Integrated Acid Gas And Sour Gas Reinjection Process

Abstract

A method for hydrocarbon processing is provided. In one or more embodiments, the method includes splitting a hydrocarbon stream comprising natural gas and acid gas into a first stream and a second stream. Alternatively, the first stream and second stream may be provided from other sources. The first stream is processed to remove a portion of the acid gas therefrom, thereby producing a third stream comprising the acid gas removed from the first stream and a fourth stream comprising less than 100 ppm of sulfur-containing compounds. The second stream is combined with the third stream to provide a combined stream, which is compressed and reinjected into a subterranean reservoir.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application 60/633,361, filed 3 Dec. 2004.

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the present invention generally relate to methods for injecting hydrocarbon streams and/or waste streams derived from produced hydrocarbon streams into the subsurface, and to hydrocarbon products derived from such methods.

2. Description of the Related Art

Raw natural gas and condensate most often contain acidic impurities including sulfur-containing compounds that must be removed prior to use. A typical purification process separates the sulfur-containing compounds from the hydrocarbon stream. The separated sulfur compounds are then usually converted into non-toxic, non-hazardous elemental sulfur. This elemental sulfur is often shipped to sulfuric acid plants, or stored for later use.

Sulfur removal is often the most difficult in terms of both recovery and cost due to increasingly stringent environmental regulations and product specifications. Further, it is generally not desirable to generate elemental sulfur since there is a glut of sulfur in most markets. There is a need, therefore, for a cost effective treatment process that requires less capital expenditure and less operating expenditure for producing purified hydrocarbon gas for consumption purposes without the hassles and associated expense of separating and converting sulfur impurities into elemental sulfur.

Additional information relating to the field of the invention can be found in: R. C. Haut et al., “Development and Application of the Controlled-Freeze-Zone Process,” SPE Production Engineering, The Society, Richardson, Tex., vol. 4, no.3, August 1989, pp. 265-271 (ISSN 0885-9221); E. R. Thomas et al., “Conceptual Studies for CO₂/Natural Gas Separation Using the Controlled Freeze Zone (CFZ) Process,” Gas Separation & Purification, vol. 2 June 1988 pp. 84-89; U.S. Pat. No. 5,956,971 (Cole et al.); P. S. Northrop et al., “Cryogenic Sour Gas Process Attractive for Acid Gas Injection Applications,” Proceedings Annual Convention—Gas Processors Association, 14 Mar. 2004, pp. 1-8; and U.S. 2003/131726 (Thomas et al.).

SUMMARY OF THE INVENTION

A method for hydrocarbon processing is provided. In one or more embodiments, the method includes providing a first hydrocarbon stream comprising methane and acid gas and a second hydrocarbon stream comprising methane and acid gas. Alternatively the first and second hydrocarbon streams are provided by splitting a feed stream into the first and second hydrocarbon streams. Alternatively, the first stream and second stream may be provided from other sources. The first stream is processed to remove a portion of the acid gas therefrom, thereby producing a third stream comprising the acid gas removed from the first stream and a fourth stream comprising less than 100 ppm of sulfur-containing compounds. The second stream is combined with the third stream to provide a combined stream, which is compressed and reinjected into a subterranean reservoir. In one or more embodiments described above or elsewhere herein, the combined stream is compressed to a discharge pressure of about 200 bar or more prior to reinjection.

An alternative embodiment of the invention includes a method for producing natural gas. The method including providing a first hydrocarbon stream comprising methane and acid gas and a second hydrocarbon stream comprising methane and acid gas. Processing the first stream to remove a portion of the acid gas therefrom, thereby producing a third stream comprising the acid gas removed from the second stream and a fourth stream comprising less than 100 ppm of sulfur-containing compounds. Combining the second stream with the third stream to provide a combined stream, compressing the combined stream and passing the combined stream to a subterranean reservoir.

