US20080034789A1 - Integrated Acid Gas And Sour Gas Reinjection Process - Google Patents
Integrated Acid Gas And Sour Gas Reinjection Process Download PDFInfo
- Publication number
- US20080034789A1 US20080034789A1 US11/664,038 US66403805A US2008034789A1 US 20080034789 A1 US20080034789 A1 US 20080034789A1 US 66403805 A US66403805 A US 66403805A US 2008034789 A1 US2008034789 A1 US 2008034789A1
- Authority
- US
- United States
- Prior art keywords
- stream
- combined
- hydrocarbon
- volume
- gas
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Abandoned
Links
Images
Classifications
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
- F25J3/02—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
- F25J3/0204—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the feed stream
- F25J3/0209—Natural gas or substitute natural gas
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
- C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
- C10L3/10—Working-up natural gas or synthetic natural gas
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
- F25J3/02—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
- F25J3/0228—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream
- F25J3/0233—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream separation of CnHm with 1 carbon atom or more
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
- F25J3/02—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
- F25J3/0228—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream
- F25J3/0238—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream separation of CnHm with 2 carbon atoms or more
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
- F25J3/02—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
- F25J3/0228—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream
- F25J3/0266—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream separation of carbon dioxide
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2200/00—Processes or apparatus using separation by rectification
- F25J2200/02—Processes or apparatus using separation by rectification in a single pressure main column system
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2200/00—Processes or apparatus using separation by rectification
- F25J2200/76—Refluxing the column with condensed overhead gas being cycled in a quasi-closed loop refrigeration cycle
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2205/00—Processes or apparatus using other separation and/or other processing means
- F25J2205/20—Processes or apparatus using other separation and/or other processing means using solidification of components
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2210/00—Processes characterised by the type or other details of the feed stream
- F25J2210/06—Splitting of the feed stream, e.g. for treating or cooling in different ways
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2220/00—Processes or apparatus involving steps for the removal of impurities
- F25J2220/60—Separating impurities from natural gas, e.g. mercury, cyclic hydrocarbons
- F25J2220/66—Separating acid gases, e.g. CO2, SO2, H2S or RSH
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2240/00—Processes or apparatus involving steps for expanding of process streams
- F25J2240/02—Expansion of a process fluid in a work-extracting turbine (i.e. isentropic expansion), e.g. of the feed stream
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2240/00—Processes or apparatus involving steps for expanding of process streams
- F25J2240/30—Dynamic liquid or hydraulic expansion with extraction of work, e.g. single phase or two-phase turbine
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2260/00—Coupling of processes or apparatus to other units; Integrated schemes
- F25J2260/80—Integration in an installation using carbon dioxide, e.g. for EOR, sequestration, refrigeration etc.
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2270/00—Refrigeration techniques used
- F25J2270/04—Internal refrigeration with work-producing gas expansion loop
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2280/00—Control of the process or apparatus
- F25J2280/40—Control of freezing of components
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
- Y02C20/00—Capture or disposal of greenhouse gases
- Y02C20/40—Capture or disposal of greenhouse gases of CO2
Definitions
- 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.
- 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.
- a method for hydrocarbon processing includes providing a first hydrocarbon stream comprising methane and acid gas and a second hydrocarbon stream comprising methane and acid gas.
- the first and second hydrocarbon streams are provided by splitting a feed stream into the first and second hydrocarbon streams.
- 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.
- 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.
- 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.
- a method for producing natural gas 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.
- 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.
- CFZ controlled freeze zone
- 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 .
- 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.
- acid gas means any one or more of carbon dioxide (CO 2 ), hydrogen sulfide (H 2 S), carbon disulfide (CS 2 ), carbonyl sulfide (COS), mercaptans (R—SH, where R is an alkyl group having one to 20 carbon atoms), sulfur dioxide (SO 2 ), combinations thereof, mixtures thereof, and derivatives thereof.
- our 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.
- FIG. 1 schematically depicts an exemplary process for processing a hydrocarbon stream according to the embodiments described.
- 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 .
- 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.
- EOR enhanced oil recovery
- 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.
- 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.
- the feed stream 11 includes of from about 50% by volume to about 90% by volume of methane.
- an illustrative feed stream 11 may include carbon dioxide, one or more sulfur-containing compounds and other impurities.
- 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.
- 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.
- aromatics include, but are not limited to, benzene, toluene, ethylbenzene and xylene.
- 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 .
- 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 .
- 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.
- the feed stream 11 can be dehydrated by passing the feed stream 11 through a packed bed of molecular sieves.
- 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.
- 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.
- the acid gas and other impurities can be removed using a solvent extraction process.
- solvent extraction process encompasses any process known in the art for extracting acid gases using a solvent.
- 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.
- 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.
- NMP N-methyl-2-pyrrolidone
- 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 FlexsorbTM and Flexsorb SETM 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.
- 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.
- J-T Joule-Thompson
- 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.
- 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.
- the operating temperature and pressure of the column depend on the concentration of the carbon dioxide in the first stream 20 .
- concentration of the carbon dioxide in the first stream 20 is from about 2% by volume to about 10% by volume.
- 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.
- 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 .
- 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.
- 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 .
- 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 .
- the disposal stream 50 is combined with the bypassed second stream 30 to form the combined stream 60 .
- 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.
- a disposal stream 50 may be pumped to a higher pressure and flashed into the bypassed second stream 30 .
- a lower pressure disposal stream 50 may be vaporized and then compressed to a higher pressure.
- 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).
- the streams 30 , 50 may be mixed within piping having a sufficient length and geometry to sufficiently mix the streams.
