Hydrocarbon recovery and light product purity when processing gases with physical solvents

FIELD OF THE INVENTION

The invention relates to the field of chemical processing and, more specifically, to the processing of hydrocarbon gas streams. In particular, a method and apparatus for separating the components of a hydrocarbon gas stream is disclosed.

BACKGROUND OF THE INVENTION

Many hydrocarbon gases such as natural gas, cracked gas, or refinery off gas contain one or more light components that either contaminate the main gas or that are themselves valuable if they can be separated from the main gas stream. Such light gases include nitrogen, helium, and hydrogen. A number of economic considerations make it desirable to separate these light gases from a hydrocarbon gas stream.

For example, contamination of natural gas with one or more light components is particularly common. Natural gas is a mixture of hydrocarbons, including methane ethane, propane, butane and pentane. Natural gas can also contain nitrogen, helium, and acid gases such as carbon dioxide and hydrogen sulfide. Nitrogen is sometimes a natural component or may derive from nitrogen injections utilized for reviving oil wells in suitable formations. Helium occurs naturally in a small portion of natural gas reservoirs. Natural gas must meet certain criteria for acid gas content, heating value, dew point, and total inert content before the natural gas can be transported and marketed. Nitrogen content is often limited to less than 2 to 4 molar percent. Nitrogen must therefore be removed from natural gas containing more than the specified amount or the natural gas cannot be transported and marketed.

Natural gas is also produced in association with crude oil production as associated gas. This associated gas may contain naturally occurring nitrogen or may contain injected nitrogen used to enhance oil recovery. Associated gas must meet the same criteria as natural gas if the associated gas is to be transported and marketed.

Refinery and chemical plant streams often contain a number of light components such as nitrogen and hydrogen. Hydrogen is commonly contained in gas streams in refinery units. Hydrogen is added to some refinery operations and is produced as a side-product in other refinery unit operations. It is often desirable to separate this hydrogen from the refinery off gas because removed and recovered hydrogen can be recycled within the facility or sold, typically for a higher value than the heating value of the hydrogen in a refinery or chemical plant hydrocarbon stream. Likewise, removing nitrogen from the plant stream increases the heating value of the remaining hydrocarbon stream and potentially increases the stream's value as a fuel stream.

Separation of light components such as hydrogen or nitrogen from heavier components such as methane and ethane can increase the value of either or both of the resulting separate streams. Existing technologies for performing such separations include the use of selective membranes, adsorption systems such a pressure swing adsorption, and systems that utilize very low temperatures (cryogenic plants) such as expander, Joule-Thompson, or cascaded refrigeration plants. U.S. Pat. Nos. 6,053,965 and 6,264,828 provide examples of membrane technology that can be used for either stand-alone separations or as additions to purify streams.

Absorption using a physical solvent to remove the heavier components and therefore separate them from the light components, a process known as the Mehra process, can be employed. The Mehra process is described in several patents, including U.S. Pat. Nos. 4,623,371, 4,680,042, 4,882,718, 4,833,514, 5,462,585, and 5,551,972. These patents describe absorption/flash regeneration systems for removal of light components such as nitrogen or hydrogen from heavier components such as methane or ethylene. They address systems wherein the physical solvent used is external, meaning a made up of component(s) added to the system, and also systems wherein the physical solvent used is internally generated and is therefore composed of heavier component(s) in the feed gas. Improvements to these processes are also described in U.S. Pat. Nos. 6,698,237 and 7,337,631 B2 and U.S. patent application Ser. Nos. 11/211,145 and 11/210,144, all by Thomas K. Gaskin.

In the Mehra process, the heavier components are absorbed away from the light components using a circulating physical solvent. Reducing the pressure of the rich solvent in a flash separator releases the heavier component and regenerates the solvent for recirculation to the absorber. When processing natural gas, the unabsorbed component stream is predominately nitrogen and it is preferably vented to atmosphere. The physical solvent may be a liquid chosen for its physical properties, one property being that it is heavier than the component to be absorbed from the light component. The physical solvent may also be made up entirely of the heaviest components of the feed gas stream. These heaviest components are those that do not readily vaporize in the flash regeneration of the circulating solvent. In this case, the components that are absorbed in the solvent and then released at lower pressure as a product stream are the intermediate range molecular weight or volatility components. The intermediate and heavier components are typically hydrocarbons. These absorption processes are characterized in that a feed stream comprising multiple components enters the process and two or more streams enriched in at least one of the components leave the process.

There is a need to further process a light gas stream exiting the top of the absorber in an existing or new absorption-based gas processing plant that utilizes solvent-based absorption for separation of components from a feed gas, with the rich solvent being regenerated by pressure reduction with the absorbed components being released during regeneration. In this context, the feed gas to the absorption process plant is referred to as a feed gas or multi-component feed gas, and it will comprise at least a light component and a heavier component. The light component will typically be an inert gas, non-hydrocarbon such as nitrogen or hydrogen. These light components will exit the top of the absorber as unabsorbed components, and be referred to as the absorber overhead stream or light component stream or inert stream.

Heavier components in the feed gas will be any component with a lower relative volatility, indicating that it is more readily absorbed into a circulating physical solvent in the absorber. These heavier components are typically hydrocarbons, and can be referred to as such. These heavier components in the feed gas can be in several ranges of volatility; starting with the lightest, or highest volatility of the absorbed components, referred to as intermediate compounds or components. They are heavier than the unabsorbed components, they are largely absorbed into the lean solvent, and they are subsequently largely released from the solvent when the solvent is regenerated by flash regeneration to become a second product stream. These intermediate components are often methane and ethane. Absorbed components that are somewhat lower volatility are sometimes referred to as volatile organic compounds, or VOC components. These components are typically propane, butanes and pentanes. The VOC label refers to their classification in some cases as being restricted in terms of allowable emissions to atmosphere, typically in tons/year allowable. The VOC components will typically split in the absorption plant, with some exiting with the light unabsorbed component stream and some with the absorbed and then released intermediate components stream. These VOC range components will be absorbed, but because they are not entirely released during solvent regeneration, they can build up to become a portion of the lean solvent, resulting in some of these components having a high enough partial pressure at the top of the absorber to leave with the light component stream.

