorber bottoms in an absorber from an absorber feed, wherein the absorber overhead is propane depleted and the absorber bottoms is ethane rich; introducing the absorber bottoms into a stripper and producing a stripper overhead and a stripper bottoms comprising the NGL product. wherein the stripper is located downstream of the absorber and fluidly connected therewith such that the absorber bottoms can be introduced into the stripper, wherein the stripper is operated at a higher pressure than the absorber and is operated as a deethanizer to fractionate the absorber bottoms into an ethane rich stripper overhead and a stripper bottoms comprising less than 2 or 1 mole percent ethane; and utilizing the stripper overhead to reflux the absorber subsequent passage of the stripper overhead through a first pass of a multi-pass heat exchanger.
E: A method of operating a natural gas liquids (NGL) plant to produce an NGL product, the method comprising: effecting ethane recovery in the NGL product by: producing an absorber overhead and an absorber bottoms in an absorber from an absorber feed; introducing the absorber bottoms into the stripper and producing a stripper overhead and a stripper bottoms comprising the NGL product in a stripper located downstream of the absorber and fluidly connected therewith such that the absorber bottoms can be introduced into the stripper, wherein the stripper is operated at substantially the same pressure as the absorber and is operated as a demethanizer to fractionate the absorber bottoms into a methane rich stripper overhead and an ethane rich stripper bottoms comprising less than 1 mole percent methane; and directing the stripper overhead to the absorber feed; separating an NGL feed comprising predominantly C1-C6 hydrocarbons, nitrogen, and other inert compounds into a separator vapor and a separator liquid; expanding a portion of the separator vapor in an expander and introducing the expanded vapor into a bottom of the absorber as the absorber feed; utilizing another portion of the separator vapor to reflux the absorber subsequent passage of the another portion through a first pass of a multi-pass heat exchanger; utilizing a portion of a residue gas obtained by compressing and heat exchanging the absorber overhead as additional reflux of the absorber after passage of the at least a portion of the residue gas through a second pass of the multi-pass heat exchanger; and introducing the separator liquid into the stripper without passing same through the multi-pass heat exchanger.
Each of embodiments A, B, C, D, and E may have one or more of the following additional elements:
Element 1: wherein the multi-pass heat exchanger is configured, in the ethane recovery arrangement, to provide at least two reflux streams to the absorber. Element 2: wherein the stripper is configured, in the ethane recovery arrangement, as a demethanizer to provide a stripper bottoms comprising less than 1 vol % methane, and the stripper is configured, in the ethane rejection arrangement, as a deethanizer to provide a stripper bottoms comprising less than 2 mole percent ethane. Element 3: further comprising: a cold separator configured to separate a two-phase separator feed into a separator vapor and a separator liquid, wherein the cold separator is fluidly connected with the absorber, wherein the cold separator is configured, in the ethane rejection arrangement, to route the separator vapor to the bottom of the absorber. Element 4: wherein the cold separator is configured, in the ethane recovery arrangement, to pass a first portion of the separator vapor to the absorber through a first pass of the multi-pass heat exchanger, and to pass a second portion of the separator vapor to the bottom of the absorber. Element 5: further comprising: an expander in fluid communication with a bottom portion of the absorber, wherein the expander is configured, in the ethane rejection arrangement, to produce an expander discharge from the separator vapor, and wherein the expander is configured, in the ethane recovery arrangement, to produce the expander discharge from the second portion of the separator vapor.
Element 6: wherein the cold separator is configured to pass at least a portion of the separator liquid through a second pass of the multi-pass heat exchanger prior to introduction into the stripper. Element 7: wherein the cold separator is configured, in an ethane recovery arrangement, to pass a first portion of the separator liquid through a second pass of the multi-pass heat exchanger prior to introduction into the absorber, and to pass a second portion of the separator liquid directly to the stripper. Element 8: wherein the multi-pass heat exchanger comprises a pass configured to chill a first portion of an NGL feed gas and provide at least a portion of the two-phase separator feed. Element 9: further comprising a heat exchanger and propane chiller configured to chill a second portion of the NGL feed gas to provide at least another portion of the two-phase separator feed. Element 