Patent Grant
9057558
Ethylene, ethane, propylene, propane, and/or heavier hydrocarbons can be recovered from a variety of gases, such as natural gas, refinery gas, and synthetic gas streams obtained from other hydrocarbon materials such as coal, crude oil, naphtha, oil shale, tar sands, and lignite. Natural gas usually has a major proportion of methane and ethane, i.e., methane and ethane together comprise at least 50 mole percent of the gas. The gas also contains relatively lesser amounts of heavier hydrocarbons such as propane, butanes, pentanes, and the like, as well as hydrogen, nitrogen, carbon dioxide, and other gases.
The present invention is generally concerned with the recovery of ethylene, ethane, propylene, propane, and heavier hydrocarbons from such gas streams. A typical analysis of a gas stream to be processed in accordance with this invention would be, in approximate mole percent, 90.3% methane, 4.0% ethane and other C2 components, 1.7% propane and other C3 components, 0.3% iso-butane, 0.5% normal butane, and 0.8% pentanes plus, with the balance made up of nitrogen and carbon dioxide. Sulfur containing gases are also sometimes present.
The historically cyclic fluctuations in the prices of both natural gas and its natural gas liquid (NGL) constituents have at times reduced the incremental value of ethane, ethylene, propane, propylene, and heavier components as liquid products. This has resulted in a demand for processes that can provide more efficient recoveries of these products, for processes that can provide efficient recoveries with lower capital investment, and for processes that can be easily adapted or adjusted to vary the recovery of a specific component over a broad range. Available processes for separating these materials include those based upon cooling and refrigeration of gas, oil absorption, and refrigerated oil absorption. Additionally, cryogenic processes have become popular because of the availability of economical equipment that produces power while simultaneously expanding and extracting heat from the gas being processed. Depending upon the pressure of the gas source, the richness (ethane, ethylene, and heavier hydrocarbons content) of the gas, and the desired end products, each of these processes or a combination thereof may be employed.
The cryogenic expansion process is now generally preferred for natural gas liquids recovery because it provides maximum simplicity with ease of startup, operating flexibility, good efficiency, safety, and good reliability. U.S. Pat. Nos. 3,292,380; 4,061,481; 4,140,504; 4,157,904; 4,171,964; 4,185,978; 4,251,249; 4,278,457; 4,519,824; 4,617,039; 4,687,499; 4,689,063; 4,690,702; 4,854,955; 4,869,740; 4,889,545; 5,275,005; 5,555,748; 5,566,554; 5,568,737; 5,771,712; 5,799,507; 5,881,569; 5,890,378; 5,983,664; 6,182,469; 6,578,379; 6,712,880; 6,915,662; 7,191,617; 7,219,513; reissue U.S. Pat. No. 33,408; and co-pending application Ser. Nos. 11/430,412; 11/839,693; 11/971,491; 12/206,230; 12/689,616; 12/717,394; 12/750,862; 12/772,472; 12/781,259; 12/868,993; 12/869,007; 12/869,139; 12/979,563; 13/048,315; 13/051,682; 13/052,348; and 13/052,575 describe relevant processes (although the description of the present invention in some cases is based on different processing conditions than those described in the cited U.S. patents).
In a typical cryogenic expansion recovery process, a feed gas stream under pressure is cooled by heat exchange with other streams of the process and/or external sources of refrigeration such as a propane compression-refrigeration system. As the gas is cooled, liquids may be condensed and collected in one or more separators as high-pressure liquids containing some of the desired C2+ components. Depending on the richness of the gas and the amount of liquids formed, the high-pressure liquids may be expanded to a lower pressure and fractionated. The vaporization occurring during expansion of the liquids results in further cooling of the stream. Under some conditions, pre-cooling the high pressure liquids prior to the expansion may be desirable in order to further lower the temperature resulting from the expansion. The expanded stream, comprising a mixture of liquid and vapor, is fractionated in a distillation (demethanizer or deethanizer) column. In the column, the expansion cooled stream(s) is (are) distilled to separate residual methane, nitrogen, and other volatile gases as overhead vapor from the desired C2 components, C3 components, and heavier hydrocarbon components as bottom liquid product, or to separate residual methane, C2 components, nitrogen, and other volatile gases as overhead vapor from the desired C3 components and heavier hydrocarbon components as bottom liquid product.