The next and lowest volatility range of heavier components is solvent-range components, typically hexane and heavier hydrocarbons. Components in this volatility range in the feed will largely become part of the solvent with small amounts leaving with the absorbed and released intermediate stream, and even smaller amounts leaving with the unabsorbed light component stream. These solvent range components are indeed used as the circulating lean solvent. These components can be entirely components that are present in the multi-component feed gas, in which case the solvent is entirely internally generated and there is no need for a purchased or imported solvent. If there are no solvent range components in the multi-component feed gas, a solvent range component or components will have to be added to establish solvent inventory. This is referred to as an external solvent. The solvent can also be a combination, a portion of external solvent is required, but some of the solvent that is being circulated is also made up from the feed gas, and can comprise solvent range components from the feed gas and VOC range components. Solvent is what is circulated in order to absorb any of the heavier components. Lean solvent is solvent that has been regenerated. Solvent is a term that is used generally throughout this application to mean physical solvent comprising hydrocarbons. Rich solvent is solvent that is leaving the bottom of the absorber, and contains the components absorbed from the feed gas. Intermediate and heavier refers to all components that are intermediate, VOC and through solvent range components, so this includes all components heavier, or with lower volatility, than the light unabsorbed components.

An improvement to the process that results in increasing the purity of one or more of the exiting streams, increases hydrocarbon recovery, reduces hydrocarbon emissions, or improves process implementation cost or reliability that does not use higher solvent circulation rates or a purer solvent is needed.

SUMMARY OF THE INVENTION

A process and apparatus for separating the components of a multi-component gas stream comprising light and intermediate volatility components. The process includes contacting the multi-component gas stream with a lean solvent in an absorber to produce a light component overhead stream and a rich solvent bottoms stream, flashing the rich solvent bottoms stream in at least one reduced pressure stage, recycling the lean solvent to the absorber, heat exchange cooling of the light component overhead stream, using at least one pressure reduction device for auto-refrigeration cooling, vapor/liquid separating the light component overhead stream in a vapor/liquid separator, reheating a vapor product stream from the vapor/liquid separator against the light component overhead stream; and removing the condensed intermediate component liquid from the vapor/liquid separator. The process also includes recycling the regenerated lean solvent to the absorber and purifying the unabsorbed light component absorber overhead stream and increasing absorbed intermediate component recovery by heat exchange cooling of the light overhead stream, auto-refrigeration cooling of one or more streams using a pressure reduction device, and vapor/liquid separation of the cooled light overhead stream. The process also includes reheating of the purified light overhead stream from the vapor/liquid separator against the light overhead stream, and removing the condensed intermediate component liquid from the vapor/liquid separator.

The apparatus includes an absorption tower containing internal equipment for contacting a feed gas with a lean solvent stream to create an light component overhead stream and a rich solvent bottom stream, a heat exchanger in contact with the light component overhead stream and a purified product stream, a vapor/liquid separator in contact with the light component overhead stream, a pressure reduction device in contact with the light component overhead stream, and a conduit for liquid from the vapor/liquid separator that is in contact with a control valve.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a prior art process for separating the components of a gas stream.

FIG. 2 is a prior art process for separating the components of a gas wherein the process includes recycling a portion of the overhead gas stream from a flash separator back to the absorber.

FIG. 3 is a prior art process for separating the components of a gas wherein multiple flashes are utilized, at least a portion of the solvent is made up of components of the inlet gas, and a solvent recovery chiller is included on the released product.

FIG. 4 is a prior art process for separating a gas stream with an additional purification and intermediate and heavier component recovery step on the product stream containing the light components.

FIG. 5A is a process wherein additional hydrocarbon is recovered from a feed gas by adding a purification/recovery step based on heat exchange within the recovery system, a single pressure reduction and separation integrated with the main solvent absorption system.

FIG. 5B is a process wherein the purification/recovery step is based on a single heat exchanger, a separation vessel, and a single pressure drop auto-refrigeration step wherein the single pressure drop is taken on the vapor stream leaving the separator.

FIG. 6 is a process wherein the purification/recovery step is based on heat exchange cooling, dual pressure reduction, and separation.

FIG. 7 is a process wherein the purification/recovery step is based on using a slip stream for the stripping of the light components from the recovered intermediate and heavier components utilizing a single pressure reduction step.

FIG. 8 is a process wherein the purification/recovery step is based on using a slip stream for the stripping of the light components from the recovered intermediate and heavier components utilizing dual pressure reduction steps.

FIG. 9 is a process wherein the purification/recovery step is based on using a slip stream for the stripping of the light components from the recovered intermediate components utilizing dual pressure reduction steps with the second pressure reduction based on the use of a turbo-expander.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

It should be understood that pipelines are in fact being designated when streams are identified hereinafter and that streams are intended, if not stated, when materials are mentioned. Moreover, flow control valves, temperature regulator devices, pumps, compressors, and the like are understood as installed and operating in conventional relationships to the major items of equipment which are shown in the drawings and discussed hereinafter with reference to the continuously operating process of this invention. All of these valves, devices, pumps, and compressors, as well as heat exchangers, accumulators, condensers and the like are included in the term “auxiliary equipment.” As used herein, “absorber” refers to any apparatus known in the art in which a gas is contacted with a solvent to absorb part of the gas into the solvent. According to certain embodiments, the absorber may include internal compounds including plates, packing, and baffles, to promote mass transfer. As used herein, referring to a process step as producing a stream that is enriched in a certain component or components means that the fractional percentage of that component or components in the produced stream, relative to the other components, is greater than the relative percentage of that component or components in the stream entering the process step.

If the feed gas contains only nitrogen and methane, the nitrogen would be the light unabsorbed component and methane would be absorbed by the solvent. The solvent would be a heavier hydrocarbon such as heptane. When the feed gas contains a wider range of components such as nitrogen, methane, ethane, propane, butanes, and heavier components, the nitrogen is the light component and methane and heavier components are absorbed. The heavier components, propane and heavier, can comprise all or a portion of the solvent. The absorbed and released components are intermediate range components.