In at least one other embodiment, the method includes at least partially separating a hydrocarbon stream comprising methane, ethane, propane, carbon dioxide, water, one or more sulfur-containing compounds, and of from 0.5% to 10% by volume of one or more hydrocarbons having four or more carbon atoms. The hydrocarbon stream is at least partially separated at conditions sufficient to produce a first stream comprising one or more sulfur-containing compounds and at least 2% by volume of the carbon dioxide based on the total volume of the second stream and a second stream comprising one or more hydrocarbons having four or more carbon atoms. The first stream is treated in a distillation column having a controlled freeze zone (CFZ) to produce a third stream containing methane and lighter compounds (e.g., nitrogen and helium) and a fourth stream containing carbon dioxide, one or more sulfur-containing compounds, ethane, and certain heavier hydrocarbons. The second stream is bypassed around the distillation column and mixed with the fourth stream to produce a combined stream. The combined stream is then passed into a subterranean reservoir.

Further, a method for producing natural gas is provided. In at least one embodiment, the method includes providing a first hydrocarbon stream comprising methane and acid gas and a second hydrocarbon stream comprising methane and acid gas. The first stream is processed to remove a portion of the acid gas therefrom, thereby producing a third stream comprising the acid gas removed from the second stream and a fourth stream comprising less than 100 ppm of sulfur-containing compounds. The second stream is combined with the third stream to provide a combined stream that is compressed and passed to a subterranean reservoir. The fourth stream is liquefied to form a liquefied natural gas stream.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.

FIG. 1 schematically depicts a process 100 for processing a portion of a hydrocarbon stream required for consumption as a fuel gas or sales gas or both, and reinjecting the remainder of the hydrocarbon stream.

FIG. 2 is a schematic process flow diagram of an illustrative distillation process 200 that utilizes a column 225 having a controlled freeze zone (CFZ) according to one embodiment described herein.

FIG. 3 schematically depicts an alternative process 300 for processing a portion of a hydrocarbon stream required for consumption as a fuel gas or sales gas or both, and reinjecting the remainder of the hydrocarbon stream. This process 300 is similar to the process 100 of FIG. 1, but also provides a low temperature separation unit 310 prior to the sour gas processing unit 125.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

Introduction and Definitions

A detailed description will now be provided. Each of the appended claims defines a separate invention, which for infringement purposes is recognized as including equivalents to the various elements or limitations specified in the claims. Depending on the context, all references below to the “invention” may in some cases refer to certain specific embodiments only. In other cases it will be recognized that references to the “invention” will refer to subject matter recited in one or more, but not necessarily all, of the claims. Each of the inventions will now be described in greater detail below, including specific embodiments, versions and examples, but the inventions are not limited to these embodiments, versions or examples, which are included to enable a person having ordinary skill in the art to make and use the inventions, when the information in this patent is combined with available information and technology.

Various terms as used herein are defined below. To the extent a term used in a claim is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent.

The term “gas” is used interchangeably with “vapor,” and means a substance or mixture of substances in the gaseous state as distinguished from the liquid or solid state.

The term “acid gas” means any one or more of carbon dioxide (CO₂), hydrogen sulfide (H₂S), carbon disulfide (CS₂), carbonyl sulfide (COS), mercaptans (R—SH, where R is an alkyl group having one to 20 carbon atoms), sulfur dioxide (SO₂), combinations thereof, mixtures thereof, and derivatives thereof.

The term “sour gas” means a gas containing undesirable quantities of acid gas, e.g., 55 parts-per-million by volume (ppmv) or more, or 500 ppmv, or 5 percent by volume or more, or 15 percent by volume or more, or 35 percent by volume or more.

Specific Embodiments In Drawings

Specific embodiments shown in the drawings will now be described. It is emphasized that the claims should not be read to be limited to aspects of the drawings. FIG. 1 schematically depicts an exemplary process for processing a hydrocarbon stream according to the embodiments described. In one or more embodiments, a well stream 10 that contains one or any combination of natural gas, gas condensate, and volatile oil, is cooled and separated into gas, oil, and water phases using a separator 110, such as a pressure vessel for example. The well stream 10 is preferably separated at about 40° C. or more and about 60 bar or more. The oil and water phases are processed as needed. The gas phase is a hydrocarbon feed stream 11 that is split into at least a first portion or “first stream” 20 and a second portion or “second stream” 30. As such, the first stream 20 and the second stream 30 have identical compositions. The first stream 20 is directed to a gas processing unit 125 to remove acid gas, producing a product stream 40 for fuel, or sales, or both, and a disposal stream 50. The second stream 30 bypasses the gas processing unit 125 and is combined with the disposal stream 50 to provide a combined stream 60. The combined stream 60 is compressed by the compressor 150 and then reinjected or otherwise passed into a subterranean reservoir 175 for disposal, for use as a pressure maintenance fluid, or for use as an enhanced oil recovery (EOR) agent.