If the feed gas is not totally condensed (typically it is not), the vapor remaining from the partial condensation can be split into two streams. One portion of the vapor is passed through a work expansion machine or engine, or an expansion valve, to a lower pressure at which additional liquids are condensed as a result of further cooling of the stream. The pressure after expansion is essentially the same as the pressure at which the distillation column is operated. The combined vapor-liquid phases resulting from the expansion are supplied as feed to the column.
The remaining portion of the vapor is cooled to substantial condensation by heat exchange with other process streams, e.g., the cold fractionation tower overhead. Some or all of the high-pressure liquid may be combined with this vapor portion prior to cooling. The resulting cooled stream is then expanded through an appropriate expansion device, such as an expansion valve, to the pressure at which the demethanizer is operated. During expansion, a portion of the liquid will vaporize, resulting in cooling of the total stream. The flash expanded stream is then supplied as top feed to the demethanizer. Typically, the vapor portion of the flash expanded stream and the demethanizer overhead vapor combine in an upper separator section in the fractionation tower as residual methane product gas. Alternatively, the cooled and expanded stream may be supplied to a separator to provide vapor and liquid streams. The vapor is combined with the tower overhead and the liquid is supplied to the column as a top column feed.
In the ideal operation of such a separation process, the residue gas leaving the process will contain substantially all of the methane in the feed gas with essentially none of the heavier hydrocarbon components and the bottoms fraction leaving the demethanizer will contain substantially all of the heavier hydrocarbon components with essentially no methane or more volatile components. In practice, however, this ideal situation is not obtained because the conventional demethanizer is operated largely as a stripping column. The methane product of the process, therefore, typically comprises vapors leaving the top fractionation stage of the column, together with vapors not subjected to any rectification step. Considerable losses of C2, C3, and C4+ components occur because the top liquid feed contains substantial quantities of these components and heavier hydrocarbon components, resulting in corresponding equilibrium quantities of C2 components, C3 components, C4 components, and heavier hydrocarbon components in the vapors leaving the top fractionation stage of the demethanizer. The loss of these desirable components could be significantly reduced if the rising vapors could be brought into contact with a significant quantity of liquid (reflux) capable of absorbing the C2 components, C3 components, C4 components, and heavier hydrocarbon components from the vapors.
In recent years, the preferred processes for hydrocarbon separation use an upper absorber section to provide additional rectification of the rising vapors. One method of generating a reflux stream for the upper rectification section is to use the flash expanded substantially condensed stream to cool and partially condense the column overhead vapor, with the heated flash expanded stream then directed to a mid-column feed point on the demethanizer. The liquid condensed from the column overhead vapor is separated and supplied as top feed to the demethanizer, while the uncondensed vapor is discharged as the residual methane product gas. The heated flash expanded stream is only partially vaporized, and so contains a substantial quantity of liquid that serves as supplemental reflux for the demethanizer, so that the top reflux feed can then rectify the vapors leaving the lower section of the column. U.S. Pat. No. 4,854,955 is an example of a process of this type.
The present invention employs a novel means of performing the various steps described above more efficiently and using fewer pieces of equipment. This is accomplished by combining what heretofore have been individual equipment items into a common housing, thereby reducing the plot space required for the processing plant and reducing the capital cost of the facility. Surprisingly, applicants have found that the more compact arrangement also significantly reduces the power consumption required to achieve a given recovery level, thereby increasing the process efficiency and reducing the operating cost of the facility. In addition, the more compact arrangement also eliminates much of the piping used to interconnect the individual equipment items in traditional plant designs, further reducing capital cost and also eliminating the associated flanged piping connections. Since piping flanges are a potential leak source for hydrocarbons (which are volatile organic compounds, VOCs, that contribute to greenhouse gases and may also be precursors to atmospheric ozone formation), eliminating these flanges reduces the potential for atmospheric emissions that can damage the environment.
In accordance with the present invention, it has been found that C2 recoveries in excess of 86% can be obtained. Similarly, in those instances where recovery of C2 components is not desired, C3 recoveries in excess of 99% can be obtained while providing essentially complete rejection of C2 components to the residue gas stream. In addition, the present invention makes possible essentially 100% separation of methane (or C2 components) and lighter components from the C2 components (or C3 components) and heavier components at lower energy requirements compared to the prior art while maintaining the same recovery level. The present invention, although applicable at lower pressures and warmer temperatures, is particularly advantageous when processing feed gases in the range of 400 to 1500 psia [2,758 to 10,342 kPa(a)] or higher under conditions requiring NGL recovery column overhead temperatures of −50° F. [−46° C.] or colder.