10: further comprising: one or more residue gas compressors configured to compress the absorber overhead to produce a compressed residue gas, wherein the NGL plant is configured, in the ethane recovery operation, to expand and pass a portion of the compressed residue gas via the multi-pass exchanger into a top of the absorber. Element 11: wherein operating the NGL plant in the ethane rejection mode further comprises: separating an NGL feed into a separator vapor stream and a separator liquid stream; expanding the separator vapor stream in an expander; introducing the expanded vapor into a bottom of the absorber as the absorber feed; passing the separator liquid through a pass of a multi-pass heat exchanger; and passing the separator liquid into the stripper downstream of the multi-pass exchanger, wherein the temperature of the separator liquid is increased in the multi-pass exchanger prior to introduction into the stripper. Element 12: wherein operating the NGL plant in the ethane recovery mode further comprises: separating an NGL feed into a separator vapor and a separator liquid; expanding a first portion of the separator vapor in an expander and introducing the expanded vapor into a bottom of the absorber as the absorber feed; chilling a second portion of the separator vapor to provide a chilled second portion of the separator vapor; refluxing the absorber with the chilled second portion of the separator vapor; compressing and heat exchanging the absorber overhead stream to produce a residue gas stream; using a portion of the residue gas stream as reflux in the absorber after passage of the portion of the residue gas stream through a pass of a multi-pass heat exchanger; and introducing the separator liquid into the stripper without passing the separator liquid through the multi-pass heat exchanger. Element 13: wherein the first portion of the separator vapor is between 50 to 70 mole percent (mol %) of the separator vapor. Element 14: wherein the third pass is further fluidly connected with a separator vapor line of the cold separator, wherein the cold separator is configured to separate a separator vapor from the two-phase separator feed, wherein the third pass is configured, in the ethane recovery arrangement, to chill at least a portion of the separator vapor and pass the chilled separator vapor to the top of the absorber. Element 15: further comprising: a fourth pass fluidly connected with a cooled high pressure residue gas line comprising an overhead product from the absorber, wherein the fourth pass is configured, in the ethane recovery arrangement, to chill at least a portion of the high pressure residue gas in the high pressure residue gas line and pass the chilled portion of the high pressure residue gas as reflux to the absorber. Element 16: further comprising: a fifth pass fluidly connected with a feed gas line comprising a feed gas, wherein the fifth pass is configured to chill at least a portion of the feed gas prior to introduction of the portion of the feed gas to the cold separator; a sixth pass a pass fluidly connected with a refrigerant line, wherein the sixth pass is configured to chill one or more fluids passing through the multi-pass heat exchanger; and a seventh pass fluidly connected with an absorber overhead line, wherein the seventh pass is configured to provide heat exchange between an absorber overhead stream in the absorber overhead line with the one or more fluids passing through the multi-pass heat exchanger. Element 17: wherein the multi-pass heat exchanger is configured, in the ethane rejection arrangement, to provide a single reflux stream to the absorber, and wherein the multi-pass exchanger is configured, in the ethane recovery arrangement, to provide two reflux streams to the absorber. Element 18: further comprising increasing the temperature of the absorber bottoms via passage thereof through a second pass of the multi-pass heat exchanger prior to introduction into the stripper. Element 19: wherein, during ethane rejection, a recovery of propane in the NGL product is at least about 98 mole percent. Element 20: further comprising: separating an NGL feed comprising predominantly C1-C6 hydrocarbons, nitrogen, and other inert compounds into a separator vapor and a separator liquid; expanding the separator vapor in an expander; introducing the expanded vapor into a bottom of the absorber as the absorber feed; and passing the separator liquid through another pass of the multi-pass heat exchanger, wherein the temperature of the separator liquid is increased prior to introduction into the stripper. Element 21: further comprising: switching to ethane recovery in the NGL product by: ceasing utilization of the stripper overhead to reflux the absorber, by directing the stripper overhead to the absorber feed; and operating the stripper at about the same pressure as the absorber and as a demethanizer to fractionate the absorber bottoms into an methane rich stripper overhead and an ethane rich stripper bottoms. Element 22: further comprising: separating an NGL feed comprising predominantly C1-C6 hydrocarbons, nitrogen, and other inert compounds into a separator vapor and a separator liquid; expanding a portion of the separator vapor in an expander and introducing the expanded vapor into a bottom of the absorber as the absorber feed; utilizing another portion of the separator vapor to reflux the absorber subsequent passage of the another portion through the first pass of a multi-pass heat exchanger; utilizing a portion of a residue gas obtained by compressing and heat exchanging the absorber overhead as additional reflux of the absorber after passage of the at least a portion of the residue gas through another pass of the multi-pass heat exchanger; and introducing the separator liquid into the stripper without passing same through the multi-pass heat exchanger. Element 23: wherein, during ethane recovery, the ethane rich stripper bottoms comprise less than about 1 mole percent methane; wherein, during ethane recovery, a recovery of ethane is at least about 98 mole percent; wherein, during ethane recovery, a recovery of propane is at least about 99 mole percent; or a combination thereof. Element 24: wherein, during ethane recovery, a recovery of ethane is at least about 98 mole percent; wherein, during ethane recovery, a recovery of propane is at least about 99 mole percent; or a combination thereof. Element 25: wherein, during ethane recovery, from 50 to 70 mole percent (mol %) of the separator vapor is expanded in the expander and the remainder of the separator vapor is utilized to reflux the absorber. Element 26: wherein, during ethane recovery, from 10 to 25 volume percent (vol %) of the residue gas is utilized as the additional reflux to the absorber. Element 27: further comprising: switching to ethane rejection from the NGL product by: ceasing directing of the stripper overhead to the absorber feed and ceasing utilizing of the another portion of the separator vapor to reflux the absorber; utilizing the stripper overhead to reflux the absorber subsequent passage of the stripper overhead through the first pass of the multi-pass heat exchanger expanding the entirety of the separator vapor in the expander; and operating the stripper at a higher pressure than the absorber and operating the stripper as a deethanizer to fractionate the absorber bottoms into an ethane rich stripper overhead and a stripper bottoms comprising less than 2 or 1 mole percent ethane. Element 28: further comprising increasing the temperature of the absorber bottoms via passage thereof through a second pass of the multi-pass heat exchanger prior to introduction into the stripper. Element 29: wherein, during ethane rejection, a recovery of propane in the NGL product is at least about 98 mole percent.
The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and such variations are considered within the scope and spirit of the present disclosure. Alternative embodiments that result from combining, integrating, and/or omitting features of the embodiment(s) are also within the scope of the disclosure. While compositions and methods are described in broader terms of “having”, “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. Use of the term “optionally” with respect to any element of a claim means that the element is required, or alternatively, the element is not required, both alternatives being within the scope of the claim.
Numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an”, as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents, the definitions that are consistent with this specification should be adopted.
Numerous other modifications, equivalents, and alternatives, will become apparent to those skilled in the art once the above disclosure is fully appreciated. It is intended that the following claims be interpreted to embrace such modifications, equivalents, and alternatives where applicable. Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including equivalents of the subject matter of the claims.
While various embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the disclosure. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the subject matter disclosed herein are possible and are within the scope of the disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a numerical range with a lower limit, R_Land an upper limit, R_Uis disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed: R=R_L+k*(R_U-R_L), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . 50 percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed. Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc.
Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present disclosure. Thus, the claims are a further description and are an addition to the embodiments of the present disclosure. The discussion of a reference is not an admission that it is prior art to the present disclosure, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent that they provide exemplary, procedural, or other details supplementary to those set forth herein.