The feed stream 11 can be any hydrocarbon-containing stream. An illustrative feed stream 11 is a sour gas stream that originates from one or more hydrocarbon production wells either on-shore or off-shore or both. For example, the feed stream 11 can be a combined stream from two or more different wells. An illustrative feed stream 11 includes of from about 20% by volume to about 95% by volume of methane. Preferably, the feed stream 11 includes of from about 50% by volume to about 90% by volume of methane. In addition to containing methane and one or more other hydrocarbons, an illustrative feed stream 11 may include carbon dioxide, one or more sulfur-containing compounds and other impurities. For example, the feed stream 11 may include up to 15% by volume of one or more sulfur-containing compounds and other impurities, of from about 2% by volume to about 65% by volume of carbon dioxide, and of from about 20% by volume to about 90% by volume of one or more hydrocarbons. Common impurities in the feed stream 11 may include, but are not limited to, water, oxygen, nitrogen, argon, and helium. Illustrative sulfur-containing compounds may include, but are not limited to, mercaptans, hydrogen sulfide, carbon disulfide, disulfide oil, and carbonyl sulfide.

Of the one or more hydrocarbons, up to 10% by volume can be carbon-containing compounds having at least four carbon atoms, such as butane, pentane, hexane, and aromatics, for example. Illustrative aromatics include, but are not limited to, benzene, toluene, ethylbenzene and xylene.

In one or more embodiments, the split of the feed stream 11 is determined by the volume of gas that is needed for fuel gas and/or sales gas. As such, the volume of gas that is needed for fuel and/or sales is directed to the sour gas processing unit 125 as the first stream 20 and the balance of the feed stream 11 is split into the second stream 30 and bypassed around the sour gas processing unit 125. For example, at least 10% by volume of the feed stream 11 is split into the first stream 20 and processed in the sour gas processing unit 125 to produce fuel gas, sales gas, or both. In one or more embodiments, at least 15%, 20%, 30%, 40%, or 50% of the feed stream 11 is split into the first stream 20 and processed in the sour gas processing unit 125. In one or more embodiments, of from about 10% by volume to about 50% by volume of the separated feed stream 11 is split into the first stream 20. In one or more embodiments, at least 15%, 20%, 30%, 40%, or 50% of the feed stream 11 is split into the second stream 30. In one or more embodiments, of from about 15% to about 50% of the feed stream 11 is split into the second stream 30. In one or more embodiments, of from about 15% to about 30% of the feed stream 11 is split into the second stream 30.

Although not shown in FIG. 1, the feed stream 11 can be dehydrated to remove water prior to the gas processing unit 125. Any technique for removing water from a gaseous stream can be used. For example, the feed stream 11 can be dehydrated by passing the feed stream 11 through a packed bed of molecular sieves. In one or more embodiments, one or both of the individual split streams 20, 30 can be dehydrated in lieu of or in addition to dehydrating the feed stream 11 as described above.

Gas Processing Unit 125

The gas processing unit 125 removes acid gas and other impurities from the first stream 20. The acid gas and other impurities may be removed from the first stream 20 using any separation process known in the art. For example, the acid gas and other impurities can be removed using a solvent extraction process. The term “solvent extraction process” encompasses any process known in the art for extracting acid gases using a solvent. For example, the first stream 20 can be passed to a contactor and contacted with a counter-current flow of solvent at a pressure ranging from a low of 10 bar, 20 bar, or 30 bar to a high of 80 bar, 90 bar, or 100 bar. The contactor can be an absorber tower or column, such as a bubble-tray tower having a plurality of horizontal trays spaced throughout or contain a packing material for liquid vapor contacting.