One aspect of the present invention is a process for separating the components of a multi-component gas stream. The process comprises contacting the gas stream with a solvent to produce an overhead stream that is enriched in at least one of the components and a rich solvent bottoms stream that is enriched in at least one of the other components. This contacting step is typically performed in an absorber. Typically the solvent absorbs the heavier component(s) of the multi-component stream, leaving the light component(s) as the overhead stream. The enriched solvent bottoms stream is flashed in at least one reduced pressure stage to release the absorbed component(s), thereby regenerating the solvent and providing the absorbed and released component(s) as an overhead vapor product stream. The regenerated solvent is recycled to the absorber.

When the feed gas contains no components heavier than the intermediate absorbed and released component(s) of the feed gas, use of external solvent, such as a hydrocarbon with a carbon number of three or greater, is required to facilitate condensation and recovery of components in a light component stream. When the feed gas contains a significant amount of components heavier than the absorbed and released component(s), an internally generated solvent may be used. If the feed gas stream contains components that are heavier than the intermediate component(s), then these components will accumulate to an equilibrium level in the solvent. This will occur whether the solvent is an external solvent or an internally generated solvent. These components, which are typically in the volatile organic carbon range of propane and heavier will cause some contamination of the light or unabsorbed component, which may be significant depending on light product specifications. If the light component is nitrogen separated from natural gas and preferably vented to the atmosphere, then contamination with even small amounts of propane and heavier hydrocarbons can exceed environmental VOC regulations and reduce hydrocarbon recovery. If the light component is hydrogen separated from a refinery stream, then contamination with small amounts of components heavier than methane may reduce the hydrogen concentration and partial pressure to the extent that it is not usable for a desired refinery process. In either case, removal of propane and heavier components from the feed gas by a variety of means including cooling, chilling, and absorption could avoid these components becoming contaminates in the light unabsorbed stream.

Characteristics of the solvent used affect the circulation rate required to achieve a desired separation of feed components. Heavier components with a higher molecular weight typically have fewer, larger molecules per unit volume. Those skilled in the art will recognize that use of heavier solvents will increase the circulation requirement, will increase the power required for the circulation, will increase and cooling duty required to meet a desired solvent temperature, and will increase the size of associated equipment. When solvent components are available in the feed gas, using these components as all or part of the solvent is desirable to improve energy efficiency of the process and a lower molecular weight solvent is often the result.

The present invention removes contaminants, including VOC hydrocarbons, from the unabsorbed light component stream. It is counterintuitive that a contaminant that can be removed from a feed stream, rather than from a product stream, should be left in the feed stream and allowed to contaminate the product stream. At times, the efficiency gained by leaving the contaminant in the feed to the main absorption process is so desirable that contaminant removal from a product stream can justify using the second process step.

According to another aspect of the present invention, the contaminant is removed from the unabsorbed product stream using the technology of vapor/liquid separation at low temperatures achieved by a combination of any or all of expansion, heat exchange, and refrigeration.

The process of the present invention is generally applicable to any multi-component gas stream containing at least three components wherein the different components of the gas stream have different solubilities in a circulating solvent that is used to absorb one or more components of the multicomponent stream gas. The multi-component gas stream will typically comprise one or more hydrocarbons.

Aspects of the present invention can be better understood with reference to the drawings and the following discussion of the embodiments depicted in the drawings. Where numbered components are not specifically discussed in the text, they can be assumed to have the same identity and purpose as the corresponding numbered component in the discussion of the previous or prior drawings.

FIG. 1 shows a prior art process without solvent inventory controls that is non-specific regarding either external or internal solvent, and that does not include additional product purification steps. According to the process of FIG. 1, hydrocarbon feed gas 1 is counter-currently contacted with lean solvent 12 in absorber 13, generating an overhead stream 118 and a rich solvent bottoms stream 14. The rich solvent bottoms stream 14 is directed to one or more flash separators 15. The number of separators can vary. According to one embodiment, there is a single flash separator 15. The component absorbed in the solvent is released in separator 15, and is separated as vapor stream 16. While only one flash stage is depicted in FIG. 1, multiple separators could be used. The pressure of stream 16 is elevated via compressor 17, yielding stream 18 as a product stream of the process. The regenerated lean solvent leaves separator 15 as a liquid stream 19 and is returned to absorber 13 as stream 110 via pump 112. Lean solvent stream 110 may be cooled in solvent cooler 111 prior to re-entering the absorber 13. If the multi-component gas stream 1 entering the process of FIG. 1 comprises methane and nitrogen, for example, natural gas contaminated with nitrogen, then an external solvent would be utilized and stream 118 will be enriched with nitrogen and stream 18 will be enriched with methane. However, stream 18 is often contaminated with a significant amount of nitrogen because nitrogen co-absorbs with methane into the solvent. Ideally, contacting stream II with solvent would result in overhead stream 118 being nitrogen and stream 14 being solvent enriched only with absorbed methane. However, under real working conditions, feed composition and operating conditions result in an undesirable amount of nitrogen being co-absorbed into the solvent stream 4 along with the desired absorbed components, i.e., methane, ethane, propane and heavier components. FIG. 1 is equally applicable to separation of hydrogen from methane.

Some of the listed patents address methods to recover work from the unabsorbed light component stream or recover additional hydrocarbons from the light component stream. U.S. Pat. No. 4,623,371 discloses that a light product stream of nitrogen that will be vented to the atmosphere can be reduced in pressure using an expander to recover usable work from the vent. U.S. Pat. No. 4,680,042 discloses the application of an expander (71) used to extract energy from a separated light component nitrogen stream that is vented. U.S. Pat. No. 4,883,514 restates the use of an expansion turbine for power recovery from the light component stream.