Claims

1. A natural gas liquids (NGL) plant, the NGL plant comprising:

an absorber configured to provide an absorber overhead and an absorber bottoms;

a stripper configured to produce a stripper overhead and a stripper bottoms, wherein the stripper is positioned downstream from the absorber and fluidly connected therewith such that the absorber bottoms can be introduced into the stripper; and

a multi-pass heat exchanger configured to provide at least one reflux stream to the absorber wherein the multi-pass heat exchanger is configured, in the ethane recovery arrangement, to provide at least two reflux streams to the absorber,

wherein the absorber and stripper are configured, in an ethane rejection arrangement, to provide the stripper overhead to a top of the absorber, and wherein the absorber and stripper are configured, in an ethane recovery arrangement, to provide the stripper overhead to a bottom of the absorber.

2. (canceled)

3. The NGL plant of claim 1, wherein the stripper is configured, in the ethane recovery arrangement, as a demethanizer to provide a stripper bottoms comprising less than 1 vol % methane, and the stripper is configured, in the ethane rejection arrangement, as a deethanizer to provide a stripper bottoms comprising less than 2 mole percent ethane.

4. The NGL plant of claim 1, further comprising:

a cold separator configured to separate a two-phase separator feed into a separator vapor and a separator liquid,

wherein the cold separator is fluidly connected with the absorber, wherein the cold separator is configured, in the ethane rejection arrangement, to route the separator vapor to the bottom of the absorber.

5. The NGL plant of claim 4, wherein the cold separator is configured, in the ethane recovery arrangement, to pass a first portion of the separator vapor to the absorber through a first pass of the multi-pass heat exchanger, and to pass a second portion of the separator vapor to the bottom of the absorber.

6. The NGL plant of claim 5, further comprising:

an expander in fluid communication with a bottom portion of the absorber,

wherein the expander is configured, in the ethane rejection arrangement, to produce an expander discharge from the separator vapor, and

wherein the expander is configured, in the ethane recovery arrangement, to produce the expander discharge from the second portion of the separator vapor.

7. The NGL plant of claim 4, wherein the cold separator is configured to pass at least a portion of the separator liquid through a second pass of the multi-pass heat exchanger prior to introduction into the stripper.

8. The NGL plant of claim 4, wherein the cold separator is configured, in an ethane recovery arrangement, to pass a first portion of the separator liquid through a second pass of the multi-pass heat exchanger prior to introduction into the absorber, and to pass a second portion of the separator liquid directly to the stripper.

9. The NGL plant of claim 4, wherein the multi-pass heat exchanger comprises a pass configured to chill a first portion of an NGL feed gas and provide at least a portion of the two-phase separator feed.

10. The NGL plant of claim 9, further comprising a heat exchanger and propane chiller configured to chill a second portion of the NGL feed gas to provide at least another portion of the two-phase separator feed.

11. The NGL plant of claim 1, further comprising:

one or more residue gas compressors configured to compress the absorber overhead to produce a compressed residue gas,

wherein the NGL plant is configured, in the ethane recovery operation, to expand and pass a portion of the compressed residue gas via the multi-pass exchanger into a top of the absorber.

12. A method of operating a natural gas liquids (NGL) plant to produce an NGL product, the method comprising:

operating the NGL plant in an ethane rejection mode, wherein operating in the ethane rejection mode comprises:

producing, with an absorber, an absorber overhead stream and an absorber bottoms stream,

introducing the absorber bottoms stream into a stripper;

producing, with the stripper, a stripper overhead stream and a stripper bottoms stream while operating the stripper at a higher pressure than the absorber, wherein the stripper bottoms stream comprises the NGL product; and

chilling the stripper overhead stream to produce a chilled stripper overhead stream;

passing the chilled stripper overhead stream to a top of the absorber to reflux the absorber;

separating an NGL feed into a separator vapor stream and a separator liquid stream;

expanding the separator vapor stream in an expander,

introducing the expanded vapor into a bottom of the absorber the absorber feed;

passing the separator liquid through a pass of a multi-pass heat exchanger; and

passing the separator liquid into the stripper downstream of the multi-pass exchanger, wherein the temperature of the separator liquid is increased in the multi-pass exchanger prior to introduction into the stripper;

operating the NGL plant in an ethane recovery mode, wherein operating in the ethane recovery mode comprises:

producing, with the absorber, the absorber overhead stream and the absorber bottoms stream;

introducing the absorber bottoms stream into the stripper;

producing, with the stripper, the stripper overhead stream and the stripper bottoms stream, wherein the stripper bottoms stream comprises the NGL product; and

passing the stripper overhead stream to a bottom of the absorber.