A preferred solvent will physically and/or chemically absorb, chemisorb, or otherwise capture the acid gases from the first stream 20 upon contact. Illustrative solvents include, but are not limited to, alkanolamines, aromatic amines, diamines, sterically hindered amines, mixtures thereof or derivatives thereof. Specific amines include monoethanolamine (MEA), diethanolamine (DEA), diglycolamine, methyldiethanolamine (MDEA; with and without activator), di-isopropanolamine (DIPA), triethanolamine (TEA), and dimethylaniline, for example. Other suitable solvents may include, for example, polyethylene glycol ethers and derivatives thereof, carbonates, sulfites, nitrites, caustics, methanol, sulfolane, and N-methyl-2-pyrrolidone (NMP), either alone or in combination with the amines listed above.

In operation, the first stream 20 flows upward through the contactor while the lean solvent flows downward through the contactor. This is also known as counter-current flow. The solvent strips or otherwise removes the acid gas and other impurities from the first stream 20, producing the product stream 40 for fuel, or sales, or both. The solvent having the removed acid gas and other impurities (i.e. “rich solvent”) is then regenerated using techniques well known in the art. Details of an illustrative absorption process are described in U.S. Pat. No. 5,820,837.

A selective absorption process can also be used. A selective absorption process may be used alone or in combination with the solvent extraction process described above. Such selective absorption techniques are well known in the art and are more selective toward a particular chemical specie, such as hydrogen sulfide for example. Illustrative selective absorbents include Flexsorb™ and Flexsorb SE™ which are commercially available from Exxon Mobil Research and Engineering. An MDEA solvent as described above may also be used. Additional details can also be found in U.S. Pat. No. 5,820,837.

Cryogenic Distillation

In one or more embodiments, the acid gas and other impurities can be removed from the first stream 20 using a cryogenic distillation process. The first stream 20 is fed to a distillation column operated at a low temperature and refluxed with a refrigerated overhead stream. The first stream 20 can be chilled prior to the column using cross-exchange with other process streams, external refrigeration streams, or adiabatic expansion, such as expansion through a Joule-Thompson (“J-T”) valve or an expander, for example. A portion of the overhead stream is the product stream 40 and a portion of the bottoms from the column is recovered as the disposal stream 60. The amount of acid gas in the overhead can be controlled through the design of the column, such as the number of trays, operating temperature, operating pressure, etc., and through modification of the reflux rate.

The temperature and pressure of the column are controlled so that a solid phase is not formed at any location within the column. In one or more embodiments, the pressure of the column is preferably of from about 20 bar to about 50 bar, and the operating temperature of the column is from about −100° C. to about 10° C. More preferably, the pressure of the column is of from about 20 bar to about 35 bar, and the operating temperature of the column is from about −50° C. to about 0° C.

Typically, the operating temperature and pressure of the column depend on the concentration of the carbon dioxide in the first stream 20. Preferably, the concentration of the carbon dioxide in the first stream 20 is from about 2% by volume to about 10% by volume. For carbon dioxide concentrations of about 10% by volume or more, a cryogenic distillation process having a controlled freeze zone (CFZ) is preferred. Additional details of an illustrative cryogenic distillation process is described in U.S. Pat. No. 4,533,372.

CFZ (FIG. 2)

FIG. 2 is a schematic process flow diagram of an illustrative distillation process 200 that utilizes a column 225 having a controlled freeze zone (CFZ) as shown and described in U.S. Pat. Nos. 4,533,372; 4,923,493; 5,062,270; 5,120,338; and 5,956,971. The column 225 is separated into three distinct sections including a lower distillation section 230, middle controlled freezing zone 235, and an upper distillation section 240. The second stream 20 is introduced into the lower distillation section 230. The second stream 20 can be chilled and/or expanded prior to entering the column 225. Alternatively, a Joule-Thomson valve may be used in place of the expander. The internals of the lower section 230 can include trays, downcorners, weirs, packing, or any combination thereof.

A liquid stream 210 that contains carbon dioxide exits the bottom of the lower section 230 and a portion of the liquid stream 210 is heated in a reboiler 215. The liquid stream 210 contains the acid gas and some of the ethane and heavier hydrocarbons from the first stream 20. A portion of the liquid stream 210 returns to the column 225 as reboiled vapor. The remainder of the liquid stream 210 leaves the process 200 as the bottoms product which is the stream 50. The reboiler 215 typically operates in a temperature range of from about −10° C. to about 10° C. The reboiler 215 can be controlled to leave less than about 5% by volume methane in the stream 50, such as less than 4%, or less than 3%, or less than 2%, or less than 1%.