- the combined stream 60 is a high molecular weight gas.
- the combined stream 60 can have a specific gravity of greater than 0.5.
- the combined stream 60 has a specific gravity of greater than 0.6, greater than 0.7, or greater than 0.8.
- the combined stream 60 has a specific gravity of greater than 1.0.
- 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.
- the combined stream 60 has a specific gravity of from 0.5 to 1.0 or of from 0.5 to 0.8.
- 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 .
- 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.
- 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.
- the compressor 150 is capable of operating in acid gas service at high discharge pressure.
- 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.
- the compressor 150 discharge pressure ranges from a low of 250, 300, or 350 bars to a high of 500, 600, or 700 bars.
- the compressor 150 discharge pressure is of from 300 bars to 700 bars.
- the compressor 150 discharge pressure is of from 300 bars to 500 bars.
- the compressor 150 discharge pressure is of from 500 bars to 700 bars.
- the compressor 150 must be capable of pressurizing a supercritical fluid.
- the combined stream 60 can have a high molecular weight.
- 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.
- 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 .
- 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 .
- the hydrocarbon stream 10 may be chilled within a cooler or adiabatically expanded using an expansion device.
- 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.
- J-T Joule-Thompson
- 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.
- 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.
- the hydrocarbon stream 10 can be dehydrated by passing the stream 10 through a packed bed 320 of molecular sieves.
- the gas stream 11 can be dehydrated in lieu of or in addition to dehydrating the hydrocarbon stream 10 as described above.
- 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.
- 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.
- 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.
- 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.
- 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.
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
- This application claims the benefit of U.S.
Provisional Application 60/633,361, filed 3 Dec. 2004. - 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.).
- 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.
- 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 aprocess 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 anillustrative distillation process 200 that utilizes acolumn 225 having a controlled freeze zone (CFZ) according to one embodiment described herein. -
FIG. 3 schematically depicts analternative 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. Thisprocess 300 is similar to theprocess 100 ofFIG. 1 , but also provides a lowtemperature separation unit 310 prior to the sourgas processing unit 125. - 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 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, awell 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 aseparator 110, such as a pressure vessel for example. Thewell 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 ahydrocarbon 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, thefirst stream 20 and thesecond stream 30 have identical compositions. Thefirst stream 20 is directed to agas processing unit 125 to remove acid gas, producing aproduct stream 40 for fuel, or sales, or both, and adisposal stream 50. Thesecond stream 30 bypasses thegas processing unit 125 and is combined with thedisposal stream 50 to provide a combinedstream 60. The combinedstream 60 is compressed by thecompressor 150 and then reinjected or otherwise passed into asubterranean 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. Anillustrative 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, thefeed stream 11 can be a combined stream from two or more different wells. Anillustrative feed stream 11 includes of from about 20% by volume to about 95% by volume of methane. Preferably, thefeed 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, anillustrative feed stream 11 may include carbon dioxide, one or more sulfur-containing compounds and other impurities. For example, thefeed 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 thefeed 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 sourgas processing unit 125 as thefirst stream 20 and the balance of thefeed stream 11 is split into thesecond stream 30 and bypassed around the sourgas processing unit 125. For example, at least 10% by volume of thefeed stream 11 is split into thefirst stream 20 and processed in the sourgas 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 thefeed stream 11 is split into thefirst stream 20 and processed in the sourgas processing unit 125. In one or more embodiments, of from about 10% by volume to about 50% by volume of the separatedfeed stream 11 is split into thefirst stream 20. In one or more embodiments, at least 15%, 20%, 30%, 40%, or 50% of thefeed stream 11 is split into thesecond stream 30. In one or more embodiments, of from about 15% to about 50% of thefeed stream 11 is split into thesecond stream 30. In one or more embodiments, of from about 15% to about 30% of thefeed stream 11 is split into thesecond stream 30. - Although not shown in
FIG. 1 , thefeed stream 11 can be dehydrated to remove water prior to thegas processing unit 125. Any technique for removing water from a gaseous stream can be used. For example, thefeed stream 11 can be dehydrated by passing thefeed 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 thefeed stream 11 as described above. -
Gas Processing Unit 125 - The
gas processing unit 125 removes acid gas and other impurities from thefirst stream 20. The acid gas and other impurities may be removed from thefirst 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, thefirst 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 thefirst stream 20, producing theproduct 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. Thefirst stream 20 is fed to a distillation column operated at a low temperature and refluxed with a refrigerated overhead stream. Thefirst 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 theproduct stream 40 and a portion of the bottoms from the column is recovered as thedisposal 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 thefirst 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 anillustrative distillation process 200 that utilizes acolumn 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. Thecolumn 225 is separated into three distinct sections including alower distillation section 230, middle controlled freezingzone 235, and anupper distillation section 240. Thesecond stream 20 is introduced into thelower distillation section 230. Thesecond stream 20 can be chilled and/or expanded prior to entering thecolumn 225. Alternatively, a Joule-Thomson valve may be used in place of the expander. The internals of thelower section 230 can include trays, downcorners, weirs, packing, or any combination thereof. - A