For a better understanding of the present invention, reference is made to the following examples and drawings. Referring to the drawings:
In the following explanation of the above figures, tables are provided summarizing flow rates calculated for representative process conditions. In the tables appearing herein, the values for flow rates (in moles per hour) have been rounded to the nearest whole number for convenience. The total stream rates shown in the tables include all non-hydrocarbon components and hence are generally larger than the sum of the stream flow rates for the hydrocarbon components. Temperatures indicated are approximate values rounded to the nearest degree. It should also be noted that the process design calculations performed for the purpose of comparing the processes depicted in the figures are based on the assumption of no heat leak from (or to) the surroundings to (or from) the process. The quality of commercially available insulating materials makes this a very reasonable assumption and one that is typically made by those skilled in the art.
For convenience, process parameters are reported in both the traditional British units and in the units of the Système International d'Unités (SI). The molar flow rates given in the tables may be interpreted as either pound moles per hour or kilogram moles per hour. The energy consumptions reported as horsepower (HP) and/or thousand British Thermal Units per hour (MBTU/Hr) correspond to the stated molar flow rates in pound moles per hour. The energy consumptions reported as kilowatts (kW) correspond to the stated molar flow rates in kilogram moles per hour.
The feed stream 31 is divided into two portions, streams 32 and 33. Stream 32 is cooled to −34° F. [−37° C.] in heat exchanger 10 by heat exchange with cool residue gas stream 42a, while stream 33 is cooled to −13° F. [−25° C.] in heat exchanger 11 by heat exchange with demethanizer reboiler liquids at 52° F. [11° C.] (stream 45) and side reboiler liquids at −49° F. [−45° C.] (stream 44). Streams 32a and 33a recombine to form stream 31a, which enters separator 12 at −28° F. [−33° C.] and 893 psia [6,155 kPa(a)] where the vapor (stream 34) is separated from the condensed liquid (stream 35).
The vapor (stream 34) from separator 12 is divided into two streams, 36 and 39. Stream 36, containing about 27% of the total vapor, is combined with the separator liquid (stream 35), and the combined stream 38 passes through heat exchanger 13 in heat exchange relation with cold residue gas stream 42 where it is cooled to substantial condensation. The resulting substantially condensed stream 38a at −135° F. [−93° C.] is then flash expanded through expansion valve 14 to slightly above the operating pressure (approximately 396 psia [2,730 kPa(a)]) of fractionation tower 18. During expansion a portion of the stream is vaporized, resulting in cooling of the total stream. In the process illustrated in
The remaining 73% of the vapor from separator 12 (stream 39) enters a work expansion machine 15 in which mechanical energy is extracted from this portion of the high pressure feed. The machine 15 expands the vapor substantially isentropically to the tower operating pressure, with the work expansion cooling the expanded stream 39a to a temperature of approximately −95° F. [−71° C.]. The typical commercially available expanders are capable of recovering on the order of 80-85% of the work theoretically available in an ideal isentropic expansion. The work recovered is often used to drive a centrifugal compressor (such as item 16) that can be used to re-compress the heated residue gas stream (stream 42b), for example. The partially condensed expanded stream 39a is thereafter supplied as feed to fractionation tower 18 at a lower mid-column feed point.
The column overhead vapor (stream 41) is withdrawn from the top of demethanizer 18 and cooled from −136° F. [−93° C.] to −138° F. [−94° C.] and partially condensed (stream 41a) in heat exchanger 20 by heat exchange with the flash expanded substantially condensed stream 38b as previously described. The operating pressure in reflux separator 21 (391 psia [2,696 kPa(a)]) is maintained slightly below the operating pressure of demethanizer 18. This provides the driving force which causes overhead vapor stream 41 to flow through heat exchanger 20 and thence into the reflux separator 21 wherein the condensed liquid (stream 43) is separated from the uncondensed vapor (stream 42). The liquid stream 43 from reflux separator 21 is pumped by pump 22 to a pressure slightly above the operating pressure of demethanizer 18, and stream 43a is then supplied as cold top column feed (reflux) to demethanizer 18. This cold liquid reflux absorbs and condenses the C2 components, C3 components, and heavier components in the vapors rising through the upper region of absorbing section 18a of demethanizer 18.