The lighter vapors exit the lower section 230 via a chimney tray 216, and contact a liquid spray from nozzles or spray jet assemblies 220. The vapor then continues up through the upper distillation section 240 and contacts reflux introduced to the column 225 through line 218. The vapor exits the column 225 through an overhead line 214. A portion of the vapor is returned to the top of the column 225 as liquid reflux via a refrigeration loop 250. The remainder of the vapor is removed from the process 200 as fuel gas, sales gas or both in stream 40.

The overhead refrigeration loop 250 includes a cross exchanger 255 for extracting cold energy from the vapor leaving the column via line 214. The warmed vapor stream 257 from the exchanger 255 is compressed in compressor 270 and cooled in cooler 280. A portion of the cooled vapor stream 282 is passed through the exchanger 255 and is at least partially condensed to form stream 254. The at least partially condensed stream 254 is then expanded in expander 255, and returned to the upper distillation section 240 of the column 225 via line 218.

The liquid in the upper distillation section 240 is collected and withdrawn from the column 225 via line 262. The liquid in line 262 may be accumulated in vessel 265 and returned to the controlled freezing zone 235 via spray nozzles 220. The vapor rising through the chimney tray 216 meets the spray emanating from the nozzles 220. Here, the gaseous carbon dioxide of the rising vapor contacts the sprayed cold liquid and freezes. The solid carbon dioxide falls to the bottom of the controlled freezing zone 235 and collects on the chimney tray 216. A level of liquid (possibly containing some melting solids) is maintained in the bottom of the controlled freezing zone 235. The temperature can be controlled by an external heater (not shown). The heater can be electric or any other suitable and available heat source. The liquid flows down from the bottom of controlled freezing zone 235 through exterior line 272 into the upper end of the bottom distillation section 230.

Referring again to FIG. 1, the disposal stream 50 is combined with the bypassed second stream 30 to form the combined stream 60. In the event the disposal stream 50 has a lower pressure than the second stream 30, the disposal stream 50 may be pumped to a higher pressure and then vaporized using cross-exchange with another process stream or other heating media. Further, a disposal stream 50 may be pumped to a higher pressure and flashed into the bypassed second stream 30. Still further, a lower pressure disposal stream 50 may be vaporized and then compressed to a higher pressure.

In one or more embodiments, the disposal stream 50 and the bypassed second stream 30 are mixed. The two streams 30, 50 may be mixed in a pressure vessel or static mixer (not shown). Alternatively, the streams 30, 50 may be mixed within piping having a sufficient length and geometry to sufficiently mix the streams.

In one or more embodiments, the combined stream 60 is a high molecular weight gas. For example, the combined stream 60 can have a specific gravity of greater than 0.5. In one or more embodiments, the combined stream 60 has a specific gravity of greater than 0.6, greater than 0.7, or greater than 0.8. In one or more embodiments, the combined stream 60 has a specific gravity of greater than 1.0. In one or more embodiments, the combined stream 60 has a specific gravity ranging from a low of 0.5, 0.55, or 0.60 to a high of 0.7, 0.8, or 1.2. In one or more embodiments, the combined stream 60 has a specific gravity of from 0.5 to 1.0 or of from 0.5 to 0.8.

In one or more embodiments, the combined stream 60 has a temperature of greater than −20° C. (−4° F.). In one or more embodiments, the combined stream 60 has a temperature of greater than 0° C. (32° F.). In one or more embodiments, the combined stream 60 has a temperature of greater than 10° C. (50° F.). In one or more embodiments, the combined stream 60 has a temperature greater than 15.6° C. (60° F.), 21.1° C. (70° F.), or 26.7° C. (80° F.). In one or more embodiments, the combined stream 60 has a temperature ranging from 21.1° C. (70° F.) to 54.4° C. (130° F.), or alternatively from 26.7° C. (80° F.) to 48.9° C. (120° F.).

The combined stream 60 can have a pressure less than about 300 bar, such as about 200 bar or less, or 150 bar or less, or 100 bar or less, depending on the upstream process requirements. Therefore, a compressor 150 is used to boost the pressure of the combined stream 60 for injection into a higher pressure reservoir 175. In certain locations, the reservoir 175 may have a pressure at or above 250 bars, such as 300 bars or more, 400 bars or more, or 500 bars or more, or 700 bars or more.