U.S. Pat. No. 5,551,972 discloses a method for liquid recovery from the light component stream. FIGS. 2 and 3 show use of an expander located to extract work from the light component stream 24. A vapor liquid separation vessel 27 is included downstream of the expander for separation of hydrocarbons condensed due to the work extraction from the stream. This includes that a valve can be used in place of the expander, although with less hydrocarbon condensation as liquid. The separated liquid is re-introduced into the process. The addition of heat exchange of the light component stream with the feed gas to the process helps in the original cooling of the feed gas. It is indicated that use of a solvent with fewer intermediate range components reduces the amount of intermediate components in the light component stream. The light component nitrogen product stream is expanded with a turbine from 700 psia to 43 psia and reaches a minimum temperature of −215° F. at 43 psia. The uncondensed vapor is reheated by heat exchange with the plant feed gas which recovers heat resulting in reheating the cold vent to 74° F. against the feed stream of 80° F. The condensed liquids are recycled to the plant. Table 3 of U.S. Pat. No. 5,551,972 indicates that the feed stream is at a temperature of 80° F., so reheat to 74° F. is reasonable. Table 3, light product stream composition indicates high recovery of C3+ components from the light gas entering the expander, identified as Absorber Stripper Overhead. Recovery of heavier components from the light product by use of any or all of heat exchange, expansion and separation is also discussed.

FIG. 2 is a prior art process that reduces the amount that the product stream is contaminated with co-adsorbed light components. The process of FIG. 2 utilizes two flash-regeneration separators, intermediate flash 213 and final flash 25. Overhead stream 215 from intermediate flash 213 is recompressed by recycle compressor 216 and recycled to absorber 23. Final flash 25 generally operates at a lower pressure than intermediate flash 213. Because nitrogen is a lighter component than methane, intermediate flash 213 preferentially releases the co-absorbed nitrogen and preferentially leaves the desired methane in the enriched solvent 214. Nitrogen rich gas stream 215 is recompressed and returned to absorber 23, preferably at a point in the absorber that is equal to or below the feed gas stream 21. This results in stream 218 being further enriched with nitrogen. Removing co-absorbed nitrogen from stream 24 results in final product stream 28 containing less nitrogen than the product stream of the process of FIG. 1. The process according to FIG. 2 provides a higher purity product stream but requires an additional nitrogen compressor 216 and an additional flash stage 213. FIG. 2 is non-specific for use of external or internal solvent.

FIG. 3 depicts prior art that includes two points for solvent inventory control, and was developed for use with internal solvents. A multi-component gas stream 31 is cooled in chiller 32, and enters separator 33 where vapor and liquid phases are separated. The vapor phase is introduced to absorber 35, where the vapor is contacted with lean liquid solvent stream 36. The lean solvent absorbs intermediate and heavy components from the vapor, leaving the light components to exit the absorber top as vapor stream 37. The rich solvent, containing absorbed intermediate and heavy components, exits the bottom of the tower as stream 38 after being contacted with vapor recycled to the bottom of the absorber. Stream 38 is reduced in pressure by restrictor 39, and the resulting vapor and liquid phases are separated in separator 310. The vapor stream 311 contains a portion of the light component that was co-absorbed in the absorber, and this vapor is recycled via compressor 312 to re-enter the bottom of the absorber as a stripping gas. The rich solvent exiting the bottom of separator 310 as stream 313 contains the intermediate absorbed component(s) and absorbed heavy components. Sequential restrictors 314, 318, and 322, combined with sequential separators 315, 319, and 323 reduce the pressure of the rich solvent and separate the intermediate components from the circulating solvent containing heavy components. Vapor streams 316, 320, and 324 contain the intermediate components of the feed stream. Any number of flashes may actually be employed. Final separator liquid phase stream 325 is the lean solvent, with the majority of the intermediate components removed. The pressure of stream 325 is increased in pressure using pump 326 to become stream 327. Stream 327 is chilled in chiller 328 to become the lean solvent stream 36 that enters the absorber. The intermediate vapor streams 316, 320 and 324 are compressed in a multistage compressor 329 to become stream 330. This stream is chilled in chiller 331 and separated into a vapor and liquid phase in separator 332. The vapor portion exits the system as intermediate product stream 333. The liquid stream 334 contains solvent weight components that vaporized with the intermediate weight components in the separator vessels 315, 319, and 323, and were condensed by chilling at the elevated pressure of separator 332. These solvent components are re-introduced to the solvent system. If the temperature in separator 332 condenses more solvent component flow than is required to maintain the inventory of solvent in the system, then the excess solvent can be removed as a heavy product stream 335, and exit the system as stream 337. Stream 337 can be stabilized by removal of lighter components in a stripping distillation tower to meet heavy product specifications if desired. Conversely, if the temperature in separator 332 cannot recover enough heavy solvent components to maintain inventory of solvent, then condensed heavy components from separator 33, stream 336, may be added to the solvent inventory by flow in the opposite direction in FIG. 3. Control of the liquid from separators 33 and 332, along with control of the operating temperatures in these separators can be used to control inventory of internal solvent.

FIG. 4 depicts a prior art application with a non-specific recovery process FIG. 4 has additional product purification/recovery equipment 419 added to its process, resulting in purified product stream 420, and removed contaminant/recovered intermediate and heavier component product stream 421. For example, U.S. Pat. No. 5,462,583 and U.S. Pat. No. 5,551,972 provide processes that are similar to the embodiment depicted by FIG. 4. Also, U.S. patent application Ser. No. 11/211,145 discloses that a contaminant can be removed from the product streams (this includes the light component stream) by a solvent absorption regeneration system or alternatively by adsorption onto a solid, use of membranes, incineration, and also by vapor/liquid separation at low temperatures achieved by non-specific expansion, heat exchange and refrigeration. It also indicates the location of recovery from the light component stream, and a depiction of recovery if the more complex absorption regeneration system is used.