liquid stream 210 that contains carbon dioxide exits the bottom of thelower section 230 and a portion of theliquid stream 210 is heated in areboiler 215. Theliquid stream 210 contains the acid gas and some of the ethane and heavier hydrocarbons from thefirst stream 20. A portion of theliquid stream 210 returns to thecolumn 225 as reboiled vapor. The remainder of theliquid stream 210 leaves theprocess 200 as the bottoms product which is thestream 50. Thereboiler 215 typically operates in a temperature range of from about −10° C. to about 10° C. Thereboiler 215 can be controlled to leave less than about 5% by volume methane in thestream 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 achimney tray 216, and contact a liquid spray from nozzles orspray jet assemblies 220. The vapor then continues up through theupper distillation section 240 and contacts reflux introduced to thecolumn 225 throughline 218. The vapor exits thecolumn 225 through anoverhead line 214. A portion of the vapor is returned to the top of thecolumn 225 as liquid reflux via arefrigeration loop 250. The remainder of the vapor is removed from theprocess 200 as fuel gas, sales gas or both instream 40. - The
overhead refrigeration loop 250 includes across exchanger 255 for extracting cold energy from the vapor leaving the column vialine 214. The warmedvapor stream 257 from theexchanger 255 is compressed incompressor 270 and cooled in cooler 280. A portion of the cooledvapor stream 282 is passed through theexchanger 255 and is at least partially condensed to formstream 254. The at least partiallycondensed stream 254 is then expanded inexpander 255, and returned to theupper distillation section 240 of thecolumn 225 vialine 218. - The liquid in the
upper distillation section 240 is collected and withdrawn from thecolumn 225 vialine 262. The liquid inline 262 may be accumulated invessel 265 and returned to the controlled freezingzone 235 viaspray nozzles 220. The vapor rising through thechimney tray 216 meets the spray emanating from thenozzles 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 freezingzone 235 and collects on thechimney tray 216. A level of liquid (possibly containing some melting solids) is maintained in the bottom of the controlled freezingzone 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 freezingzone 235 throughexterior line 272 into the upper end of thebottom distillation section 230. - Referring again to
FIG. 1 , thedisposal stream 50 is combined with the bypassedsecond stream 30 to form the combinedstream 60. In the event thedisposal stream 50 has a lower pressure than thesecond stream 30, thedisposal stream 50 may be pumped to a higher pressure and then vaporized using cross-exchange with another process stream or other heating media. Further, adisposal stream 50 may be pumped to a higher pressure and flashed into the bypassedsecond stream 30. Still further, a lowerpressure disposal stream 50 may be vaporized and then compressed to a higher pressure. - In one or more embodiments, the
disposal stream 50 and the bypassedsecond stream 30 are mixed. The twostreams streams - In one or more embodiments, the combined
stream 60 is a high molecular weight gas. For example, the combinedstream 60 can have a specific gravity of greater than 0.5. In one or more embodiments, the combinedstream 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 combinedstream 60 has a specific gravity of greater than 1.0. In one or more embodiments, the combinedstream 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 combinedstream 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 combinedstream 60 has a temperature of greater than 0° C. (32° F.). In one or more embodiments, the combinedstream 60 has a temperature of greater than 10° C. (50° F.). In one or more embodiments, the combinedstream 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 combinedstream 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, acompressor 150 is used to boost the pressure of the combinedstream 60 for injection into ahigher pressure reservoir 175. In certain locations, thereservoir 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 combinedstream 60 includes up to 50% by volume of carbon dioxide. In one or more embodiments, the combinedstream 60 includes up to 50% by volume of hydrogen sulfide. In one or more embodiments, the combinedstream 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 combinedstream 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, thecompressor 150 is capable of operating in acid gas service at high discharge pressure. As mentioned above, thecompressor 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, thecompressor 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, thecompressor 150 discharge pressure is of from 300 bars to 700 bars. In one or more embodiments, thecompressor 150 discharge pressure is of from 300 bars to 500 bars. In one or more embodiments, thecompressor 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 combinedstream 60 can have a high molecular weight. Such a high molecular weight gas is a “gas” at thecompressor 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 theprocess 100 described with reference toFIG. 1 . In thisprocess 300, thehydrocarbon stream 10 is separated within at lowtemperature separation unit 310 to remove any condensable liquids from thehydrocarbon stream 10 prior to splitting thehydrocarbon stream 10 into thefirst stream 20 and thesecond stream 30. For example, thehydrocarbon stream 10 may be chilled within a cooler or adiabatically expanded using an expansion device. Preferably, thehydrocarbon stream 10 is cooled or expanded at conditions sufficient to provide acondensate stream 12 containing ethane, propane, butane, and less than 20% by volume of the acid gas from thehydrocarbon 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. Thechilled hydrocarbon stream 10 is then separated to provide agas stream 11 andcondensate stream 12. Thecondensate 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 lowtemperature separation unit 310, as shown inFIG. 3 . Any technique for removing water from a gaseous stream can be used. For example, thehydrocarbon stream 10 can be dehydrated by passing thestream 10 through a packedbed 320 of molecular sieves. Although not shown, thegas stream 11 can be dehydrated in lieu of or in addition to dehydrating thehydrocarbon 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 thehydrocarbon stream 10 as described above. - 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 (40)
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.