The molecular weight of the combined stream 60 may depend on the concentration of the carbon dioxide and hydrogen sulfide in the stream. In one or more embodiments, the combined stream 60 includes up to 50% by volume of carbon dioxide. In one or more embodiments, the combined stream 60 includes up to 50% by volume of hydrogen sulfide. In one or more embodiments, the combined stream 60 includes of from about 5% by volume of carbon dioxide to about 40% by volume of carbon dioxide. In one or more embodiments, the combined stream 60 includes of from about 5% by volume of hydrogen sulfide to about 40% by volume of hydrogen sulfide.

In some embodiments the combined stream includes greater than 10% by volume of methane and/or ethane. In alternative embodiments, the combined stream contains greater than 20%, 30%, 40% or 50% by volume of methane and/or ethane. In some embodiments the combined stream includes greater than 10% by volume of methane. In some embodiments, the combined stream contains greater than 20%, 30%, 40% or 50% by volume of methane.

Any compressor 150 capable of operating in acid gas service, such as a reciprocating or centrifugal compressor for example, can be used. Preferably, the compressor 150 is capable of operating in acid gas service at high discharge pressure. As mentioned above, the compressor 150 discharge pressure is greater than 250 bars, such as 300 bars or more, 400 bars or more, or 500 bars or more, or 700 bars or more. In one or more embodiments, the compressor 150 discharge pressure ranges from a low of 250, 300, or 350 bars to a high of 500, 600, or 700 bars. In one or more embodiments, the compressor 150 discharge pressure is of from 300 bars to 700 bars. In one or more embodiments, the compressor 150 discharge pressure is of from 300 bars to 500 bars. In one or more embodiments, the compressor 150 discharge pressure is of from 500 bars to 700 bars.

In one or more embodiments, the compressor 150 must be capable of pressurizing a supercritical fluid. As mentioned above, the combined stream 60 can have a high molecular weight. Such a high molecular weight gas is a “gas” at the compressor 150 suction conditions but can enter the supercritical phase at the discharge pressures specified above. The term “supercritical phase” refers to a dense fluid that is maintained above its critical temperature. The critical temperature is the temperature above which the fluid cannot be liquefied by increasing pressure. A supercritical fluid is typically compressible, similar to a gas, but is more dense than a gas, i.e. more similar to a liquid. Suitable compressors for supercritical fluid service have specially engineered seals, rotor dynamic characteristics, metallic components, and elastomeric components. For example, the seals must be fully redundant to ensure leak-free operation under all conditions. The rotor dynamics have to be able to handle a high molecular weight gas approaching the dense phase. The metallic components have to be shown to withstand corrosive levels of hydrogen sulfide without cracking, and the elastomeric components have to withstand high pressure hydrogen sulfide and carbon dioxide without failure during depressurization.

FIG. 3 schematically depicts an alternative embodiment of the process 100 described with reference to FIG. 1. In this process 300, the hydrocarbon stream 10 is separated within at low temperature separation unit 310 to remove any condensable liquids from the hydrocarbon stream 10 prior to splitting the hydrocarbon stream 10 into the first stream 20 and the second stream 30. For example, the hydrocarbon stream 10 may be chilled within a cooler or adiabatically expanded using an expansion device. Preferably, the hydrocarbon stream 10 is cooled or expanded at conditions sufficient to provide a condensate stream 12 containing ethane, propane, butane, and less than 20% by volume of the acid gas from the hydrocarbon stream 10. A suitable cooler includes a heat exchanger using a cross-exchange with other process streams or an external refrigeration stream. Suitable expansion devices include, but are not limited to, a Joule-Thompson (“J-T”) valve or turbo expander. The chilled hydrocarbon stream 10 is then separated to provide a gas stream 11 and condensate stream 12. The condensate stream 12 may then be sweetened, fractionated and sold.