The demethanizer in tower 18 is a conventional distillation column containing a plurality of vertically spaced trays, one or more packed beds, or some combination of trays and packing. As is often the case in natural gas processing plants, the demethanizer tower consists of two sections: an upper absorbing (rectification) section 18a that contains the trays and/or packing to provide the necessary contact between the vapor portion of expanded stream 39a rising upward and cold liquid falling downward to condense and absorb the C2 components, C3 components, and heavier components; and a lower stripping (demethanizing) section 18b that contains the trays and/or packing to provide the necessary contact between the liquids falling downward and the vapors rising upward. The demethanizing section 18b also includes reboilers (such as the reboiler and the side reboiler described previously) which heat and vaporize a portion of the liquids flowing down the column to provide the stripping vapors which flow up the column to strip the liquid product (stream 46) of methane and lighter components. The liquid product stream 46 exits the bottom of the tower at 77° F. [25° C.], based on a typical specification of a methane to ethane ratio of 0.010:1 on a mass basis in the bottom product.
Vapor stream 42 from reflux separator 21 is the cold residue gas stream. It passes countercurrently to the incoming feed gas in heat exchanger 13 where it is heated to −54° F. [−48° C.] (stream 42a) and in heat exchanger 10 where it is heated to 98° F. [37° C.] (stream 42b) as it provides cooling as previously described. The residue gas is then re-compressed in two stages. The first stage is compressor 16 driven by expansion machine 15. The second stage is compressor 23 driven by a supplemental power source which compresses the residue gas (stream 42d) to sales line pressure. After cooling to 110° F. [43° C.] in discharge cooler 24, residue gas stream 42e flows to the sales gas pipeline at 915 psia [6,307 kPa(a)], sufficient to meet line requirements (usually on the order of the inlet pressure).
A summary of stream flow rates and energy consumption for the process illustrated in
In this simulation of the process, inlet gas enters the plant at 110° F. [43° C.] and 915 psia [6,307 kPa(a)] as stream 31 and is cooled in heat exchanger 10 by heat exchange with cool residue gas stream 42a. Cooled stream 31a enters separator 12 at 15° F. [−9° C.] and 900 psia [6,203 kPa(a)] where the vapor (stream 34) is separated from the condensed liquid (stream 35).
The vapor (stream 34) from separator 12 is divided into two streams, 36 and 39. Stream 36, containing about 28% of the total vapor, is combined with the separator liquid (stream 35), and the combined stream 38 passes through heat exchanger 13 in heat exchange relation with cold residue gas stream 42 where it is cooled to substantial condensation. The resulting substantially condensed stream 38a at −114° F. [−81° C.] is then flash expanded through expansion valve 14 to slightly above the operating pressure (approximately 400 psia [2,758 kPa(a)]) of fractionation tower 18. During expansion a portion of the stream is vaporized, resulting in cooling of the total stream. In the process illustrated in
The remaining 72% of the vapor from separator 12 (stream 39) enters a work expansion machine 15 in which mechanical energy is extracted from this portion of the high pressure feed. The machine 15 expands the vapor substantially isentropically to the tower operating pressure, with the work expansion cooling the expanded stream 39a to a temperature of approximately −58° F. [−50° C.] before it is supplied as feed to fractionation tower 18 at a lower mid-column feed point.
The column overhead vapor (stream 41) is withdrawn from the top of deethanizer 18 and cooled from −102° F. [−74° C.] to −117° F. [−83° C.] and partially condensed (stream 41a) in heat exchanger 20 by heat exchange with the flash expanded substantially condensed stream 38b as previously described. The partially condensed stream 41a enters reflux separator 21, operating at 395 psia [2,723 kPa(a)], where the condensed liquid (stream 43) is separated from the uncondensed vapor (stream 42). The liquid stream 43 from reflux separator 21 is pumped by pump 22 to a pressure slightly above the operating pressure of deethanizer 18, and stream 43a is then supplied as cold top column feed (reflux) to deethanizer 18.
