Patent Application
20190358583
This invention relates to systems and methods that make use of membrane technology to remove carbon dioxide (CO2) and hydrogen sulfide (H2S) from a gas stream.
Removing CO2 and H2S from gas using membranes is a well-known process. The membranes typically separate the gas into two streams, a CO2- and H2S-enriched low pressure stream as permeate and a CO2- and H2S-depleted high pressure stream as a product gas. Such processes are often used to help purify natural gas where standard cryogenic fractionation processes are limited by azeotrope formation between CO2 and ethane (C2H6).
Generally speaking, the membrane technology approaches require several membranes and large compressors, making it both capital-intensive and inefficient. Each successive membrane step requires recompression of the permeate from the last membrane step, along with compression of the product from the membrane step to combine with the higher pressure product from the last membrane step. This is a major hurdle to implementing membrane technology for gas stream applications. A need exists to optimize primary membrane stream processing and reduce the overall compression requirements and capital cost.
U.S. Pat. No. 7,152,430 B1 to Parro reduces the amount of CO2 in a feed gas stream by using fractional distillation that provides a CO2-rich bottom stream and a CO2-lean distillation overhead stream. The CO2-lean distillation overhead stream is passed through a membrane unit to produce a low-pressure CO2-rich stream and a hydrocarbon stream. The hydrocarbon stream is chilled to produce a reflux liquid stream and a hydrocarbon gas product. The low-pressure CO2-rich stream is further compressed and mixed with the overhead of the fractionation reflux drum.
Some embodiments of acid gas purification systems described herein include An acid gas purification system, comprising a primary membrane system with a CO2- and H2S-enriched permeate stream effluent and a hydrocarbon stream effluent; a first compression stage arranged to receive the CO2- and H2S-enriched permeate stream and produce a compressed stream; and a cryogenic separation system to receive the compressed stream, the cryogenic separation system including a conditioner followed by a fractionator, wherein the fractionator produces a CO2- and H2S liquid stream and a hydrocarbon gas stream.
Other embodiments of acid gas purification systems described herein include a membrane separation unit that produces a permeate stream enriched in CO2 and/or H2S and a retentate stream from a feed stream; a conditioner to reduce a temperature of the permeate stream; and a cryogenic fractionator to separate acid gases from the cooled permeate stream.
Other embodiments of acid gas purification systems described herein include a non-distillation separation system with an acid gas effluent and a separation gas effluent, wherein the non-distillation separation system is a single step separation and the acid gas effluent is at least 90 mol % CO2 and/or H2S; and a cryogenic fractionation system including a conditioner and a fractionator.
To facilitate understanding, identical reference numerals have been used, where possible, to designate identical elements that are common to the figures. It is contemplated that elements and features of one embodiment may be beneficially incorporated in other embodiments without further recitation.
A feed gas stream 15, which may be a natural gas stream, a combustion effluent stream, an air fraction stream, or another gas stream containing CO2 and/or H2S is charged to a pretreatment unit 20. The pretreatment unit 20 can filter the feed gas stream 15, remove water, dehydrate, and condition the feed gas stream 15 to a dew point thereof, producing a pretreated feed gas stream 25. The feed gas is typically at least 10 mol % acid gases (CO2 and H2S), for example 10-11 mol % CO2, with the balance mostly light hydrocarbons such as methane and ethane. There may be a few heavier hydrocarbons such as propane and butane in the feed gas stream, on occasion, but if present the concentration of such gases is normally less than about 0.5 mol %. In some cases the concentration of acid gases may be less than 10 mol %, as noted below.
The pretreated feed gas stream 25 enters a membrane system 30 at high pressure (up to 2000 psig) where the membrane system 30 separates the stream 25 into a CO2- and H2S-enriched low pressure stream as permeate 33 (<400 psig) and a CO2- and H2S-depleted high pressure stream as a product gas 37 (>1000 psig). The membrane system 30 includes a membrane separator with a polymeric membrane element. Examples of membrane systems that can be used include the CYNARA and APURA membrane systems available from the Process Solutions and Systems unit of Schlumberger Technology Corporation of Houston, Tex. Other membrane systems for high selectivity separation of acid gases such as CO2 and H2S from hydrocarbons may be used. The permeate stream 33 is at least 90 mol % acid gases CO2 and H2S. Because the primary membrane system 30 recovers a maximum amount of ethane and heavy hydrocarbons in the product gas 37, only a small amount of ethane and heavy hydrocarbons are permeated in the low pressure permeate stream 33. The product gas 37 has no more than 10 mol % acid gases.