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US11/664,038 US20080034789A1 (en) | 2004-12-03 | 2005-10-19 | Integrated Acid Gas And Sour Gas Reinjection Process |
Applications Claiming Priority (3)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US63336104P | 2004-12-03 | 2004-12-03 | |
PCT/US2005/038236 WO2006062595A1 (en) | 2004-12-03 | 2005-10-19 | Integrated acid gas and sour gas reinjection process |
US11/664,038 US20080034789A1 (en) | 2004-12-03 | 2005-10-19 | Integrated Acid Gas And Sour Gas Reinjection Process |
Publications (1)
Publication Number | Publication Date |
---|---|
US20080034789A1 true US20080034789A1 (en) | 2008-02-14 |
Family
ID=34956547
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US11/664,038 Abandoned US20080034789A1 (en) | 2004-12-03 | 2005-10-19 | Integrated Acid Gas And Sour Gas Reinjection Process |
Country Status (5)
Country | Link |
---|---|
US (1) | US20080034789A1 (en) |
EP (1) | EP1819976A4 (en) |
CA (1) | CA2583120C (en) |
EA (1) | EA014650B1 (en) |
WO (1) | WO2006062595A1 (en) |
Cited By (38)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20090036727A1 (en) * | 2007-08-01 | 2009-02-05 | Stone & Webster Process Technology, Inc. | Removal of acid gases and sulfur compounds from hydrocarbon gas streams in a caustic tower |
US20090266107A1 (en) * | 2007-01-19 | 2009-10-29 | Vikram Singh | Integrated Controlled Freeze Zone (CFZ) Tower and Dividing Wall (DWC) for Enhanced Hydrocarbon Recovery |
US20100018248A1 (en) * | 2007-01-19 | 2010-01-28 | Eleanor R Fieler | Controlled Freeze Zone Tower |
WO2011053400A1 (en) * | 2009-11-02 | 2011-05-05 | Exxonmobil Upstream Research Company | Cryogenic system for removing acid gases from a hydrocarbon gas stream, with removal of hydrogen sulfide |
US20110167869A1 (en) * | 2008-08-29 | 2011-07-14 | Geers Henricus Abraham | Process and apparatus for removing gaseous contaminants from gas stream comprising gaseous contaminants |
WO2011090553A1 (en) * | 2010-01-22 | 2011-07-28 | Exxonmobil Upstream Research Company | Removal of acid gases from a gas stream, with co2 capture and sequestration |
US20120079852A1 (en) * | 2009-07-30 | 2012-04-05 | Paul Scott Northrop | Systems and Methods for Removing Heavy Hydrocarbons and Acid Gases From a Hydrocarbon Gas Stream |
US9423174B2 (en) | 2009-04-20 | 2016-08-23 | Exxonmobil Upstream Research Company | Cryogenic system for removing acid gases from a hydrocarbon gas stream, and method of removing acid gases |
US9504984B2 (en) | 2014-04-09 | 2016-11-29 | Exxonmobil Upstream Research Company | Generating elemental sulfur |
US9562719B2 (en) | 2013-12-06 | 2017-02-07 | Exxonmobil Upstream Research Company | Method of removing solids by modifying a liquid level in a distillation tower |
WO2017096149A1 (en) * | 2015-12-03 | 2017-06-08 | Air Liquide Advanced Technologies, U.S. LLC | Method and system for purification of natural gas using membranes |
US9739528B2 (en) | 2014-04-22 | 2017-08-22 | Exxonmobil Upstream Research Company | Method and system for starting up a distillation tower |
US9739529B2 (en) | 2014-07-08 | 2017-08-22 | Exxonmobil Upstream Research Company | Method and system for separating fluids in a distillation tower |
US9752827B2 (en) | 2013-12-06 | 2017-09-05 | Exxonmobil Upstream Research Company | Method and system of maintaining a liquid level in a distillation tower |
US9784498B2 (en) | 2014-06-11 | 2017-10-10 | Exxonmobil Upstream Research Company | Method for separating a feed gas in a column |
US9803918B2 (en) | 2013-12-06 | 2017-10-31 | Exxonmobil Upstream Research Company | Method and system of dehydrating a feed stream processed in a distillation tower |
US9823017B2 (en) | 2014-10-22 | 2017-11-21 | Exxonmobil Upstream Research Company | Method and system of controlling a temperature within a melt tray assembly of a distillation tower |
US9823016B2 (en) | 2013-12-06 | 2017-11-21 | Exxonmobil Upstream Research Company | Method and system of modifying a liquid level during start-up operations |
US9829247B2 (en) | 2013-12-06 | 2017-11-28 | Exxonmobil Upstream Reseach Company | Method and device for separating a feed stream using radiation detectors |
US9829246B2 (en) | 2010-07-30 | 2017-11-28 | Exxonmobil Upstream Research Company | Cryogenic systems for removing acid gases from a hydrocarbon gas stream using co-current separation devices |
US9869511B2 (en) | 2013-12-06 | 2018-01-16 | Exxonmobil Upstream Research Company | Method and device for separating hydrocarbons and contaminants with a spray assembly |
US9874395B2 (en) | 2013-12-06 | 2018-01-23 | Exxonmobil Upstream Research Company | Method and system for preventing accumulation of solids in a distillation tower |
US9874396B2 (en) | 2013-12-06 | 2018-01-23 | Exxonmobil Upstream Research Company | Method and device for separating hydrocarbons and contaminants with a heating mechanism to destabilize and/or prevent adhesion of solids |
US9964352B2 (en) | 2012-03-21 | 2018-05-08 | Exxonmobil Upstream Research Company | Separating carbon dioxide and ethane from a mixed stream |
US10006700B2 (en) | 2014-12-30 | 2018-06-26 | Exxonmobil Upstream Research Company | Accumulation and melt tray assembly for a distillation tower |