The liquid product stream 46 exits the bottom of the tower at 223° F. [106° C.], based on a typical specification of an ethane to propane ratio of 0.050:1 on a molar basis in the bottom product. The cold residue gas (vapor stream 42 from reflux separator 21) passes countercurrently to the incoming feed gas in heat exchanger 13 where it is heated to −25° F. [−31° C.] (stream 42a) and in heat exchanger 10 where it is heated to 105° F. [41° C.] (stream 42b) as it provides cooling as previously described. The residue gas is then re-compressed in two stages, compressor 16 driven by expansion machine 15 and compressor 23 driven by a supplemental power source. After stream 42d is cooled to 110° F. [43° C.] in discharge cooler 24, the residue gas product (stream 42e) flows to the sales gas pipeline at 915 psia [6,307 kPa(a)].
A summary of stream flow rates and energy consumption for the process illustrated in
In the simulation of the
The second portion, stream 33, enters a heat and mass transfer means in stripping section 118d inside processing assembly 118. This heat and mass transfer means may also be comprised of a fin and tube type heat exchanger, a plate type heat exchanger, a brazed aluminum type heat exchanger, or other type of heat transfer device, including multi-pass and/or multi-service heat exchangers. The heat and mass transfer means is configured to provide heat exchange between stream 33 flowing through one pass of the heat and mass transfer means and a distillation liquid stream flowing downward from an absorbing means above the heat and mass transfer means in stripping section 118d, so that stream 33 is cooled while heating the distillation liquid stream, cooling stream 33a to −10° F. [−23° C.] before it leaves the heat and mass transfer means. As the distillation liquid stream is heated, a portion of it is vaporized to form stripping vapors that rise upward as the remaining liquid continues flowing downward through the heat and mass transfer means. The heat and mass transfer means provides continuous contact between the stripping vapors and the distillation liquid stream so that it also functions to provide mass transfer between the vapor and liquid phases, stripping the liquid product stream 46 of methane and lighter components.
Streams 32a and 33a recombine to form stream 31a, which enters separator section 118e inside processing assembly 118 at −23° F. [−31° C.] and 900 psia [6,203 kPa(a)], whereupon the vapor (stream 34) is separated from the condensed liquid (stream 35). Separator section 118e has an internal head or other means to divide it from stripping section 118d, so that the two sections inside processing assembly 118 can operate at different pressures.
The vapor (stream 34) from separator section 118e is divided into two streams, 36 and 39. Stream 36, containing about 29% of the total vapor, is combined with the separated liquid (stream 35, via stream 37), and the combined stream 38 enters a heat exchange means in the lower region of feed cooling section 118a inside processing assembly 118. This heat exchange means may likewise be comprised of a fin and tube type heat exchanger, a plate type heat exchanger, a brazed aluminum type heat exchanger, or other type of heat transfer device, including multi-pass and/or multi-service heat exchangers. The heat exchange means is configured to provide heat exchange between stream 38 flowing through one pass of the heat exchange means and the distillation vapor stream arising from rectifying section 118b inside processing assembly 118, so that stream 38 is cooled to substantial condensation while heating the distillation vapor stream.
The resulting substantially condensed stream 38a at −135° F. [−93° C.] is then flash expanded through expansion valve 14 to slightly above the operating pressure (approximately 388 psia [2,675 kPa(a)]) of rectifying section 118b and absorbing section 118c (an absorbing means) inside processing assembly 118. During expansion a portion of the stream may be vaporized, resulting in cooling of the total stream. In the process illustrated in
The flash expanded stream 38b is partially vaporized as it provides cooling and partial condensation of the distillation vapor stream, and exits the heat and mass transfer means in rectifying section 118b at −140° F. [−96° C.]. (Note that the temperature of stream 38b drops slightly as it is heated, due to the pressure drop through the heat and mass transfer means and the resulting vaporization of some of the liquid methane contained in the stream.) The heated flash expanded stream is separated into its respective vapor and liquid phases, with the vapor phase combining with the vapor arising from absorbing section 118c to form the distillation vapor stream that enters the heat and mass transfer means in rectifying section 118b as previously described. The liquid phase is directed to the upper region of absorbing section 118c to join with the liquid condensed from the distillation vapor stream in rectifying section 118b.