The permeate stream 33 is compressed to 400-600 psig pressure in a first-stage compressor 40, which may be a multi-stage compression unit with interstage condensate handling. The compressed stream 45 enters the cryogenic separation system 50 at a conditioner 51 thereof, and is cooled in the conditioner 51 that includes a series of heat exchangers 53 followed by cooling to −60° F. to −140° F. (about −51° C. to −96° C.) temperature in an inlet chiller 55. The cryogenically cooled stream 60 then enters a fractionator 61. When a multi-stage compression unit is used for the compressor 40, any interstage liquids that are desirous of recovery may be routed to the conditioner 51 for recovery in the fractionator 61.
The fractionator 61 should be able to handle multiple phases of CO2 and H2S under variable temperature conditions to achieve a desired separation. The fractionator 61 includes a stripping section of the fractionator 61 and a rectification section of the fractionator 61 in fluid communication with each other. Between the stripping section and the rectification section, the fractionator 61 can have different mid-section features to handle CO2 and H2S phase changes. For example, the mid-section of the fractionator 61 may include a space for nucleating crystals that then fall into the top of the rectifying section and melt. The fractionator 61 may also have a side processor at the middle section of the fractionator 61 to process a sidestream from the stripping section and return a condensed stream to the rectifying section of the fractionator 61.
The side processor may address formation of solids in different ways. For example, the side processor may include an empty section for nucleating crystals that fall into a warmer liquid, which is then returned to the fractionator 306 (shown in
In other embodiments, the fractionator 61 may be two or more distillation columns. For example, a first distillation column may be a stripping section of the fractionator 61 while a second distillation column is a rectification section of the fractionator 61. Equipment can be provided between the two columns to handle phase changes, as necessary. In such embodiments, the first column is sometimes operated at lower pressure than the second column. Compression and cooling of a stream from the first column for feeding to the second column can produce solid CO2, which can be separated, melted, and added to the CO2 product of the second column.
Most CO2 and H2S from the cryogenically cooled stream 60 emerges from the fractionator 61 as a liquid stream 65 in the bottom/reboiler section of the fractionator 61. In an example operation at about 500 psig pressure, the bottom liquid stream is reboiled at a temperature of about 10° C., while the overhead is condensed at a temperature of about −50° C. If pressure of the fractionator 61 is controlled to a certain target, and if the fractionator 61 operation is controlled to deliver purified CO2 and H2S stream as a bottoms stream, fluctuations in composition of the cryogenically cooled stream 60 will cause fluctuations in operating temperatures of the fractionator 61. The CO2 and H2S bottoms stream 65 contains less than 10% of the amount of non-0O2 and H2S (mostly hydrocarbon) compounds. The bottoms stream 65 (i.e. the bottoms section of the fractionator 61) can be at 300-600 psig pressure, and can be further conditioned to increase the temperature to higher than 40° F. (about 4° C.).
The hydrocarbon-rich gas 70 is separated at the reflux drum overhead of the fractionator 61, with a lower temperature of the overhead being maintained thorough a condenser. The reflux/condensation process reduces the total amount of CO2 and H2S leaving the reflux drum overhead in the hydrocarbon stream 70. The amount of CO2 and H2S in the reflux drum overhead hydrocarbon-rich stream 70 can be adjusted to manage composition of the final hydrocarbon product stream 90, which is the mixture of the primary membrane product gas 37 and the overhead stream 70. The overhead stream 70 can be further compressed in a second stage compressor 80 at pressure to form a compressed overhead stream 85 that matches pressure with the primary membrane product gas 37.
A significant number of membrane modules/surface area and recycle compression can be reduced using this novel approach. For a feed gas of 10-11 mol % inlet CO2, at 1000 psig and 61° F. (about 21° C.) inlet conditions, at a rate of 840 MIVISCFD, and producing a product gas with less than 2% CO2 and less than 2% hydrocarbon losses in the permeate stream, use of a cryogenic fractionation system as described herein can reduce the need for membranes by 50% or more, and the need for compression to drive the membranes by 30% or more.