US10139158B2 (en) | 2013-12-06 | 2018-11-27 | Exxonmobil Upstream Research Company | Method and system for separating a feed stream with a feed stream distribution mechanism |
US10222121B2 (en) | 2009-09-09 | 2019-03-05 | Exxonmobil Upstream Research Company | Cryogenic system for removing acid gases from a hydrocarbon gas stream |
US10274252B2 (en) | 2015-06-22 | 2019-04-30 | Exxonmobil Upstream Research Company | Purge to intermediate pressure in cryogenic distillation |
US10281205B2 (en) | 2014-11-17 | 2019-05-07 | Exxonmobil Upstream Research Company | Heat exchange mechanism for removing contaminants from a hydrocarbon vapor stream |
US10323495B2 (en) * | 2016-03-30 | 2019-06-18 | Exxonmobil Upstream Research Company | Self-sourced reservoir fluid for enhanced oil recovery |
US10365037B2 (en) * | 2015-09-18 | 2019-07-30 | Exxonmobil Upstream Research Company | Heating component to reduce solidification in a cryogenic distillation system |
US10408534B2 (en) | 2010-02-03 | 2019-09-10 | Exxonmobil Upstream Research Company | Systems and methods for using cold liquid to remove solidifiable gas components from process gas streams |
US10495379B2 (en) | 2015-02-27 | 2019-12-03 | Exxonmobil Upstream Research Company | Reducing refrigeration and dehydration load for a feed stream entering a cryogenic distillation process |
US20190381450A1 (en) * | 2018-06-19 | 2019-12-19 | L'air Liquide, Societe Anonyme Pour L'etude Et L'exploitation Des Procedes Georges Claude | Systems, processes and methods for concentrating acid gas and producing hydrocarbon liquid with a membrane separation system |
US10589215B2 (en) | 2017-09-21 | 2020-03-17 | Air Liquide Advanced Technologies U.S. Llc | Production of biomethane using multiple types of membrane |
US11255603B2 (en) | 2015-09-24 | 2022-02-22 | Exxonmobil Upstream Research Company | Treatment plant for hydrocarbon gas having variable contaminant levels |
US11306267B2 (en) | 2018-06-29 | 2022-04-19 | Exxonmobil Upstream Research Company | Hybrid tray for introducing a low CO2 feed stream into a distillation tower |
US11378332B2 (en) | 2018-06-29 | 2022-07-05 | Exxonmobil Upstream Research Company | Mixing and heat integration of melt tray liquids in a cryogenic distillation tower |
Families Citing this family (3)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
RU2467788C1 (en) * | 2011-06-02 | 2012-11-27 | Сергей Анатольевич Щелкунов | Method of cleaning waste gases from sulfur dioxide |
US20130025317A1 (en) | 2011-06-15 | 2013-01-31 | L'Air Liguide Societe Anonyme Pour L' Etude Et L' Exploitation Des Procedes Georges Claude | Process for Removing Carbon Dioxide From a Gas Stream using Desublimation |
RU2750013C1 (en) * | 2020-11-17 | 2021-06-21 | Общество с ограниченной ответственностью "АЭРОГАЗ" (ООО "АЭРОГАЗ") | Method for injecting gas into reservoir (options) |
Citations (20)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US2960837A (en) * | 1958-07-16 | 1960-11-22 | Conch Int Methane Ltd | Liquefying natural gas with low pressure refrigerants |
US3848427A (en) * | 1971-03-01 | 1974-11-19 | R Loofbourow | Storage of gas in underground excavation |
US4533372A (en) * | 1983-12-23 | 1985-08-06 | Exxon Production Research Co. | Method and apparatus for separating carbon dioxide and other acid gases from methane by the use of distillation and a controlled freezing zone |
US4551158A (en) * | 1983-03-08 | 1985-11-05 | Basf Aktiengesellschaft | Removal of CO2 and/or H2 S from gases |
US4923493A (en) * | 1988-08-19 | 1990-05-08 | Exxon Production Research Company | Method and apparatus for cryogenic separation of carbon dioxide and other acid gases from methane |
US5062270A (en) * | 1990-08-31 | 1991-11-05 | Exxon Production Research Company | Method and apparatus to start-up controlled freezing zone process and purify the product stream |
US5120338A (en) * | 1991-03-14 | 1992-06-09 | Exxon Production Research Company | Method for separating a multi-component feed stream using distillation and controlled freezing zone |
US5820837A (en) * | 1996-05-20 | 1998-10-13 | Mobil Oil Corporation | Process for treating a gas stream to selectively separate acid gases therefrom |
US5819555A (en) * | 1995-09-08 | 1998-10-13 | Engdahl; Gerald | Removal of carbon dioxide from a feed stream by carbon dioxide solids separation |
US5956971A (en) * | 1997-07-01 | 1999-09-28 | Exxon Production Research Company | Process for liquefying a natural gas stream containing at least one freezable component |
US5983663A (en) * | 1998-05-08 | 1999-11-16 | Kvaerner Process Systems, Inc. | Acid gas fractionation |
US6053007A (en) * | 1997-07-01 | 2000-04-25 | Exxonmobil Upstream Research Company | Process for separating a multi-component gas stream containing at least one freezable component |
US20020062735A1 (en) * | 2000-09-26 | 2002-05-30 | Lecomte Fabrice | Process for pretreating a natural gas containing acid gases |
US6442969B1 (en) * | 2000-05-02 | 2002-09-03 | Institut Francais Du Petrole | Process and device for separation of at least one acid gas that is contained in a gas mixture |
US20030047309A1 (en) * | 2001-09-07 | 2003-03-13 | Exxonmobil Upstream Research Company | Acid gas disposal method |