The remaining 71% of the vapor from separator section 118e (stream 39) enters a work expansion machine 15 in which mechanical energy is extracted from this portion of the high pressure feed. The machine 15 expands the vapor substantially isentropically to the operating pressure of absorbing section 118c, with the work expansion cooling the expanded stream 39a to a temperature of approximately −93° F. [−70° C.]. The partially condensed expanded stream 39a is thereafter supplied as feed to the lower region of absorbing section 118c inside processing assembly 118 to be contacted by the liquids supplied to the upper region of absorbing section 118c.
Absorbing section 118c and stripping section 118d each contain an absorbing means consisting of a plurality of vertically spaced trays, one or more packed beds, or some combination of trays and packing. The trays and/or packing in absorbing section 118c and stripping section 118d provide the necessary contact between the vapors rising upward and cold liquid falling downward. The liquid portion of the expanded stream 39a comingles with liquids falling downward from absorbing section 118c and the combined liquid continues downward into stripping section 118d. The vapors arising from stripping section 118d combine with the vapor portion of the expanded stream 39a and rise upward through absorbing section 118c, to be contacted with the cold liquid falling downward to condense and absorb most of the C2 components, C3 components, and heavier components from these vapors. The vapors arising from absorbing section 118c combine with the vapor portion of the heated expanded stream 38b and rise upward through rectifying section 118b, to be cooled and rectified to remove most of the C2 components, C3 components, and heavier components remaining in these vapors as previously described. The liquid portion of the heated expanded stream 38b comingles with liquids falling downward from rectifying section 118b and the combined liquid continues downward into absorbing section 118c.
The distillation liquid flowing downward from the heat and mass transfer means in stripping section 118d inside processing assembly 118 has been stripped of methane and lighter components. The resulting liquid product (stream 46) exits the lower region of stripping section 118d and leaves processing assembly 118 at 73° F. [23° C.]. The distillation vapor stream arising from rectifying section 118b is warmed in feed cooling section 118a as it provides cooling to streams 32 and 38 as previously described, and the resulting residue gas stream 42 leaves processing assembly 118 at 99° F. [37° C.]. The residue gas stream is then re-compressed in two stages, compressor 16 driven by expansion machine 15 and compressor 23 driven by a supplemental power source. After stream 42b is cooled to 110° F. [43° C.] in discharge cooler 24, the residue gas product (stream 42c) flows to the sales gas pipeline at 915 psia [6,307 kPa(a)].
A summary of stream flow rates and energy consumption for the process illustrated in
A comparison of Tables I and III shows that, compared to the prior art, the present invention improves ethane recovery from 84.99% to 86.66% and propane recovery from 97.74% to 98.01%, and maintains essentially the same butanes+recovery (99.81% versus 99.83% for the prior art). Comparison of Tables I and III further shows that the product yields were achieved using significantly less power than the prior art. In terms of the recovery efficiency (defined by the quantity of ethane recovered per unit of power), the present invention represents nearly a 6% improvement over the prior art of the
The improvement in recovery efficiency provided by the present invention over that of the prior art of the
Second, using the heat and mass transfer means in stripping section 118d to simultaneously heat the distillation liquid leaving the absorbing means in stripping section 118d while allowing the resulting vapors to contact the liquid and strip its volatile components is more efficient than using a conventional distillation column, with external reboilers. The volatile components are stripped out of the liquid continuously, reducing the concentration of the volatile components in the stripping vapors more quickly and thereby improving the stripping efficiency for the present invention.
Third, using the heat and mass transfer means in rectifying section 118b to simultaneously cool the distillation vapor stream arising from absorbing section 118c while condensing the heavier hydrocarbon components from the distillation vapor stream provides more efficient rectification than using reflux in a conventional distillation column. As a result, more of the C2 components, C3 components, and heavier hydrocarbon components can be removed from the distillation vapor stream using the refrigeration available in the expanded stream 38b compared to the prior art of the
The present invention offers two other advantages over the prior art in addition to the increase in processing efficiency. First, the compact arrangement of processing assembly 118 of the present invention replaces eight separate equipment items in the prior art (heat exchangers 10, 11, 13, and 20, separator 12, reflux separator 21, reflux pump 22, and fractionation tower 18 in
In those cases where the C2 component recovery level in the liquid product must be reduced (as in the
In the simulation of the
The vapor (stream 34) from separator section 118e is divided into two streams, 36 and 39. Stream 36, containing about 28% of the total vapor, is combined with the separated liquid (stream 35, via stream 37), and the combined stream 38 enters a heat exchange means in the lower region of feed cooling section 118a inside processing assembly 118. The heat exchange means is configured to provide heat exchange between stream 38 flowing through one pass of the heat exchange means and the distillation vapor stream arising from rectifying section 118b inside processing assembly 118, so that stream 38 is cooled to substantial condensation while heating the distillation vapor stream.