FIG. 5A depicts an embodiment of the present invention utilizing a specific arrangement of heat exchange, pressure reduction and vapor/liquid separation on the unabsorbed product stream. FIG. 5A equipment numbers and stream numbers 540-549 are indicated as improving the hydrocarbon recovery of an absorption process. Stream 57 is the overhead product stream from the absorber primarily containing the light components contaminated with intermediate and heavier hydrocarbon components. Stream 57 is cooled by cross-exchange with the purified product stream 545 in exchanger 540 where it is cooled to between −50 to −250° F. to produce stream 541. Stream 541 is then flashed via pressure reducing valve 542, where it auto-refrigerates to a lower temperature to produce the mixed phase stream 543. Stream 543 is separated in the vapor/liquid separator 544 into streams 545 and stream 546. Stream 545 has been enriched in the light component while stream 546 is enriched in the intermediate and heavier hydrocarbon components. Stream 545 is heated by cross-exchange in heat exchanger 540 to produce purified product stream 549. Stream 546 is reduced in pressure through control valve 547 to produce stream 548, which is directed to either another location within the absorption plant or delivered as a separate product composed of intermediate and heavier hydrocarbon components. When stream 548 is at adequate pressure, routing to stream 530 of the upstream process allows integration of the recovered liquid into the solvent with minimal pressure reduction.

Control valve 547 will typically control the level of condensed liquid in separator 544. Pressure in separator 544 is controlled by valve 542. The temperature of separator 544 can be controlled by a combination of pressure of separator 544 and the amount of stream 545 which bypasses exchanger 540 allowing stream 541 to be warmer. Bypass and control of bypass are not shown. Bypass of a portion of stream 57 may also be used for temperature control. Stream 549 is reheated to close to stream 57 temperature. Stream 549 can contribute to initial cooling of the main absorption process multi-component feed gas stream 51 after providing required process cooling in exchanger 540.

The pressure at the outlet of valve 542 is typically in the range of 200 to 600 psi but is selected to result in the necessary cooling to achieve the ultimate purity required for stream 545. Also, the pressure of the light component overhead stream is at least about 200 psig. The pressure of the vapor/liquid separator is greater than about 150 psig. In additional embodiments, the pressure of the vapor/liquid separator is greater than about 250 psig or even greater than about 450 psig.

FIG. 5B depicts another embodiment. The process of FIG. 5B includes all items of FIG. 5A except that FIG. 5B substitutes items 550 through 559 for items 540 through 549. The process is similar to the process of FIG. 5A, with the change that the pressure reduction valve 557 is located on the purified vapor stream 553 exiting separator 552, rather than being in the feed stream 551 that is now routed directly to separator 552 without pressure drop. Separator 552 will operate at a pressure greater than 300 psig, typically greater than 450 psig, and at a temperature of −50 F to −220 F. Stream 558 is the outlet from valve 557 in the new location, and this stream is at a lower pressure than stream 553 and is also at a lower temperature due to auto-refrigeration. Stream 558 is reheated in exchanger 550 and provides the cooling required to allow for a portion of stream 551 to be liquid and therefore separate in separator 552 and leave as recovered intermediate and heavy components in stream 554. In the process of FIG. 5b, separator 552 can operate at nearly the pressure of stream 57, while still being at a reduced temperature. In some cases, this allows for higher recovery of desired liquid components. In some cases, this arrangement allows for operation of separator 552 at warmer temperatures, and this will reduce the possibility of liquid components freezing during the recovery process, as they can be removed prior to the coldest point in the process, which is stream 558.

FIG. 6 depicts another embodiment. The process of FIG. 6 is similar to that depicted in FIG. 5A with the addition of a second pressure reducing valve 649. Stream 67 is the overhead product stream from the absorber primarily containing the light components contaminated with intermediate and heavier hydrocarbon components. Stream 67 is cooled by cross-exchange with the purified product stream 650 in exchanger 640 where it is cooled to between −50° F. to −250° F. to produce stream 641. Stream 641 is then flashed via pressure reducing valve 642, where it auto-refrigerates to produce the mixed phase stream 643. Stream 643 is separated in the vapor/liquid separator 644 into streams 645 and stream 646. Stream 645 has been enriched in the light component while stream 646 is enriched in the intermediate and heavier hydrocarbon components. The pressure of stream 645 is further reduced in pressure reducing valve 649. The temperature of the resulting stream 650, is colder and allows improved cooling of stream 67, which in turn increases the removal of the intermediate and heavier hydrocarbons from the feed stream 67. Stream 650 is heated by cross-exchange in heat exchanger 640 to produce stream 651, which is typically vented to the atmosphere. Stream 646 is reduced in pressure through level control valve 647 to produce stream 648, which is directed to either another location within the absorption plant or delivered as a separate product composed of intermediate and heavier hydrocarbon components.

The added valve 649 results in improved control of both temperature and pressure in the vapor liquid separator 644. Improved control of both temperature and pressure in separator 644 allows for the optimization of intermediate and heavier hydrocarbon contaminate removal. This dual valve configuration allows operation of separator 644 at the same or lower temperature as can be achieved by the process of FIG. 5A, but at a higher pressure, which allows disposition of hydrocarbon rich stream 648 to the most optimum location with the absorption plant and/or higher recovery of intermediate and heavier hydrocarbons, including VOC components.

FIG. 7 depicts an embodiment utilizing cooling, pressure reduction, and vapor/liquid separation via absorption. Stream 77 is the overhead product stream from the absorber primarily containing the light components contaminated with intermediate and heavier hydrocarbon components. Stream 77 is split into stream 741 and stream 746 at split 740. Stream 746 is smaller, typically 5 percent to 20 percent of stream 77. The pressure of stream 746 is reduced by pressure reducing valve 747. Resulting stream 748 is then directed to the bottom of absorber 749. Stream 741 is cooled by cross-exchange with the purified product stream 753 in exchanger 742 where it is cooled to between −100° F. to −250° F. to produce stream 743. Stream 743 is then flashed via pressure reducing valve 744, where it auto-refrigerates to produce the mixed phase stream 745. Stream 745 is then directed to the top of absorber 749. Absorber 749 is a vapor/liquid contacting device containing packing, trays, or any other mass transfer device. The vapor portion of stream 748 contacts the liquid from stream 745 flowing downward in the absorber where a portion of the light component is stripped out into the vapor phase. Some of the vapor-phase intermediate and heavier hydrocarbons from stream 1748 are simultaneously condensed into the liquid phase. Stream 753 exiting the top of absorber 749 is concentrated in the light component while stream 750 exiting the bottom of absorber 749 is concentrated in intermediate and heavier hydrocarbons. The net effect of the absorber 749 is to further enrich the overhead stream 753 in the light component and the bottom stream 750 in the intermediate and heavier hydrocarbon components above that achieved by the embodiment depicted in FIG. 5A. Note also that by splitting stream 77 and having a lower flow rate through exchanger 742, additional cooling of stream 742 is possible, resulting in colder streams 743 and 745, which also aids in condensation of heavier components.