13. (canceled)

14. The method of claim 12, wherein operating the NGL plant in the ethane recovery mode further comprises:

separating an NGL feed into a separator vapor and a separator liquid;

expanding a first portion of the separator vapor in an expander and introducing the expanded vapor into a bottom of the absorber as the absorber feed;

chilling a second portion of the separator vapor to provide a chilled second portion of the separator vapor;

refluxing the absorber with the chilled second portion of the separator vapor;

compressing and heat exchanging the absorber overhead stream to produce a residue gas stream;

using a portion of the residue gas stream as reflux in the absorber after passage of the portion of the residue gas stream through a pass of a multi-pass heat exchanger; and

introducing the separator liquid into the stripper without passing the separator liquid through the multi-pass heat exchanger.

15. The method of claim 14, wherein the first portion of the separator vapor is between 50 to 70 mole percent (mol %) of the separator vapor.

16. A multi-pass heat exchanger configured to provide reflux to an absorber of a natural gas liquids (NGL) plant comprising the absorber and a stripper, wherein the NGL plant is configured to selectively operate in an ethane recovery arrangement or an ethane rejection arrangement, wherein the multi-pass heat exchanged comprises:

a first pass fluidly connected with a separator liquid line of a cold separator, wherein the cold separator is configured to separate a separator liquid from a two-phase separator feed, wherein the first pass is configured, in the ethane rejection arrangement, to heat the separator liquid prior to introduction of the separator liquid into the stripper;

a second pass fluidly connected with the separator liquid line of the cold separator, wherein the second pass is configured, in the ethane recovery arrangement, to chill a portion the separator liquid prior to introduction of the portion of separator liquid into the absorber; and

a third pass fluidly connected with an overhead vapor from the stripper and the absorber, wherein the third pass is configured, in the ethane rejection arrangement, to chill the overhead vapor from the stripper prior to passing the overhead vapor to a top of the absorber.

17. The multi-pass exchanger of claim 16, wherein the third pass is further fluidly connected with a separator vapor line of the cold separator, wherein the cold separator is configured to separate a separator vapor from the two-phase separator feed, wherein the third pass is configured, in the ethane recovery arrangement, to chill at least a portion of the separator vapor and pass the chilled separator vapor to the top of the absorber.

18. The multi-pass exchanger of claim 17, further comprising:

a fourth pass fluidly connected with a cooled high pressure residue gas line comprising an overhead product from the absorber, wherein the fourth pass is configured, in the ethane recovery arrangement, to chill at least a portion of the high pressure residue gas in the high pressure residue gas line and pass the chilled portion of the high pressure residue gas as reflux to the absorber.

19. The multi-pass exchanger of claim 18, further comprising:

a fifth pass fluidly connected with a feed gas line comprising a feed gas, wherein the fifth pass is configured to chill at least a portion of the feed gas prior to introduction of the portion of the feed gas to the cold separator;

a sixth pass a pass fluidly connected with a refrigerant line, wherein the sixth pass is configured to chill one or more fluids passing through the multi-pass heat exchanger; and

a seventh pass fluidly connected with an absorber overhead line, wherein the seventh pass is configured to provide heat exchange between an absorber overhead stream in the absorber overhead line with the one or more fluids passing through the multi-pass heat exchanger.

20. The multi-pass heat exchanger of claim 16, wherein the multi-pass heat exchanger is configured, in the ethane rejection arrangement, to provide a single reflux stream to the absorber, and wherein the multi-pass exchanger is configured, in the ethane recovery arrangement, to provide two reflux streams to the absorber.