US6581618B2 (en) * | 2001-05-25 | 2003-06-24 | Canatxx Energy, L.L.C. | Shallow depth, low pressure gas storage facilities and related methods of use |
US20030124594A1 (en) * | 1997-10-10 | 2003-07-03 | President & Fellows Of Harvard College | Replica amplification of nucleic acid arrays |
US20030131726A1 (en) * | 2001-09-07 | 2003-07-17 | Exxonmobil Upstream Research Company | High-pressure separation of a multi-component gas |
US6605138B2 (en) * | 1999-04-21 | 2003-08-12 | Matthew T. Frondorf | Apparatus and method for exclusively removing VOC from regeneratable solvent in a gas sweetening system |
US20060000698A1 (en) * | 2004-06-30 | 2006-01-05 | Lg Electronics, Inc. | Dial knob of washing machine and manufacturing method thereof |
-
2005
- 2005-10-19 EA EA200701206A patent/EA014650B1/en not_active IP Right Cessation
- 2005-10-19 CA CA2583120A patent/CA2583120C/en not_active Expired - Fee Related
- 2005-10-19 EP EP05811899A patent/EP1819976A4/en not_active Withdrawn
- 2005-10-19 WO PCT/US2005/038236 patent/WO2006062595A1/en active Application Filing
- 2005-10-19 US US11/664,038 patent/US20080034789A1/en not_active Abandoned
Patent Citations (23)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US2960837A (en) * | 1958-07-16 | 1960-11-22 | Conch Int Methane Ltd | Liquefying natural gas with low pressure refrigerants |
US3848427A (en) * | 1971-03-01 | 1974-11-19 | R Loofbourow | Storage of gas in underground excavation |
US4551158A (en) * | 1983-03-08 | 1985-11-05 | Basf Aktiengesellschaft | Removal of CO2 and/or H2 S from gases |
US4533372A (en) * | 1983-12-23 | 1985-08-06 | Exxon Production Research Co. | Method and apparatus for separating carbon dioxide and other acid gases from methane by the use of distillation and a controlled freezing zone |
US4923493A (en) * | 1988-08-19 | 1990-05-08 | Exxon Production Research Company | Method and apparatus for cryogenic separation of carbon dioxide and other acid gases from methane |
US5062270A (en) * | 1990-08-31 | 1991-11-05 | Exxon Production Research Company | Method and apparatus to start-up controlled freezing zone process and purify the product stream |
US5120338A (en) * | 1991-03-14 | 1992-06-09 | Exxon Production Research Company | Method for separating a multi-component feed stream using distillation and controlled freezing zone |
US5819555A (en) * | 1995-09-08 | 1998-10-13 | Engdahl; Gerald | Removal of carbon dioxide from a feed stream by carbon dioxide solids separation |
US5820837A (en) * | 1996-05-20 | 1998-10-13 | Mobil Oil Corporation | Process for treating a gas stream to selectively separate acid gases therefrom |
US5956971A (en) * | 1997-07-01 | 1999-09-28 | Exxon Production Research Company | Process for liquefying a natural gas stream containing at least one freezable component |
US6053007A (en) * | 1997-07-01 | 2000-04-25 | Exxonmobil Upstream Research Company | Process for separating a multi-component gas stream containing at least one freezable component |
US20030124594A1 (en) * | 1997-10-10 | 2003-07-03 | President & Fellows Of Harvard College | Replica amplification of nucleic acid arrays |
US5983663A (en) * | 1998-05-08 | 1999-11-16 | Kvaerner Process Systems, Inc. | Acid gas fractionation |
US6605138B2 (en) * | 1999-04-21 | 2003-08-12 | Matthew T. Frondorf | Apparatus and method for exclusively removing VOC from regeneratable solvent in a gas sweetening system |
US6442969B1 (en) * | 2000-05-02 | 2002-09-03 | Institut Francais Du Petrole | Process and device for separation of at least one acid gas that is contained in a gas mixture |
US20020062735A1 (en) * | 2000-09-26 | 2002-05-30 | Lecomte Fabrice | Process for pretreating a natural gas containing acid gases |
US6735979B2 (en) * | 2000-09-26 | 2004-05-18 | Institut Francais Du Petrole | Process for pretreating a natural gas containing acid gases |
US6581618B2 (en) * | 2001-05-25 | 2003-06-24 | Canatxx Energy, L.L.C. | Shallow depth, low pressure gas storage facilities and related methods of use |
US20040059692A1 (en) * | 2001-05-25 | 2004-03-25 | Hill Ross K. | Underground gas storage with short term reversible flow operable for use in arbitrage/trading |
US20030047309A1 (en) * | 2001-09-07 | 2003-03-13 | Exxonmobil Upstream Research Company | Acid gas disposal method |
US20030131726A1 (en) * | 2001-09-07 | 2003-07-17 | Exxonmobil Upstream Research Company | High-pressure separation of a multi-component gas |
US7128150B2 (en) * | 2001-09-07 | 2006-10-31 | Exxonmobil Upstream Research Company | Acid gas disposal method |
US20060000698A1 (en) * | 2004-06-30 | 2006-01-05 | Lg Electronics, Inc. | Dial knob of washing machine and manufacturing method thereof |
Cited By (54)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US8312738B2 (en) * | 2007-01-19 | 2012-11-20 | Exxonmobil Upstream Research Company | Integrated controlled freeze zone (CFZ) tower and dividing wall (DWC) for enhanced hydrocarbon recovery |
US20090266107A1 (en) * | 2007-01-19 | 2009-10-29 | Vikram Singh | Integrated Controlled Freeze Zone (CFZ) Tower and Dividing Wall (DWC) for Enhanced Hydrocarbon Recovery |
US20100018248A1 (en) * | 2007-01-19 | 2010-01-28 | Eleanor R Fieler | Controlled Freeze Zone Tower |