FIG. 8 illustrates an embodiment utilizing cooling, pressure reduction and vapor/liquid separation via absorption. The process of FIG. 8 is similar to that depicted in FIG. 7 with the addition of a second pressure-reducing valve 854, which causes additional cooling of absorber overhead stream 853 due to pressure reduction, allowing additional heat exchange in exchanger 842 and a reduction in the temperature of streams 843 and 845. Stream 87 is the overhead product stream from the absorber containing the light components contaminated with intermediate and heavier hydrocarbon components. Stream 87 is split into stream 846 and stream 841. Stream 846 is smaller, typically 5 percent to 20 percent of stream 87. The pressure of stream 846 is reduced by pressure reducing valve 847. Resulting stream 848 is then directed to the bottom of absorber 849. Stream 841 is cooled by cross-exchange with the purified product stream 855 in exchanger 842 where it is cooled to between −50° F. to −250° F. to produce stream 843. Stream 843 is then flashed via pressure reducing valve 844, where it auto-refrigerates to produce the mixed phase stream 845. Stream 845 is then directed to the top of absorber 849. Absorber 849 is a vapor/liquid contacting device containing packing, trays, or any other mass transfer device. The vapor portion of stream 848 contacts the liquid flowing downward in the absorber where a portion of the light component is stripped out into the vapor phase. Some of the vapor-phase intermediate and heavier hydrocarbons in stream 848 are simultaneously condensed into the liquid phase. Stream 853 exiting the top of absorber 849 is concentrated in the light component while stream 850 exiting the bottom of absorber 849 is concentrated in intermediate and heavier hydrocarbons. The net effect of the absorber 849 is to further enrich the overhead stream 853 in the light component and the bottom stream 850 in the intermediate and heavier hydrocarbon components above that achieved by the embodiment depicted in FIG. 5A.

The added valve 854 results in improved control of both temperature and pressure in the absorber 849. Improved control of both temperature and pressure in absorber 849 allows for the optimization of intermediate and heavier hydrocarbon contaminates removal. This dual valve configuration allows operation of absorber 849 at a higher pressure, which allows disposition of hydrocarbon rich stream 852 to the most optimum location with the absorption plant. Optimal location includes routing to flash vessel 810, wherein any light component in the recovered liquid can still be recycled to the absorber 85 without affecting quality of the final product stream 833. Routing to flash vessel 810 also minimizes the pressure drop for stream 852, which minimizes the flow capacity of the actual pipe should the liquid level in absorber 849 drop unexpectedly resulting in vapor blowby.

FIG. 9 depicts an embodiment, which is the same as that depicted in FIG. 8 with the exception that the pressure-reducing valve 854 is replaced with a turbo-expander 15. The turbo-expander 945, in addition to resulting in additional cooling of the feed stream and hence improved purity of the product streams 920 and 921, extracts energy from stream 914. This energy extraction could be utilized to generate power or compress other gas streams in the process.

ADVANTAGES

Use of this process increases recovery of valuable hydrocarbons from the light overhead stream, reduces hydrocarbon emissions when the light component stream would be nitrogen vented to atmosphere, allows use of intermediate weight components in the solvent that improve absorption efficiency as potential emissions are no longer a limitation, allows this recovery at warmer temperatures than prior art and also allows for recovery of these hydrocarbons at pressure higher than prior art that allows for increased flexibility of for use of the recovered liquid hydrocarbons.

All of the processes depicted in FIGS. 5A through 9 utilize cooling by heat exchange with streams in the purification section, auto-refrigeration cooling by pressure drop, and separation of condensed components from the purified vapor. The valve 557 of FIG. 5B, valve 649 of FIG. 6, valve 854 of FIG. 8, and expander 954 of FIG. 9 are important to allow the separation of components a higher temperature than other processes, allowing the process to meet higher BTU recovery or VOC reduction goals at separator temperatures of −250° F. or higher such as −200° F. or even −175° F. or warmer. Additional variations are possible and are included in this invention disclosure, including reheating the recovered liquid to further cool the incoming vapor, utilizing expanders or hydraulic turbines instead of valves for pressure drop auto refrigeration, using simple pressure regulators in place of pressure control valves, providing one or more additional separators, enabling heavier components to be separated prior to cooling below its freeze point, providing pressure drop auto refrigeration only on the purified separator gas in order to allow the separator to operate at inlet pressure less heat exchange pressure drop only. Operability items and controls are also not indicated in the figures. These can include bypass pipes and controls around heat exchangers, dehydration of feed steam 57 from the absorber in FIG. 5A by molecular sieve or other method when required to prevent freezing or hydrate formation, injection points for methanol for hydrate prevention or thawing of hydrates, bypass lines to allow backflow of warm gas for thawing any hydrates intermittently, line and control valve sizing that can be useful to prevent flow rates that are too high or large vapor flow out the recovered liquid stream line should the control valve fail open, or the possibility of adding a small amount of a heavier intermediate component to stream 57 in FIG. 5A (or other absorber overhead streams in other figures) in order to aid condensation of intermediate and heavier components. It is also possible to add a second technology upstream or downstream of the present invention; in particular to use a membrane separation technology to increase hydrocarbon recovery and or reduce VOC content of the inert gas stream.