Combining the primary membrane system 30 with the cryogenic separation system 50 can be applied, for example, in a liquefied natural gas pretreatment plant where CO2 in the feed gas can vary from 2% to 40% or higher. In cases where CO2 from a hydrocarbon production facility is to be re-injected into the reservoir, the system 200 can help reduce the overall re-injection cost of CO2 and H2S by producing the re-injection gas as a liquid for pumping directly into the ground, avoiding the cost of compressing a gas for re-injection. This also avoids any sulfur plant requirement to manage H2S downstream. A purified liquid CO2 product stream can also be advantageous for enhanced oil recovery techniques, where CO2 is sometimes used as a hydrocarbon mobilant in hydrocarbon reservoirs, and where compressing a gas to reservoir pressure can be avoided. Other uses of liquid CO2 may include manufacture of methanol, semiconductor processes that utilize supercritical CO2, mechanical uses of liquid CO2 in pressure bottles, and various medical uses of CO2.
Using a non-fractionation separation prior to a fractionation separation avoids barriers associated with separating ethane (“C2”) from CO2 by distillation. C2 forms an azeotrope with CO2 that has approximately 70 mol % CO2 and 30 mol % C2, which prevents separation of the two compounds purely by distillation. The azeotrope has a boiling point at about −6° C. and 34 bar. Using a non-distillation separation coupled with a distillation separation, an operational objective of the system can be selected by operating the non-distillation separation to target a composition either side of the CO2/C2 azeotrope point. Some, or most, C2 is separated from the CO2 and H2S in the non-distillation separation, and a feed stream substantially concentrated in CO2 and H2S can be charged to a fractionator. If the feed stream has a CO2 composition less than the CO2/C2 azeotrope point, the fractionator can be operated to purify C2 overhead. If the feed stream has a CO2 composition higher than the CO2/C2 azeotrope point, the fractionator can be operated to maximize CO2 at bottoms. H2S does not form an azeotrope with either CO2 or C2, and is high-boiling relative to both, so H2S will generally emerge in the bottoms section of the fractionator.
The acid gas stream 341 is routed to a first compressor 302, which is similar to the compressor 40 of
The compressor 302 produces a compressed stream 303 and routed to a cryogenic fractionation system 301. The compressed stream 303 is treated in a conditioner 304, which produces a cooled stream 305, which may be, or may include, liquid. The conditioner 304 includes one or more heat exchangers, and may also include one or more cryogenic expanders. The cooled stream 305 is charged to a fractionator 306, which may include more than one distillation column.
In the implementation of
The fractionator 306 has a reflux system 320 with an overhead accumulator 322, which has a vapor space and a liquid portion. A liquid level may be maintained in the overhead accumulator 322. Vapor stream 313 from the fractionator 306 is cooled and routed to the accumulator 322, where some liquid is condensed. A reflux stream 326 returns the liquid from the accumulator 322 to the fractionator 306. A portion of the reflux stream 326 can be routed to the conditioner 304, if desired, for heat integration, or upstream of the conditioner 304 for recycle. These optional streams are respectively labelled 328 and 330 in
A vapor stream 324 from the accumulator 322 to be mixed with the hydrocarbon stream 343 is compressed by compressor 310 before mixing. The second compressor 310 produces a compressed hydrocarbon stream 315, which can then be combined with the hydrocarbon stream 341. Temperatures may be equalized, if desired, prior to mixing.
In one embodiment, the bottoms stream of the fractionator 306 is a high purity liquid CO2 stream, which can be used for any suitable purpose. For example, the liquid CO2 can be used in enhanced oil recovery, as a raw material for production of bio-based ethanol, as food grade CO2, as a raw material for certain semiconductor processes, as a refrigerant, or the liquid CO2 can be conveniently sequestered underground. Such sequestration can be designed to allow recovery of energy from the liquid CO2 by adiabatic expansion, if desired.
In an embodiment where high purity liquid CO2 is recovered in the bottoms product stream 309, the fractionator 306 produces an overhead stream 313 that is at least about 30 mol % hydrocarbon, most of which is C2, but which may also contain small amounts of higher hydrocarbons including propanes, butanes, and pentanes (including normal and branched isomers). In such an embodiment, most of the higher hydrocarbons will emerge with the CO2 (and any H2S present in the system) in the bottoms product stream 309. When the non-fractionation separation removes most hydrocarbon from the system prior to compression in the compressor 302, the flowrate of the overhead stream 313 is relatively small, for example about 10% of the feed to the fractionator 306 depending on composition of the various streams. In such an embodiment, recycling a portion of the bottoms stream 307 to the compressor 302 can increase purity of the CO2 stream recovered in the bottoms product stream 309.