In one or more embodiments, the hydrocarbon stream 10 can be dehydrated to remove water prior to the low temperature separation unit 310, as shown in FIG. 3. Any technique for removing water from a gaseous stream can be used. For example, the hydrocarbon stream 10 can be dehydrated by passing the stream 10 through a packed bed 320 of molecular sieves. Although not shown, the gas stream 11 can be dehydrated in lieu of or in addition to dehydrating the hydrocarbon stream 10 as described above. Further, one or both of the individual split streams 20, 30 can be dehydrated in lieu of or in addition to dehydrating the hydrocarbon stream 10 as described above.

Specific Embodiments of Claims

Various specific embodiments are described below, at least some of which are also recited in the claims. For example, at least one specific embodiment is directed to a method for hydrocarbon processing by splitting a hydrocarbon stream comprising methane and acid gas into a first stream and a second stream. The first stream is processed to remove a portion of the acid gas therefrom, thereby producing a third stream consisting essentially of the acid gas removed from the first stream and a fourth stream comprising less than 100 ppm of sulfur-containing compounds. The second stream is then combined with the third stream to provide a combined stream, which is then compressed and passed to a subterranean reservoir. The combined stream is compressed to a pressure of about 200 bar or more prior to passing the combined stream to the subterranean reservoir.

In one or more embodiments described above or elsewhere herein, the hydrocarbon stream can be at least partially evaporated at conditions sufficient to produce a first stream having one or more sulfur-containing compounds and at least 2% by volume of the carbon dioxide based on total volume of the second stream and a second stream having one or more hydrocarbons that includes four or more carbon atoms.

At least one other specific embodiment is directed to a method for producing natural gas. In one or more embodiments, this method provides a first hydrocarbon stream comprising methane and acid gas and a second hydrocarbon stream comprising methane and acid gas. The first stream is processed to remove a portion of the acid gas therefrom, thereby producing the third stream comprising the acid gas removed from the second stream and a fourth stream comprising less than 100 ppm of sulfur-containing compounds. The second stream is combined with the third stream to provide the combined stream that is compressed and passed to a subterranean reservoir as described. The fourth stream is condensed or liquefied to form a liquefied natural gas stream. The liquefied natural gas stream can be stored, transported or sold on site.

Certain composition features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges from any lower limit to any upper limit are contemplated unless otherwise indicated. Certain lower limits, upper limits and ranges appear in one or more claims below. All numerical values are “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art. Furthermore, all patents, test procedures, and other documents cited in this application are fully incorporated by reference to the extent such disclosure is not inconsistent with this application and for all jurisdictions in which such incorporation is permitted.

While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.

Claims

1. A method for producing natural gas, comprising:

providing a first hydrocarbon stream comprising methane and acid gas and a second hydrocarbon stream comprising methane and acid gas;

processing the first stream to remove a portion of the acid gas therefrom, thereby producing a third stream comprising the acid gas removed from the second stream and a fourth stream comprising less than 100 ppm of sulfur-containing compounds;

combining the second stream with the third stream to provide a combined stream;

compressing the combined stream; and

passing the combined stream to a subterranean reservoir.

2. The method of claim 1, further comprising liquefying the fourth stream to form a liquefied natural gas stream.

3. The method of claim 2, further comprising transporting the liquefied natural gas stream from a first location to a second location.

4. The method of claim 3, further comprising regasifying the liquefied natural gas stream to a gaseous state.

5. The method of claim 1, wherein in the compressing step the combined stream enters a compressor as a gas and discharges from the compressor as a supercritical fluid.

6. A method for hydrocarbon processing, comprising:

providing a first stream comprising methane and acid gas and a second stream comprising methane and acid gas;

processing the first stream to remove a portion of the acid gas therefrom, thereby producing a third stream comprising the acid gas removed from the first stream and a fourth stream comprising less than 100 ppm of sulfur-containing compounds;

combining the second stream with the third stream to provide a combined stream;

compressing the combined stream; and

passing the combined stream to a subterranean reservoir.

7. The method of claim 6, wherein the first and second streams are provided by splitting a feed stream into the first and second streams.

8. The method of claim 6, wherein the first and second streams are provided from two different sources.

9. The method of claim 6, further comprising mixing the combined stream using a static mixer prior to passing the combined stream to the subterranean reservoir.

10. The method of claim 6, further comprising mixing the combined stream using an eductor prior to passing the combined stream to the subterranean reservoir.