The resulting substantially condensed stream 38a at −114° F. [−81° C.] is then flash expanded through expansion valve 14 to slightly above the operating pressure (approximately 393 psia [2,710 kPa(a)]) of rectifying section 118b and absorbing section 118c inside processing assembly 118. During expansion a portion of the stream may be vaporized, resulting in cooling of the total stream. In the process illustrated in
The flash expanded stream 38b is partially vaporized as it provides cooling and partial condensation of the distillation vapor stream, then exits the heat and mass transfer means in rectifying section 118b at −104° F. [−75° C.] and is separated into its respective vapor and liquid phases. The vapor phase combines with the vapor arising from absorbing section 118c to form the distillation vapor stream that enters the heat and mass transfer means in rectifying section 118b as previously described. The liquid phase is directed to the upper region of absorbing section 118c to join with the liquid condensed from the distillation vapor stream in rectifying section 118b.
The remaining 72% of the vapor from separator section 118e (stream 39) enters a work expansion machine 15 in which mechanical energy is extracted from this portion of the high pressure feed. The machine 15 expands the vapor substantially isentropically to the operating pressure of absorbing section 118c, with the work expansion cooling the expanded stream 39a to a temperature of approximately −60° F. [−51° C.]. The partially condensed expanded stream 39a is thereafter supplied as feed to the lower region of absorbing section 118c inside processing assembly 118 to be contacted by the liquids supplied to the upper region of absorbing section 118c.
Absorbing section 118c and stripping section 118d each contain an absorbing means. Stripping section 118d also includes a heat and mass transfer means beneath its absorbing means which is configured to provide heat exchange between a heating medium flowing through one pass of the heat and mass transfer means and a distillation liquid stream flowing downward from the absorbing means, so that the distillation liquid stream is heated. As the distillation liquid stream is heated, a portion of it is vaporized to form stripping vapors that rise upward as the remaining liquid continues flowing downward through the heat and mass transfer means. The heat and mass transfer means provides continuous contact between the stripping vapors and the distillation liquid stream so that it also functions to provide mass transfer between the vapor and liquid phases, stripping the liquid product stream 46 of methane, C2 components, and lighter components. The resulting liquid product (stream 46) exits the lower region of stripping section 118d and leaves processing assembly 118 at 221° F. [105° C.].
The distillation vapor stream arising from rectifying section 118b is warmed in feed cooling section 118a as it provides cooling to streams 31 and 38 as previously described, and the resulting residue gas stream 42 leaves processing assembly 118 at 106° F. [41° C.]. The residue gas stream is then re-compressed in two stages, compressor 16 driven by expansion machine 15 and compressor 23 driven by a supplemental power source. After stream 42b is cooled to 110° F. [43° C.] in discharge cooler 24, the residue gas product (stream 42c) flows to the sales gas pipeline at 915 psia [6,307 kPa(a)].
A summary of stream flow rates and energy consumption for the process illustrated in
A comparison of Tables II and IV shows that the present invention maintains essentially the same recoveries as the prior art. However, further comparison of Tables II and IV shows that the product yields were achieved using significantly less power than the prior art. In terms of the recovery efficiency (defined by the quantity of propane recovered per unit of power), the present invention represents nearly a 4% improvement over the prior art of the
The
Some circumstances may favor eliminating feed cooling section 118a from processing assembly 118, and using one or more heat exchange means external to the processing assembly for feed cooling and reflux condensing, such as heat exchangers 10 and 20 shown in
Some circumstances may favor supplying liquid stream 35 directly to stripping section 118d via stream 40 as shown in
Some circumstances may favor using the cooled second portion (stream 33a in
In some circumstances, it may be advantageous to use an external separator vessel to separate cooled feed stream 31a, rather than including separator section 118e in processing assembly 118. As shown in
Depending on the quantity of heavier hydrocarbons in the feed gas and the feed gas pressure, the cooled feed stream 31a entering separator section 118e in
Feed gas conditions, plant size, available equipment, or other factors may indicate that elimination of work expansion machine 15, or replacement with an alternate expansion device (such as an expansion valve), is feasible. Although individual stream expansion is depicted in particular expansion devices, alternative expansion means may be employed where appropriate. For example, conditions may warrant work expansion of the substantially condensed portion of the feed stream (stream 38a).