The use of this invention as demonstrated in the above examples and descriptions can reduce VOC hydrocarbon emissions to atmosphere by more than 95 percent from a facility removing nitrogen from natural gas. This same invention will result in a 40 percent reduction in loss of heating value BTU's, and an increase in production of saleable natural gas liquids. These dramatic improvements are accomplished without the use of additional energy. No additional rotating equipment such as pumps, compressors, or expanders is required. The recovery can take place at a higher pressure than prior art, very nearly the pressure of the incoming light overhead product stream which allows for many options for best routing of recovered liquids, and also this is accomplished at warmer temperatures than prior art. The warmer temperature reduces any chance of hydrocarbon solids forming, either through freezing or hydrate formation. The process can also remove the liquids formed prior to the lowest operating temperature. Use of the purified light component stream to pre-cool the light component stream in an exchanger, with as few as one simple adiabatic pressure reduction point allows for this. This addition that recovers the intermediate volatility range components to prevent their vent to atmosphere, allows for use of lighter solvents in the main absorption plant facility and the use of lighter solvents can increase overall efficiency of the facility. As this light component stream purification invention process does not require rotating equipment, maintenance will be low, on-stream factor and operability will be high, and there are no utility costs. This invention can produce improved revenue streams that will pay for the improvement, at the same time as providing environmental benefits that at times can be required to permit building a facility.

EXAMPLE 1

This example compares the process of the present invention as described in FIG. 5A with the prior art process described in FIG. 3 with regard to their ability to process a gas stream comprising methane and nitrogen and heavier components by absorbing the methane away from the nitrogen in order to produce a methane stream that meets typical pipeline quality for inert content. The comparison is conducted under conditions such that a prior art process according to FIG. 3 utilizes an internal solvent made up of the heavier components of the feed stream, and solvent inventory is controlled by use of a product hydrocarbon gas chiller 331 for solvent recovery. Excess condensed hydrocarbon liquid from the product hydrocarbon gas stream is routed to a stabilizer to produce a separate liquid product.

The feed gas characteristics used for this example are a flow rate of 10 MMscfd, pressure of 600 psig, temperature of 120° F., and a composition of the following, in mole percent: nitrogen −24.24, methane −62.42, ethane −8.08, propane −3.42, i-butane −0.38, n-butane −0.82, i-pentane −0.16, n-pentane −0.19, n-hexane −0.13, n-heptane −0.10, carbon dioxide −0.06.

The prior art process in FIG. 3 is operated with the feed chilled to −25° F. as stream 34 and 336, the lean solvent stream 36 also chilled to −25° F., the solvent recovery chiller 331 operated at a temperature of −25° F. to maintain solvent inventory and to produce a separate hydrocarbon liquid product, and a solvent circulation rate of about 800 gpm. This results in an intermediate product sales gas (stream 333) composition containing only 3.3 percent nitrogen, easily within pipeline specification for nitrogen content, and a nitrogen vent light product stream (stream 37) operating at −24° F. at a pressure of 570 psia with a composition of less than 5 percent methane and heavier hydrocarbon and over 95 percent nitrogen. Stream 37 is used to precool the feed gas 31 in this example. Also, stream 336 is routed to the absorber 35, and the separator 332 is operated as a stabilizer in order to produce a saleable liquid product bottoms stream, both of these being minor deviations from the prior art. Separator (stabilizer) 332 operates at a pressure of 370 psia

The key results of operating the process represented by FIG. 3 are shown in Table I below.

TABLE I

Nitrogen Rejection from Natural Gas According to FIG. 3.

Process Parameter
Unit
Value

Energy Requirements
HP
3940

Liquid Production
BPD
176.9

BTU Recovery
% Of Feed
98.29

C3+ VOC in N2 Vent
Tons/Yr
426.6

This process may not meet all desired purity specifications. The light component vent stream 37 of FIG. 3 is a very significant enrichment of nitrogen, and higher solvent circulation can increase the purification. However, increased solvent circulation will increase the overall energy requirements of the facility. Use of the light internally generated solvent (about 80 molecular weight) leads to over 425 tons/year of propane and heavier content in the vent stream, which may well exceed environmental goals. The BTU recovery is 98.29 percent and is based on the feed BTUs less the BTUs contained in the vented stream 7. Liquid production is based on excess propane and heavier hydrocarbon components contained in the feed gas and not needed to maintain the circulating solvent inventory, and removed as a stable product from stabilizer 332.

Using the process of FIG. 5A, the light component vent stream (represented by stream 37 in FIG. 3) can be purified. Conditions for the process of FIG. 3 are not changed. In FIG. 5A, an absorber overhead product exchanger, pressure reduction, and separator scheme is added to the process to purify the light component vent stream and recover additional intermediate and heavier hydrocarbons. Operation of the separator (item 544 in FIG. 5A) at a pressure slightly above the solvent recovery system of FIG. 3 (items 531 and 532) and allows direct flow of the recovered liquids to the solvent recovery system. In this example the separator 544 operates at 419 psia and −77° F. The light component nitrogen vent propane and heavier VOC content is reduced from about 425 tons/year to about 330 tons/year. The results are indicated in Table II. BTU recovery of the system is increased by 0.13 percent and the C3+ VOC content is reduced by 96 tons/year using this process.

TABLE II

Nitrogen Rejection from Natural Gas According to FIG. 3.

with the Process of FIG. 5A Added to the Vent Stream

Process Parameter
Unit
Value

Energy Requirements
HP
3940

Liquid Production
BPD
179.4

BTU Recovery
% Of Feed
98.42

C3+ VOC in N2 Vent
Tons/Yr
330.6

Details of the operation according to FIG. 5A used to generate the information in Table II follow. Absorber light component vapor overhead stream 57 pressure and temperature are the same as for FIG. 3, 570 psia and −24° F. Other stream conditions are as follows: stream 541, 565 psia and −69° F.; streams 543, 546 and 545, 419 psia and −77° F.; stream 548, 403 psia and −77° F.; stream 549, 414 psia and −29° F. Stream 548 is routed to the stabilizer 532. Stream 549 is used to precool stream 51.