11. The method of claim 6, wherein the combined stream is compressed to a pressure of about 250 bar or more.

12. The method of claim 6, wherein the combined stream is compressed to a pressure of about 500 bar or more.

13. The method of claim 6, wherein in the compressing step the combined stream is a supercritical fluid at compression discharge conditions.

14. The method of claim 6, wherein in the compressing step the combined stream enters a compressor as a gas and discharges from the compressor as a supercritical fluid.

15. The method of claim 6, further comprising compressing the third stream prior to combining the third stream with the second stream.

16. The method of claim 6, further comprising removing water from the hydrocarbon stream prior to splitting the hydrocarbon stream into the first stream and the second stream.

17. The method of claim 6, further comprising removing water from the second stream prior to combining with the third stream.

18. The method of claim 6, further comprising removing water from the third stream prior to combining with the second stream.

19. The method of claim 6, wherein processing the first stream comprises contacting the first stream with one or more amine solvents.

20. The method of claim 6, wherein processing the first stream comprises contacting the first stream with MDEA.

21. The method of claim 6, wherein processing the first stream comprises treating the first stream using cryogenic distillation.

22. The method of claim 6, wherein at least 10% by volume of the hydrocarbon stream is split into the first stream.

23. The method of claim 6, wherein at least 50% by volume of the hydrocarbon stream is split into the first stream.

24. The method of claim 6, wherein at least 20% by volume of the hydrocarbon stream is split into the second stream.

25. The method of claim 6, wherein the fourth stream is an enriched gas stream for fuel consumption.

26. The method of claim 7, wherein the split of the feed stream is determined by the volume of the fourth stream that is needed for sale, use, or both.

27. The method of claim 7, wherein the split of the feed stream is determined by the volume of the second stream that is needed to achieve the discharge pressure of 300 bars or more in the compressing step.

28. The method of claim 6, wherein the third stream comprises methane, nitrogen and helium.

29. The method of claim 6, wherein the fourth stream comprises carbon dioxide, one or more sulfur-containing compounds, ethane, and hydrocarbons having three or more carbon atoms.

30. A method for hydrocarbon reinjection, comprising:

at least partially separating a hydrocarbon stream comprising methane, ethane, propane, carbon dioxide, water, one or more sulfur-containing compounds, and of from 0.5% to 10% by volume of one or more hydrocarbons having four or more carbon atoms at conditions sufficient to produce a first stream comprising one or more sulfur-containing compounds and at least 2% by volume of the carbon dioxide based on the total volume of the second stream and a second stream comprising one or more hydrocarbons having four or more carbon atoms;

treating the first stream in a distillation column having a controlled freeze zone to produce a third stream comprising methane, ethane, and propane, and a fourth stream comprising carbon dioxide and one or more sulfur-containing compounds;

passing the second stream around the distillation column and mixing the bypassed second stream with the fourth stream to produce a combined stream; and

passing the combined stream into a subterranean reservoir.

31. The method of claim 30, wherein the at least partially separating includes evaporating.

32. The method of claim 31, wherein the conditions occur at a pressure at or above 30 bars.

33. The method of claim 31, wherein the conditions occur at a temperature at or below −40° C.

34. The method of claim 31, wherein treating the second stream comprises distilling the second stream in the presence of a refrigerant to produce the third stream comprising methane, ethane, and propane, and the fourth stream comprising carbon dioxide and one or more sulfur-containing compounds.

35. The method of claim 31, wherein the hydrocarbon stream comprises of from about 2% by volume to about 65% by volume of carbon dioxide.

36. The method of claim 31, further comprising compressing the combined stream to a pressure of 700 bar or more prior to passing the combined stream into the reservoir.

37. The method of claim 31, further comprising removing water from the hydrocarbon stream prior to at least partially separating the hydrocarbon stream.

38. The method of claim 31, further comprising removing water from the hydrocarbon stream prior to at least partially separating the hydrocarbon stream, wherein the water is removed by contacting the hydrocarbon stream with a molecular sieve.

39. The method of claim 31, further comprising removing water from the second stream prior to treating the second stream in the distillation column having the controlled freeze zone.

40. The method of claim 31, further comprising removing water from the second stream prior to treating the second stream in the distillation column having the controlled freeze zone, wherein the water is removed by contacting the second stream with a molecular sieve.