In accordance with the present invention, the use of external refrigeration to supplement the cooling available to the inlet gas from the distillation vapor and liquid streams may be employed, particularly in the case of a rich inlet gas. In such cases, a heat and mass transfer means may be included in separator section 118e (or a gas collecting means in such cases when the cooled feed stream 31a contains no liquid) as shown by the dashed lines in
Depending on the temperature and richness of the feed gas and the amount of C2 components to be recovered in liquid product stream 46, there may not be sufficient heating available from stream 33 to cause the liquid leaving stripping section 118d to meet the product specifications. In such cases, the heat and mass transfer means in stripping section 118d may include provisions for providing supplemental heating with heating medium as shown by the dashed lines in
Depending on the type of heat transfer devices selected for the heat exchange means in the upper and lower regions of feed cooling section 118a in
Some circumstances may favor not providing an absorbing means in the upper region of stripping section 118d. In such cases, a distillation liquid stream is collected from the lower region of absorbing section 118c and directed to the heat and mass transfer means in stripping section 118d.
A less preferred option for the
It will be recognized that the relative amount of feed found in each branch of the split vapor feed will depend on several factors, including gas pressure, feed gas composition, the amount of heat which can economically be extracted from the feed, and the quantity of horsepower available. More feed above absorbing section 118c may increase recovery while decreasing power recovered from the expander and thereby increasing the recompression horsepower requirements. Increasing feed below absorbing section 118c reduces the horsepower consumption but may also reduce product recovery.
The present invention provides improved recovery of C2 components, C3 components, and heavier hydrocarbon components or of C3 components and heavier hydrocarbon components per amount of utility consumption required to operate the process. An improvement in utility consumption required for operating the process may appear in the form of reduced power requirements for compression or re-compression, reduced power requirements for external refrigeration, reduced energy requirements for supplemental heating, reduced energy requirements for tower reboiling, or a combination thereof.
While there have been described what are believed to be preferred embodiments of the invention, those skilled in the art will recognize that other and further modifications may be made thereto, e.g. to adapt the invention to various conditions, types of feed, or other requirements without departing from the spirit of the present invention as defined by the following claims.
This invention relates to a process and apparatus for the separation of a gas containing hydrocarbons. The applicants claim the benefits under Title 35, United States Code, Section 119(e) of prior U.S. Provisional Application No. 61/186,361 which was filed on Jun. 11, 2009. The applicants also claim the benefits under Title 35, United States Code, Section 120 as a continuation-in-part of U.S. patent application Ser. No. 13/052,575 which was filed on Mar. 21, 2011, and as a continuation-in-part of U.S. patent application Ser. No. 13/052,348 which was filed on Mar. 21, 2011, and as a continuation-in-part of U.S. patent application Ser. No. 13/051,682 which was filed on Mar. 18, 2011, and as a continuation-in-part of U.S. patent application Ser. No. 13/048,315 which was filed on Mar. 15, 2011, and as a continuation-in-part of U.S. patent application Ser. No. 12/781,259 which was filed on May 17, 2010, and as a continuation-in-part of U.S. patent application Ser. No. 12/772,472 which was filed on May 3, 2010, and as a continuation-in-part of U.S. patent application Ser. No. 12/750,862 which was filed on Mar. 31, 2010, and as a continuation-in-part of U.S. patent application Ser. No. 12/717,394 which was filed on Mar. 4, 2010, and as a continuation-in-part of U.S. patent application Ser. No. 12/689,616 which was filed on Jan. 19, 2010, and as a continuation-in-part of U.S. patent application Ser. No. 12/372,604 which was filed on Feb. 17, 2009. Assignees S.M.E. Products LP and Ortloff Engineers, Ltd. were parties to a joint research agreement that was in effect before the invention of this application was made.
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| Number | Date | Country | |
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| 20110226014 A1 | Sep 2011 | US |
| Number | Date | Country | |
|---|---|---|---|
| 61186361 | Jun 2009 | US |
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