US7772449B2 (en) * | 2007-08-01 | 2010-08-10 | Stone & Webster Process Technology, Inc. | Removal of acid gases and sulfur compounds from hydrocarbon gas streams in a caustic tower |
US20090036727A1 (en) * | 2007-08-01 | 2009-02-05 | Stone & Webster Process Technology, Inc. | Removal of acid gases and sulfur compounds from hydrocarbon gas streams in a caustic tower |
US20110167869A1 (en) * | 2008-08-29 | 2011-07-14 | Geers Henricus Abraham | Process and apparatus for removing gaseous contaminants from gas stream comprising gaseous contaminants |
US9396854B2 (en) * | 2008-08-29 | 2016-07-19 | Shell Oil Company | Process and apparatus for removing gaseous contaminants from gas stream comprising gaseous contaminants |
US9423174B2 (en) | 2009-04-20 | 2016-08-23 | Exxonmobil Upstream Research Company | Cryogenic system for removing acid gases from a hydrocarbon gas stream, and method of removing acid gases |
US20120079852A1 (en) * | 2009-07-30 | 2012-04-05 | Paul Scott Northrop | Systems and Methods for Removing Heavy Hydrocarbons and Acid Gases From a Hydrocarbon Gas Stream |
US10222121B2 (en) | 2009-09-09 | 2019-03-05 | Exxonmobil Upstream Research Company | Cryogenic system for removing acid gases from a hydrocarbon gas stream |
JP2013509300A (en) * | 2009-11-02 | 2013-03-14 | エクソンモービル アップストリーム リサーチ カンパニー | Cryogenic system for removing acid gases from hydrocarbon gas streams by removing hydrogen sulfide |
AU2010313733B2 (en) * | 2009-11-02 | 2016-05-12 | Exxonmobil Upstream Research Company | Cryogenic system for removing acid gases from a hydrocarbon gas stream, with removal of hydrogen sulfide |
US20120204599A1 (en) * | 2009-11-02 | 2012-08-16 | Paul Scott Northrop | Cryogenic system for removing acid gases from a hydrocarbon gas stream, with removal of hydrogen sulfide |
WO2011053400A1 (en) * | 2009-11-02 | 2011-05-05 | Exxonmobil Upstream Research Company | Cryogenic system for removing acid gases from a hydrocarbon gas stream, with removal of hydrogen sulfide |
CN102597671A (en) * | 2009-11-02 | 2012-07-18 | 埃克森美孚上游研究公司 | Cryogenic system for removing acid gases from a hydrocarbon gas stream, with removal of hydrogen sulfide |
EA023174B1 (en) * | 2009-11-02 | 2016-04-29 | Эксонмобил Апстрим Рисерч Компани | Cryogenic system for removing acid gases from a hydrocarbon gas stream, with removal of hydrogen sulfide |
AU2010343273B2 (en) * | 2010-01-22 | 2016-01-14 | Exxonmobil Upstream Research Company | Removal of acid gases from a gas stream, with CO2 capture and sequestration |
CN102753250A (en) * | 2010-01-22 | 2012-10-24 | 埃克森美孚上游研究公司 | Removal of acid gases from a gas stream, with co2 capture and sequestration |
WO2011090553A1 (en) * | 2010-01-22 | 2011-07-28 | Exxonmobil Upstream Research Company | Removal of acid gases from a gas stream, with co2 capture and sequestration |
EA026113B1 (en) * | 2010-01-22 | 2017-03-31 | Эксонмобил Апстрим Рисерч Компани | Removal of acid gases from a gas stream, with cocapture and sequestration |
US9149761B2 (en) | 2010-01-22 | 2015-10-06 | Exxonmobil Upstream Research Company | Removal of acid gases from a gas stream, with CO2 capture and sequestration |
US11112172B2 (en) | 2010-02-03 | 2021-09-07 | Exxonmobil Upstream Research Company | Systems and methods for using cold liquid to remove solidifiable gas components from process gas streams |
US10408534B2 (en) | 2010-02-03 | 2019-09-10 | Exxonmobil Upstream Research Company | Systems and methods for using cold liquid to remove solidifiable gas components from process gas streams |
US9829246B2 (en) | 2010-07-30 | 2017-11-28 | Exxonmobil Upstream Research Company | Cryogenic systems for removing acid gases from a hydrocarbon gas stream using co-current separation devices |
US10323879B2 (en) | 2012-03-21 | 2019-06-18 | Exxonmobil Upstream Research Company | Separating carbon dioxide and ethane from a mixed stream |
US9964352B2 (en) | 2012-03-21 | 2018-05-08 | Exxonmobil Upstream Research Company | Separating carbon dioxide and ethane from a mixed stream |
US9803918B2 (en) | 2013-12-06 | 2017-10-31 | Exxonmobil Upstream Research Company | Method and system of dehydrating a feed stream processed in a distillation tower |
US9823016B2 (en) | 2013-12-06 | 2017-11-21 | Exxonmobil Upstream Research Company | Method and system of modifying a liquid level during start-up operations |
US9829247B2 (en) | 2013-12-06 | 2017-11-28 | Exxonmobil Upstream Reseach Company | Method and device for separating a feed stream using radiation detectors |
US9752827B2 (en) | 2013-12-06 | 2017-09-05 | Exxonmobil Upstream Research Company | Method and system of maintaining a liquid level in a distillation tower |
US9869511B2 (en) | 2013-12-06 | 2018-01-16 | Exxonmobil Upstream Research Company | Method and device for separating hydrocarbons and contaminants with a spray assembly |
US9874395B2 (en) | 2013-12-06 | 2018-01-23 | Exxonmobil Upstream Research Company | Method and system for preventing accumulation of solids in a distillation tower |
US9874396B2 (en) | 2013-12-06 | 2018-01-23 | Exxonmobil Upstream Research Company | Method and device for separating hydrocarbons and contaminants with a heating mechanism to destabilize and/or prevent adhesion of solids |