In an embodiment where C2 is purified overhead in the fractionator 306, the fractionator 306 produces a bottoms stream 307 that is no more than about 70 mol % CO2, and at least about 30 mol % C2, with H2S and higher hydrocarbons recovered in the bottoms stream 307. The fractionator overhead stream 313 is at least about 90 mol % C2, and can be higher depending on how the fractionator 306 is operated. For example, if a portion of the reflux is recycled, impurities in the tower overhead will be reduced, at the expense of extra energy consumption.
The recycle modes and options depicted in
Using a non-fractionation separation prior to fractionation allows separation of hydrocarbon from acid gases to be targeted according to the objective of the cryogenic fractionation system. For example, in a case wherein a feed gas stream contains 10 mol % CO2, 10 mol % ethane, and 80 mol % methane, taking a hydrocarbon stream that is 2 mol % CO2 and an acid gas stream that is 95 mol % CO2 in the non-fractionation separator 340, with no bottoms recycle from the fractionator 306, results in a feed rate to the fractionator 306 that is approximately 9% of the feed gas stream flow rate. If the fractionator 306 is operated to produce a bottoms stream that is 99 mol % CO2, with no bottoms recycle, the fractionator 306 overhead flow rate will be approximately 16% of the feed rate to the fractionator 306, and about 1.4% of the feed gas stream flow rate. The resulting hydrocarbon stream blended from non-fractionation separator 340 product and fractionator 306 overhead will be approximately 93% of the feed gas stream and will have approximately 3 mol % CO2. In cases where one or both streams of the fractionator 306 are recycled to the non-fractionation separator 340, separation of hydrocarbon from acid gases can be improved by reintroducing CO2/C2 azeotrope to the non-fractionation separator 340 for further separation, resulting in less azeotrope being recovered at the cryogenic fractionation system 301. In some embodiments, the non-fractionation separator 340 can have variable capacity to handle different separation objectives. For example, multiple separation modules, such as membrane units, can be provided with flexible piping and valving to allow use of a desired number of modules depending on the degree of non-fractionation separation desired.
For membrane separation, CYNARA and/or APURA membrane systems available from the Process Solutions and Systems unit of Schlumberger Technology Corporation of Houston, Tex., can be used. Other membrane separation systems for high selectivity separation of acid gases such as CO2 and H2S from hydrocarbon gases can also be used. Membrane systems can be used to recover, from a gas stream that is 10 mol % acid gases (CO2 and H2S), an acid gas stream that is 35-95 mol % acid gases. Such a system can be used to target an acid gas stream that is subazeotropic or superazeotropic in CO2 and C2.
In pressure swing absorption, an adsorbent is chosen that selectively separates acid gases from hydrocarbons. In particular, a separation between acid gases such as CO2 and H2S from ethane is performed using a selected adsorbent, which may be, or include, activated carbon and metal-organic frameworks as examples. Bed lengths, cycling conditions, and number of beds can be optimized by persons skilled in the art to produce the acid gas stream 341 and hydrocarbon stream 343. Polymers are sometimes used, and may be treated with activated carbon or other adsorbent active for acid gases. Amines can be used for such cases, as well. Such systems can be used to recover an acid gas stream that is up to about 95 mol % acid gases from a gas stream that is 10 mol % acid gases.
Physical solvent absorption processes can be used for non-fractionation separation. Usable physical solvents for CO2 extraction include N-methyl pyrrolidone, methanol, and propylene carbonate, among others. CO2 is extracted into the solvent, which can then be effectively separated by distillation. The CO2 can also be extracted in one step by extractive distillation. Such processes are known in the art, and can also recover an acid gas stream that is up to about 95 mol % acid gases from a 10 mol % acid gas stream.
The fractionation separation systems above can include any of the fractionators described above in connection with
While the foregoing is directed to embodiments of the present disclosure, other and further embodiments of the disclosure may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.
This application claims benefit of U.S. Provisional Patent Application Ser. No. 62/444,443 filed Jan. 10, 2017, which is incorporated herein by reference.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2018/012856 | 1/9/2018 | WO | 00 |
| Number | Date | Country | |
|---|---|---|---|
| 62444443 | Jan 2017 | US |