Note that there are many different operating conditions possible. Higher VOC reduction in the vent with higher BTU recovery also can be achieved by operating valve 542 to create a larger pressure drop. This precludes routing the recovered liquid to stabilizer 532 without adding a pump (not shown), and also the operating temperature is much colder. Minimum VOC in the purified light product stream is achieved by reducing the pressure in separator 544 to 150 psia. The accompanying conditions are: stream 541, 565 psia and −140° F., streams 543, 546, and 545 150 psia and −173° F., and stream 549, 135 psia and −29° F. This lower operating pressure produces the following results: Energy Requirements of 3945 HP, Liquid Production of 184.5 BPD, BTU Recovery of 98.91, and C3+ VOC in the N2 vent of 28 Tons/year.

Making the one simple change of moving the pressure reduction point as shown in FIG. 5B can allow for very high recovery and VOC reduction while having almost no pressure drop upstream of the separator. In this case, the operating conditions are as follows: stream 57, 570 psia and −24° F.; stream 551, 554, and 553, 565 psia and −172° F., stream 558 145 psia and −215° F.; stream 559, 140 psia and −29° F. Corresponding results are: Energy Requirements of 3946 HP, Liquid Production of 184.9 BPD, BTU Recovery of 98.96, and C3+ VOC in the N2 vent (stream 549) of 24 Tons/year. Note that this performance exceeds that of FIG. 5A operating at low separator pressure in VOC reduction and other measures, while maintaining a high separator pressure, and operating the separator at a slightly warmer temperature.

The above Example 1 can be equally applied to separation of hydrogen from methane, with the purity of the hydrogen product and/or methane product affected by a component in the feed gas, such as ethane, propane, carbon dioxide, hydrogen sulfide, and so on.

EXAMPLE II

This example compares the process of the present invention as described in FIG. 6 with the prior art process described in FIG. 3 and as indicated above in EXAMPLE I, the results of which are shown in Table I above. The absorber overhead product stream cooler, dual pressure reduction, and separator arrangement is added to the process to purify the vent stream and recover additional hydrocarbons. Operating conditions used for this case are as follow: Stream 67, 570 psia and −24° F.; stream 641, 565 psia and −160° F.; streams 643, 646, and 645, 419 psia and −172° F.; stream 650, 145 psia and −200° F.; stream 651, 140 psia and −29° F. Operating pressure of separator 644 is the same as in the original conditions for FIG. 5A above, and VOC content of the vent stream is even lower than use of the process as described by FIG. 5B, while the minimum temperature in the system is −200° F. versus −215° F. in the process of FIG. 5B. The results are indicated in Table III. Compared to the results of Table I, the BTU recovery is increased by 0.67 percent of the feed, which is a 40 percent reduction in losses. Additionally, the VOC is reduced by 95.1 percent. Use of the operation according to FIG. 6 has desirable results with the greatest flexibility and control of actual operation due to the use of two pressure reduction points.

TABLE III

Nitrogen Rejection from Natural Gas According to FIG.

3. with the Process of FIG. 6 Added to the Vent Stream

Process Parameter
Unit
Value

Energy Requirements
HP
3946

Liquid Production
BPD
184.7

BTU Recovery
% Of Feed
98.96

C3+ VOC in N2 Vent
Tons/Yr
20.85

EXAMPLE III

This example compares the process of the present invention as described in FIG. 8 with the prior art process described in FIG. 3 and as indicated above in EXAMPLE I, the results of which are shown in Table I above. The absorber overhead stream cooler, dual pressure reduction, absorber separator scheme is added to the process to purify the light component vent stream and recover additional hydrocarbons. Operation of the absorber (item 849 in FIG. 8) at a pressure slightly above the solvent recovery system allows direct flow of the recovered liquids to the solvent recovery system. Operating conditions for this case are as follows: stream 87, 570 psia and −24° F.; stream 841 comprising 95% of stream 87, and stream 846 comprising 5 percent of stream 87; stream 843, 565 psia and −169°; stream 845, 419 psia and −181° F.; stream 848, 419 psia and −31° F.; stream 850, 419 psia and −83° F.; stream 853, 419 psia and −177° F.; stream 855, 200 psia and −200° F.; and stream 856, 195 psia and −29° F. In this example the purified light component nitrogen vent propane-plus VOC is reduced from about 425 tons/year in FIG. 3 to less than 15 tons/year. The results are indicated in Table IV.

TABLE IV

Nitrogen Rejection from Natural Gas According to FIG.

3. with the Process of FIG. 8 Added to the Vent Stream

Process Parameter
Unit
Value

Energy Requirements
HP
3946

Liquid Production
BPD
184.2

BTU Recovery
% Of Feed
98.97

C3+ VOC in N2 Vent
Tons/Yr
14.52

These examples separate the design and performance of the current invention from earlier referenced patents provided. The example performance is achieved without the use of expanders, although they can be used. The above example II best demonstrates a number of improvements including 1) condensed hydrocarbons are separated at the relatively warm temperature of −172° F. reducing the possibility of solidification of the hydrocarbons, 2) lower temperatures that may be required are only present after the separation of the heavier components that may freeze have been removed, 3) separation at higher pressure allows more possibilities for recycle of the liquid, including recycle to the first flash regeneration step which would allow any condensed nitrogen (light component) to be recycled along with co-absorbed nitrogen, or recycle to a solvent recovery section or stabilizer operating above 400 psia 4) warmer temperatures reduce the need for and the risk of hydrate formation, 5) higher final (lowest) light component product pressure reduces associated equipment sizing, especially if this stream is used in heat exchangers, 6) decoupling the method of reducing temperature and separation pressure by use of two valves provides superior control and flexibility for recovery of intermediate and heavier component liquids and also purity of the recovered liquids by choosing best relative volatility points for temperature and pressure, even when excluding the improvement possible by use of the absorber in Example III.

All of the methods and apparatus disclosed herein can be made and executed without undue experimentation in light of the present disclosure. While the methods of this invention have been described in terms of specific embodiments, it will be apparent to those of skill in the art that variations may be applied to the methods and apparatus and in the steps or in the sequence of steps of the methods described herein without departing from the concept, spirit and scope of the invention. All such similar substitutes and modifications apparent to those skilled in the art are deemed to be within the spirit, scope, and concept of the invention as defined by the following claims.

Hydrocarbon recovery and light product purity when processing gases with physical solvents

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