US9562719B2 (en) | 2013-12-06 | 2017-02-07 | Exxonmobil Upstream Research Company | Method of removing solids by modifying a liquid level in a distillation tower |
US10139158B2 (en) | 2013-12-06 | 2018-11-27 | Exxonmobil Upstream Research Company | Method and system for separating a feed stream with a feed stream distribution mechanism |
US9504984B2 (en) | 2014-04-09 | 2016-11-29 | Exxonmobil Upstream Research Company | Generating elemental sulfur |
US9739528B2 (en) | 2014-04-22 | 2017-08-22 | Exxonmobil Upstream Research Company | Method and system for starting up a distillation tower |
US9784498B2 (en) | 2014-06-11 | 2017-10-10 | Exxonmobil Upstream Research Company | Method for separating a feed gas in a column |
US9739529B2 (en) | 2014-07-08 | 2017-08-22 | Exxonmobil Upstream Research Company | Method and system for separating fluids in a distillation tower |
US9823017B2 (en) | 2014-10-22 | 2017-11-21 | Exxonmobil Upstream Research Company | Method and system of controlling a temperature within a melt tray assembly of a distillation tower |
US11543179B2 (en) | 2014-11-17 | 2023-01-03 | Exxonmobil Upstream Research Company | Heat exchange mechanism for removing contaminants from a hydrocarbon vapor stream |
US10281205B2 (en) | 2014-11-17 | 2019-05-07 | Exxonmobil Upstream Research Company | Heat exchange mechanism for removing contaminants from a hydrocarbon vapor stream |
US10006700B2 (en) | 2014-12-30 | 2018-06-26 | Exxonmobil Upstream Research Company | Accumulation and melt tray assembly for a distillation tower |
US10495379B2 (en) | 2015-02-27 | 2019-12-03 | Exxonmobil Upstream Research Company | Reducing refrigeration and dehydration load for a feed stream entering a cryogenic distillation process |
US10274252B2 (en) | 2015-06-22 | 2019-04-30 | Exxonmobil Upstream Research Company | Purge to intermediate pressure in cryogenic distillation |
US10365037B2 (en) * | 2015-09-18 | 2019-07-30 | Exxonmobil Upstream Research Company | Heating component to reduce solidification in a cryogenic distillation system |
US11255603B2 (en) | 2015-09-24 | 2022-02-22 | Exxonmobil Upstream Research Company | Treatment plant for hydrocarbon gas having variable contaminant levels |
US10874979B2 (en) | 2015-12-03 | 2020-12-29 | Air Liquide Advanced Technologies U.S. Llc | Method and system for purification of natural gas using membranes |
WO2017096149A1 (en) * | 2015-12-03 | 2017-06-08 | Air Liquide Advanced Technologies, U.S. LLC | Method and system for purification of natural gas using membranes |
US10323495B2 (en) * | 2016-03-30 | 2019-06-18 | Exxonmobil Upstream Research Company | Self-sourced reservoir fluid for enhanced oil recovery |
US10589215B2 (en) | 2017-09-21 | 2020-03-17 | Air Liquide Advanced Technologies U.S. Llc | Production of biomethane using multiple types of membrane |
US20190381450A1 (en) * | 2018-06-19 | 2019-12-19 | L'air Liquide, Societe Anonyme Pour L'etude Et L'exploitation Des Procedes Georges Claude | Systems, processes and methods for concentrating acid gas and producing hydrocarbon liquid with a membrane separation system |
US11306267B2 (en) | 2018-06-29 | 2022-04-19 | Exxonmobil Upstream Research Company | Hybrid tray for introducing a low CO2 feed stream into a distillation tower |
US11378332B2 (en) | 2018-06-29 | 2022-07-05 | Exxonmobil Upstream Research Company | Mixing and heat integration of melt tray liquids in a cryogenic distillation tower |
Also Published As
Publication number | Publication date |
---|---|
EP1819976A4 (en) | 2012-04-04 |
EA014650B1 (en) | 2010-12-30 |
EP1819976A1 (en) | 2007-08-22 |
WO2006062595A1 (en) | 2006-06-15 |
CA2583120C (en) | 2014-03-25 |
EA200701206A1 (en) | 2007-10-26 |
CA2583120A1 (en) | 2006-06-15 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
CA2583120C (en) | Integrated acid gas and sour gas reinjection process | |
CA2857122C (en) | Method of separating carbon dioxide from liquid acid gas streams | |
DK179711B1 (en) | Separating carbon dioxide and hydrogen sulfide from a natural gas stream using co-current contacting systems | |
AU2011283134B2 (en) | Cryogenic systems for removing acid gases from a hydrocarbon gas stream using co-current separation devices | |
AU2009272889B2 (en) | Two stage process for producing purified gas | |
CA2764846C (en) | Systems and methods for removing heavy hydrocarbons and acid gases from a hydrocarbon gas stream | |
Northrop et al. | The CFZ™ process: A cryogenic method for handling high-CO2 and H2S gas reserves and facilitating geosequestration of CO2 and acid gases | |
US20090299122A1 (en) | Process for producing a purified hydrocarbon gas | |
AU2009253116B2 (en) | Producing purified hydrocarbon gas from a gas stream comprising hydrocarbons and acidic contaminants | |
CA2951637C (en) | Method for separating a feed gas in a column | |
US20110144407A1 (en) | Process for producing purified hydrocarbon has | |
AU2010276661B2 (en) | Systems and methods for removing heavy hydrocarbons and acid gases from a hydrocarbon gas stream |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
STCB | Information on status: application discontinuation |
Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION |