WO2009029353A1 - Tail-gas injection in a gas cycle operation - Google Patents

Tail-gas injection in a gas cycle operation Download PDF

Info

Publication number
WO2009029353A1
WO2009029353A1 PCT/US2008/070333 US2008070333W WO2009029353A1 WO 2009029353 A1 WO2009029353 A1 WO 2009029353A1 US 2008070333 W US2008070333 W US 2008070333W WO 2009029353 A1 WO2009029353 A1 WO 2009029353A1
Authority
WO
WIPO (PCT)
Prior art keywords
stream
gas
tail gas
mol
cycle
Prior art date
Application number
PCT/US2008/070333
Other languages
French (fr)
Inventor
Robbin Bruce Anderson
Mark S. Nathern
Peter C. Rasmussen
Original Assignee
Exxonmobil Upstream Research Company
Priority date (The priority date 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 date listed.)
Filing date
Publication date
Application filed by Exxonmobil Upstream Research Company filed Critical Exxonmobil Upstream Research Company
Publication of WO2009029353A1 publication Critical patent/WO2009029353A1/en

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/164—Injecting CO2 or carbonated water
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
    • B01D53/1456—Removing acid components
    • B01D53/1462—Removing mixtures of hydrogen sulfide and carbon dioxide
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B17/00—Sulfur; Compounds thereof
    • C01B17/02—Preparation of sulfur; Purification
    • C01B17/04—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides
    • C01B17/0404—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides by processes comprising a dry catalytic conversion of hydrogen sulfide-containing gases, e.g. the Claus process
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B17/00—Sulfur; Compounds thereof
    • C01B17/02—Preparation of sulfur; Purification
    • C01B17/04—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides
    • C01B17/0404—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides by processes comprising a dry catalytic conversion of hydrogen sulfide-containing gases, e.g. the Claus process
    • C01B17/0456—Preparation of sulfur; Purification from gaseous sulfur compounds including gaseous sulfides by processes comprising a dry catalytic conversion of hydrogen sulfide-containing gases, e.g. the Claus process the hydrogen sulfide-containing gas being a Claus process tail gas
    • 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
    • Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
    • Y02P20/00—Technologies relating to chemical industry
    • Y02P20/151—Reduction of greenhouse gas [GHG] emissions, e.g. CO2

Definitions

  • Embodiments of the invention relate to the use and treatment of sour gas feed streams. More particularly, embodiments of the invention relate to methods and apparatuses for substituting cycle gas with tail gas resulting from a sulfur removal process to improve hydrocarbon utilization.
  • Hydrocarbons such as oil and natural gas are often contaminated with sulfur compounds, which are separated in gas processing plants and refineries.
  • Natural gas referred to herein as "gas" containing sulfur compounds such as hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ) are often referred to as "sour gas.”
  • “Acid gas” is gas with highly concentrated sour components (e.g. usually over about 90%). The treatment and handling of sour gas to generate clean, efficient fuel to power the world economy is one of the world's toughest energy challenges.
  • the sulfur compounds found in sour gas are commonly removed by converting such sulfur compounds into elemental sulfur in sulfur recovery units. The most common of these is a Claus reactor or unit.
  • sulfur recovery units include systems using partial oxidation recovery technology and redox recovery technology.
  • the sulfur conversion plants often include three Claus type reactors in series followed by a tail gas clean up unit to recover and recycle sulfur products that were not converted to elemental sulfur by the sulfur conversion plant or process on the first pass.
  • retrograde condensation the formation of liquid hydrocarbons in a gas reservoir as the pressure in the reservoir decreases below critical point pressure during production. It is called retrograde because the gas condenses into a liquid under isothermal conditions instead of expanding or vaporizing when pressure is decreased.” From Schlumberger Oilfield Glossary, found at http://www.glossary.oilfield.slb.com.
  • U.S. Patent No. 4,382,912 also discusses injection of tail gas from a Claus process, but does not address tail gas conditioning, gas cycling, or treatment of the tail gas.
  • One embodiment of the present invention discloses a method of utilizing hydrocarbons.
  • the method includes providing a gas cycling operation comprising: (i) providing a gaseous feed stream from a gas reservoir, (ii) treating the gaseous feed stream to form at least a gaseous cycle stream, and (iii) injecting the gaseous cycle stream into the gas reservoir.
  • the method of utilizing hydrocarbons further includes substituting at least a portion of the gaseous cycle stream with a treated tail gas and utilizing the at least a portion of the gaseous cycle stream for a non-reservoir application.
  • the treated tail gas is the result of a sulfur recovery process such as a Claus process and the treated tail gas originates from a gas reservoir, chemical plant or other location disassociated with the gas cycling operation.
  • Another embodiment of the present invention discloses a method of producing hydrocarbons.
  • the method includes producing a first feed stream comprising hydrocarbons and sour components from a production gas reservoir; separating the first feed stream into a gaseous stream and a liquid stream; and removing the liquid stream.
  • the method further includes treating the gaseous stream to form: (i) an effluent stream including sour components and (ii) a production stream substantially free of sour components; treating the effluent stream in a sulfur recovery unit to produce elemental sulfur and a tail gas stream; and treating the tail gas stream to form a treated tail gas stream.
  • the method includes the steps of providing a gas cycling operation, wherein a cycle stream containing at least some hydrocarbon components is injected into a cycle gas reservoir, wherein the cycle stream is at least a portion of a second gas stream from the cycle gas reservoir; substituting, in the gas cycling operation, at least a portion of the cycle stream with the treated tail gas stream; and utilizing the at least a portion of the cycle stream for a non-reservoir application.
  • FIG. 1 is an illustration of an exemplary embodiment of a typical gas cycling system for producing natural gas from a reservoir
  • FIG. 2 is an illustration of an embodiment of a system for utilizing hydrocarbons including elements of the typical gas cycling operation of FIG. 1 in accordance with certain aspects of the present invention
  • FIG. 3 is a schematic illustration of a process for utilizing hydrocarbons using the system of FIGs. 1 and 2 in accordance with certain aspects of the present invention
  • FIG. 4 is an illustration of an exemplary alternative embodiment of a system for utilizing hydrocarbons including elements of the typical gas cycling operation of FIGs. 1 and 2 in accordance with certain aspects of the present invention
  • FIG. 5 is a schematic illustration of an exemplary alternative process for utilizing hydrocarbons using elements of the system of FIGs. 1, 2 and 4 in accordance with certain aspects of the present invention.
  • sour gas refers to natural gas containing sour species such as hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ).
  • H 2 S is a contaminant of natural gas that is removed to satisfy legal requirements, as H 2 S and its combustion products of sulfur dioxide and sulfur trioxide are also toxic.
  • H 2 S and/or CO 2 in the presence of free water are corrosive to most metals normally associated with production and transportation equipment, including gas pipelines, so that processing and handling of sour gas may lead to premature failure of such equipment.
  • the term "acid gas” generally refers to a gas consisting almost entirely (e.g. about 90 volume percent) of sour components such as CO 2 and H 2 S with only a small amount of hydrocarbons or other non-sour components.
  • gas cycling refers to a process wherein a gaseous stream is produced from a gas condensate reservoir and a portion of that feed stream including at least some hydrocarbons is reinjected back into the reservoir to maintain reservoir pressure to prevent retrograde condensation.
  • a method of utilizing hydrocarbons is disclosed.
  • the method includes providing a gas cycling operation comprising a gaseous feed stream from a gas reservoir, treating the feed stream to form a gaseous cycle stream, and injecting the gaseous cycle stream into the gas reservoir, wherein at least a portion of the gaseous cycle stream includes hydrocarbons.
  • the method further includes substituting at least a portion of the gaseous cycle stream with a treated tail gas.
  • the treated tail gas may result from any sulfur recovery process at almost any location.
  • the method further includes utilizing the substituted portion of the gaseous cycle stream for a non-reservoir application, such as sales, fuel, or transport.
  • a method of producing hydrocarbons includes producing a feed stream comprising hydrocarbons and sour components from a production gas condensate reservoir; separating the feed stream into a gaseous stream and a liquid stream; and removing the liquid stream.
  • the method also includes treating the gaseous stream to form an effluent stream including sour components and a production stream substantially free of sour components; treating the effluent stream in a sulfur recovery unit to produce elemental sulfur and a tail gas stream; and treating the tail gas stream to form a treated tail gas stream.
  • the method further includes providing a gas cycling operation, wherein a cycle stream containing at least some hydrocarbon components is injected into a cycle gas reservoir; substituting, in the gas cycling operation, at least a portion of the cycle stream with the treated tail gas stream; and utilizing the at least a portion of the cycle stream for a non-reservoir application.
  • FIG. 1 is an illustration of an exemplary embodiment of a typical gas cycling system for producing natural gas from a reservoir.
  • the subsurface hydrocarbon reservoir 102 is accessed.
  • the resulting production or feed stream 104 may include gaseous components, as well as liquid components such as water and hydrocarbons, so it is sent to a liquid separator 106.
  • Liquid separator 106 produces a liquid stream 108 and a separated gaseous stream 110, which is sent to a sour gas removal facility 112 where the sour gas portion 114 is sent to a sulfur recovery unit 116 producing elemental sulfur 118 and tail gas 120.
  • the tail gas may go to a tail gas cleanup unit 122 (e.g.
  • the sweet gas stream 126 resulting from the sour gas treatment facility 112 may be compressed in compressor 128 and injected into the reservoir 102 using injection equipment 130.
  • This type of cycle gas operation 100 is commonly used to prevent retrograde condensation in a gas condensate reservoir 102. If the feed stream is sweet (e.g., less than four parts per million (ppm) H 2 S), then the sour gas treatment 112 and sulfur recovery 116 units may not be needed. However, the sweet gas stream 126 being injected should be compatible with the reservoir 102 and the injection equipment 130 should also be capable of handling the sweet gas stream 126.
  • FIG. 2 is an illustration of an exemplary embodiment of a system for utilizing hydrocarbons including elements of the typical gas cycling operation 100 in accordance with certain aspects of the present invention. Hence, FIG. 2 may be best understood with reference to FIG. 1.
  • the gas reservoir 102 is accessed, producing a feed or production stream 104.
  • the production stream 104 may go through a cycling system such as cycling system 100. However, a source 240 for tail gas stream 242 is provided. The tail gas stream 242 may then be combined with a portion of the cycle gas 126a to form an injection stream 244. Some issues and solutions associated with combining gas streams are more fully disclosed in U.S. Publication No. 2008/0034789, the relevant portions of which are hereby incorporated by reference.
  • the injection stream 244 may then be directed into the reservoir 102 using gas handling equipment, such as compressor 128 and injection equipment 130. Meanwhile, the remainder of the cycle stream 126b may be utilized for a non-reservoir application.
  • the tail gas stream 242 may be injected separately from the portion of the cycle gas 126a, depending on the conditions of the reservoir 102, equipment available, and other factors. For example, in some cases it may be advantageous to inject the lighter stream 126a into the gas cap region and inject the tail gas 242 into a lower portion of the reservoir 102. Such an approach is disclosed more fully in U.S. Application No. 2003/0047309, the relevant portions of which are hereby incorporated by reference. [0028] It should be noted that the treated tail gas stream 242 may come from any source 240. More specifically, the source 240 could be any number of reservoirs, a combination of multiple reservoirs, gas processing plants not specifically tied to any production operation (e.g.
  • tail gas streams 224 and 242 from different origins used as substitution gas.
  • the injection stream 244 may be a combination of streams 126a, 224, and 242.
  • the optional tail gas stream 224 is associated with a tail gas treatment unit 221 (e.g. hydrogenation, reduction, or other treatment process) associated with the gas cycling reservoir 102.
  • the gas cycling system may also include diverting a second portion of the tail gas 223 to a tail gas cleanup unit 122 and a release of some amount of the resulting gas 125 into the atmosphere. [0029] FIG.
  • FIG. 3 is a schematic illustration of a process for utilizing hydrocarbons using gas processing system 200 in accordance with certain aspects of the present invention. Hence, FIG. 3 may be best understood with reference to FIGs. 1 and 2.
  • the process 300 includes providing a gas cycling operation 302.
  • the cycling operation may include a gaseous feed stream 104 from a gas reservoir 102, treating the feed stream 104 to produce a gaseous cycle stream 126, wherein the gaseous cycle stream 126 is injected into the gas reservoir 102.
  • substituting 304 at least a portion of the cycle stream 126 with a treated tail gas stream 242 and utilizing the substituted cycle stream 126b for a non-reservoir application such as fuel or sales.
  • Treatment and formulation of the tail gas prior to injection may be accomplished by a variety of processes depending on the character of the reservoir 102, local regulations, air quality, and other factors.
  • oxygen-enriched air or pure oxygen may be fed into the sulfur reduction unit 116 to generate a tail gas with lower nitrogen content, which may be more compatible with the uphole equipment or downhole environment.
  • the tail gas treatment unit 221 may include a variety of processes such as hydrogenation, reduction, dehydration (e.g. glycol dehydration and/or interstage free water knockout), or other processes and may be combined with the handling processes to prevent corrosion or fouling of the compressors, tubulars, seals, and other equipment used for treating and handling of tail gas.
  • the treatment unit 221 may include on-line monitoring and the capability to divert tail gas to a flare system or incinerator in the event of the potential for SO 2 breaking through the treatment unit 221 into the compressor(s) 128.
  • On-line monitoring may be accomplished through a variety of technologies and techniques known to those of skill in the art of gas treatment and handling and may include process analyzers and computers connected via servers or distributed networks and communication links such as Wi-Fi, Ethernet, telephone lines, etc.
  • Such monitoring systems may be located at a central control station (not shown) and may include manual overrides, alarms, probability calculators, and other features.
  • Handling of the tail gas may include a variety of processes depending on the character of the reservoir 102, local regulations, and other factors.
  • One exemplary handling process may comprise sending the tail gas through a series of compressors, such as compressor 128 or a different compressor, liquid knock-out vessels, and interstage coolers (not shown).
  • the equipment used is preferably compatible with the composition of the tail gas 242 and/or 224 and may be a combined system for handling the injection gas 244. For example, if the stream is a "wet" stream, then piping and equipment should be resistant to corrosion from water condensation. Also, if the stream includes un-reacted SO 2 , it may leave sulfur deposits on the compressors and other equipment, so anti-fouling coatings or other treatments may be appropriate.
  • FIG. 4 is an illustration of an exemplary alternative embodiment of a system for utilizing hydrocarbons including elements of a typical gas cycling operation 100 in accordance with certain aspects of the present invention. Hence, FIG. 4 may be best understood with reference to FIGs. 1 and 2. In such a system 400, a production reservoir 402 is accessed at a first location 403.
  • the resulting production stream 404 may include liquid components, so it is sent to a liquid separator 406, which produces a liquid stream 408 and a gaseous stream 410.
  • the gaseous stream 410 then goes to a sour gas treatment facility 412 producing a sweet gas portion 426 and a sour component portion 414, which is sent to a sulfur recovery unit 416 producing elemental sulfur 418 and tail gas 420, which may be sent to a treatment facility 421 resulting in a tail gas stream 424.
  • a typical gas cycling operation such as cycling operation 100 is conducted at a cycle reservoir 102.
  • the tail gas stream 424 may be combined with a portion of the cycle gas 126a.
  • the combined stream 444 may then be sent to the compressor 128 for compression, then injected using injection equipment 130, therefore allowing the replaced portion of the cycle gas 126b to be used for a non-reservoir application.
  • the cycle gas operation 100 may optionally be modified to add a tail gas treatment unit 221 before the tail gas cleanup unit 122 to produce another source of tail gas 224 to be combined with the cycle gas portion 126a and the tail gas 424 to form the combined stream 444.
  • the cycle stream 126a may be injected separately from the tail gas streams 224 and 424, as discussed above.
  • the sour gas treatment facility 412 and sulfur recovery unit 416 may be remotely located from the first location 403.
  • the sour gas treatment 412 and sulfur recovery unit 416 may be located at or near the cycle reservoir 102 or remotely therefrom depending on a variety of circumstances such as geography, climate, pipeline conditions, pre-existing pipelines or other facilities, and other factors generally know to those of skill in the art.
  • the feed stream 404 from the production reservoir 402 is preferably a sour gas feed stream.
  • Higher levels of sour gas will generally result in more tail gas, therefore, more of the cycle gas 126 may be substituted, resulting in a higher percentage of the cycle gas 126 being diverted for sales or fuel 126b.
  • another source of tail gas (not shown) is compatible with the composition of the cycle reservoir 102, that gas may be used as the substitute for the cycle gas 126 to allow redirection or diversion of an even higher percentage of the cycle gas 126 to sales or fuel 126b.
  • the liquid separation unit 106 or 406 may comprise any available technology for liquid separation, such as, for example refrigeration, lean oil absorption, or adsorption onto a solid sorbent like silica gel.
  • the resulting liquid product 108 or 408 will depend on the composition of the source reservoir 102 or 402 and the recovery method employed, but will generally comprise water and heavier hydrocarbons, such as propane, butane, pentane, hexanes, or aromatics, natural gasoline, and even crude oil.
  • the resulting gaseous stream 110 or 410 may include a significant portion of sour components such as hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ) as well as some light hydrocarbons (e.g.
  • the gaseous streams 110 and 410 may include from about 20 mol percent (%) to about 80 mol % sour components, from about 20 mol % to about 70 mol % light hydrocarbons and from about 1 mol % to about 10 mol % other components.
  • the sour gas removal unit or plants 112 and 412 may comprise any available technology for sour gas removal or separation known to those of skill in the art.
  • Some exemplary technologies include solvent treatment, such as absorbing the sour components in an amine such as Methyldiethanolamine (MDEA); or a physical solvent like refrigerated methanol; Controlled Freeze ZoneTM (CFZTM) treatment developed by ExxonMobil; membrane separation technology; amine treatment; and iron sponge technology.
  • solvent treatment such as absorbing the sour components in an amine such as Methyldiethanolamine (MDEA); or a physical solvent like refrigerated methanol; Controlled Freeze ZoneTM (CFZTM) treatment developed by ExxonMobil; membrane separation technology; amine treatment; and iron sponge technology.
  • the sulfur recovery unit 116 or 416 may comprise any available technology for removing elemental sulfur 118 or 418 from the gaseous stream 114 or 414 containing a significant amount of H 2 S, such as over 40 mol % H 2 S. It should be noted that the sulfur recovery unit 416 may not be related to either the production or cycle gas reservoirs 402 or 102, but may be related to another plant or simply positioned at another location depending on geography, climate, local regulations, the presence of groundwater, and like considerations. Some exemplary sulfur recovery processes include the Claus process, partial oxidation recovery technology, and redox recovery technology. Examples of the Claus process may be found in U.S. Pat. Nos. 4,765,407 and 4,382,912.
  • the tail gas 120 or 420 resulting from this process most likely includes high percentages of nitrogen (N 2 ), water (H 2 O) and carbon dioxide (CO 2 ), the remainder being H 2 S, SO 2 , carbonyl sulfide (COS), carbon disulfide (CS 2 ), elemental sulfur, mercaptans, argon, hydrogen (H 2 ), carbon monoxide, and trace amounts of other components.
  • the tail gas stream 120 or 420 may also need to be cooled to a temperature from about 200 0 F to about 400 0 F. Note, this cooling may result in some sour water dropout, which may be treated separately depending on legal, environmental, and technological factors.
  • the tail gas 120 or 420 resulting from the sulfur recovery unit 116 or 416 is cleaned up using any of a variety of processes such as sulfur dioxide absorption, amine, and/or other solvent treatments such as CrystaSulf SM from CrystaTech, Inc.
  • the tail gas may also be recycled in the sulfur reduction process until the gaseous stream is more than 99.8% free of sulfur dioxide and hydrogen sulfide as required by many clean air regulations around the world.
  • the process of the present invention eliminates the need to provide such a sulfide free stream because the tail gas 120 or 420 is not intended to be combusted and/or vented into the atmosphere.
  • the nitrogen content of the tail gas 120 or 420 resulting from the sulfur recovery unit (SRU) 116 or 416 may be reduced by enriching the air fed into the SRU 116 or 416 with oxygen or replacing air with oxygen to eliminate nitrogen from the tail gas 120 or 420.
  • the tail gas treatment unit 221 or 421 may include a variety of technologies such as hydrogenation, compression, dehydration, and other similar technologies.
  • the treatment results in a stream 224, 242, or 424 that is compatible with the gas reservoir 102 for injection in sufficient quantity to maintain sufficient pressure to prevent retrograde condensation and to enhance gas production operations.
  • the treatment unit 221 may include on-line monitoring and the capability to divert tail gas to a flare system or incinerator in the event of SO 2 breaking through the treatment unit 221. The monitoring may also be utilized to ensure proper compatibility with the injection reservoir 102 prior to injection.
  • the treatment unit 221 may be adjustable manually, in real-time, or automatically to ensure compatibility, adjust oxygen-enrichment, avoid breakthrough, and account for other potential events.
  • the treated tail gas may comprise from at least about 60 mol percent (%) nitrogen (N 2 ) to about 90 mol % N 2 , from at least about 10 mol % carbon dioxide (CO 2 ) to about 30 mol % CO 2 , from at least about 0.5 mol % hydrogen sulfide (H 2 S) to about 5 mol % H 2 S, and may be injected at from about 1,000 pounds per square inch gauge (psig) to about 6,000 psig and a temperature of from about 8O 0 F to about 16O 0 F.
  • psig pounds per square inch gauge
  • the treated tail gas may comprise from at least about 70 mol percent (%) nitrogen (N 2 ) to about 75 mol % N 2 , from at least about 20 mol % carbon dioxide (CO 2 ) to about 25 mol % CO 2 , from at least about 0.5 mol % hydrogen sulfide (H 2 S) to about 1.0 mol % H 2 S, from at least about 0.0 mol % sulfur dioxide (SO 2 ) to about 0.5 mol % SO 2 .
  • the sweet gas 126 or 426 resulting from the sour gas treatment 112 or 412 preferably comprises a significant hydrocarbon component, most likely a light hydrocarbon component such as methane and/or ethane (Ci and/or C 2 ).
  • the composition of the sweet gas 126 or 426 may vary greatly and is dependent largely on the composition of the reservoir.
  • An exemplary sweet gas composition comprises from at least about 85 mol percent (%) methane plus ethane (Ci + C 2 ) to about 99.9 mol % Ci + C 2 and from at least about 0.1 mol % nitrogen (N 2 ) to about 15 mol % N 2 .
  • the nitrogen is generally inert and is typically compatible with almost any gas reservoir, but nitrogen content has an effect on the miscibility of the injected gas with the gas already in place in the reservoir.
  • a more thorough discussion of the affect of nitrogen injection into a gas reservoir and miscibility may be found in U.S. Pat. No. 4,765,407 at FIG. 1, col. 1, and col. 2.
  • the composition of the production gas reservoir 402 may vary significantly, but preferably includes light and heavy hydrocarbons, some gas condensate components, and some sour components such as hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ).
  • One exemplary composition includes from at least about 50 mol percent (%) hydrocarbons to about 80 mol % hydrocarbons, from at least about 5 mol % H 2 S to about 30 mol % H 2 S, and from at least about 5 mol % CO 2 to about 20 mol % CO 2 .
  • the cycle reservoir 102 may have a similar composition to the production gas reservoir 402, but preferably is a gas condensate reservoir and preferably includes a lower percentage of sour components than the production gas reservoir 402.
  • the composition of the cycle reservoir 102 may also vary significantly, but may include light and heavy hydrocarbons.
  • FIG. 5 is a schematic illustration of an exemplary alternative process for utilizing hydrocarbons using elements of the system 400 in accordance with certain aspects of the present invention.
  • the process 500 includes producing 502 a first feed stream 404 from a production subsurface reservoir 402, then separating 504 the first feed stream 404 into a liquid stream 408 and a gaseous stream 410 (if necessary).
  • the liquid stream 408 is removed 506.
  • the liquid stream 408 would likely comprise water and heavier hydrocarbons and be used for sale, energy, or other purposes, but may be another type of liquid.
  • the gaseous stream 410 is treated 508 to form a sour gas portion (effluent stream) 414 containing acid gas components and a production stream 426, then the sour gas portion (effluent stream) 414 is directed 510 to a sulfur recovery unit 416 to produce a tail gas stream 420 and an elemental sulfur stream 418, and the tail gas stream 420 is treated 512.
  • a gas cycling operation is provided 514 at a cycle subsurface reservoir 102, wherein the cycle gas 126 is from a portion of the cycle feed stream 104 from the cycle reservoir 102 and includes at least some hydrocarbon components.

Abstract

Methods and apparatuses for producing natural gas are provided. One method includes a more efficient utilization of hydrocarbons. The method includes providing a gas cycling operation comprising a gaseous feed stream from a gas reservoir, treating the gaseous feed stream to form at least a gaseous cycle stream, and injecting the gaseous cycle stream into the gas reservoir; substituting at least a portion of the gaseous cycle stream with a treated tail gas; and utilizing the at least a portion of the gaseous cycle stream for a non-reservoir application such as sales or fuel. The tail gas can be from any location and any type of process, but is a result of a sulfur recovery process such as a Claus unit. The Claus unit may be associated with the gas cycling reservoir, another reservoir, a refinery, or other operation.

Description

TAIL-GAS INJECTION IN A GAS CYCLE OPERATION CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional Application No. 60/966,731, filed 29 August 2007 and U.S. Provisional Application No. 61/002,189, filed 07 November 2007.
FIELD OF THE INVENTION
[0002] Embodiments of the invention relate to the use and treatment of sour gas feed streams. More particularly, embodiments of the invention relate to methods and apparatuses for substituting cycle gas with tail gas resulting from a sulfur removal process to improve hydrocarbon utilization.
BACKGROUND OF THE INVENTION
[0003] This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present invention. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present invention. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art. Description of the Related Art
[0004] Hydrocarbons such as oil and natural gas are often contaminated with sulfur compounds, which are separated in gas processing plants and refineries. Natural gas (referred to herein as "gas") containing sulfur compounds such as hydrogen sulfide (H2S) and carbon dioxide (CO2) are often referred to as "sour gas." "Acid gas" is gas with highly concentrated sour components (e.g. usually over about 90%). The treatment and handling of sour gas to generate clean, efficient fuel to power the world economy is one of the world's toughest energy challenges. [0005] The sulfur compounds found in sour gas are commonly removed by converting such sulfur compounds into elemental sulfur in sulfur recovery units. The most common of these is a Claus reactor or unit. Other examples of sulfur recovery units include systems using partial oxidation recovery technology and redox recovery technology. In order to maximize sulfur removal and minimize atmospheric sulfur emissions, the sulfur conversion plants often include three Claus type reactors in series followed by a tail gas clean up unit to recover and recycle sulfur products that were not converted to elemental sulfur by the sulfur conversion plant or process on the first pass.
[0006] In addition to producing a clean and efficient fuel, hydrocarbon production operations seek to maximize the amount of gas produced from a given subsurface reservoir. During production of certain gas reservoirs, it is desirable to maintain pressure to avoid a problem called "retrograde condensation." One useful definition of retrograde condensation is "the formation of liquid hydrocarbons in a gas reservoir as the pressure in the reservoir decreases below critical point pressure during production. It is called retrograde because the gas condenses into a liquid under isothermal conditions instead of expanding or vaporizing when pressure is decreased." From Schlumberger Oilfield Glossary, found at http://www.glossary.oilfield.slb.com. Thus, retrograde condensation allows hydrocarbons to condense in a reservoir, resulting in a "wetting" of the subsurface formation, further resulting in fewer recoverable hydrocarbons from such a reservoir. Various approaches have been taken to address this issue of preventing a loss of hydrocarbons, which typically takes the form of maintaining pressure in the reservoir above a minimum pressure by cycling produced gas back to the reservoir or building a dedicated nitrogen plant to inject the nitrogen into the reservoir. [0007] Gas cycling is one process that may be utilized to maintain pressure within a reservoir to avoid retrograde condensation and other issues. Gas may be injected into gas caps over oil reservoirs so that the pressure that pushes the oil to the producing wells is not lost. Gas is also injected in gas zones not associated with oil that contain higher concentrations of heavier hydrocarbons (propane and heavier). In such situations, the gas is produced and the heavier hydrocarbons are separated from the lighter hydrocarbon components leaving a lighter gas stream having an increased methane composition. This lighter gas stream is reinjected so that the pressure in the reservoir is not lost, heavier hydrocarbons are swept into the producing wells, and retrograde condensation does not occur. One disadvantage to this approach is that light hydrocarbons may be injected into the reservoir instead of used for sales or to generate energy. [0008] U.S. Pat. No. 4,765,407 (the '407 patent) teaches pressure maintenance of a gas reservoir using treated tail gas from a Claus plant. However, the '407 patent fails to teach or suggest a solution to the gas cycling problem.
[0009] U.S. Patent No. 4,382,912 also discusses injection of tail gas from a Claus process, but does not address tail gas conditioning, gas cycling, or treatment of the tail gas. SUMMARY OF THE INVENTION
[0010] One embodiment of the present invention discloses a method of utilizing hydrocarbons. The method includes providing a gas cycling operation comprising: (i) providing a gaseous feed stream from a gas reservoir, (ii) treating the gaseous feed stream to form at least a gaseous cycle stream, and (iii) injecting the gaseous cycle stream into the gas reservoir. The method of utilizing hydrocarbons further includes substituting at least a portion of the gaseous cycle stream with a treated tail gas and utilizing the at least a portion of the gaseous cycle stream for a non-reservoir application. In some embodiments, the treated tail gas is the result of a sulfur recovery process such as a Claus process and the treated tail gas originates from a gas reservoir, chemical plant or other location disassociated with the gas cycling operation.
[0011] Another embodiment of the present invention discloses a method of producing hydrocarbons. The method includes producing a first feed stream comprising hydrocarbons and sour components from a production gas reservoir; separating the first feed stream into a gaseous stream and a liquid stream; and removing the liquid stream. The method further includes treating the gaseous stream to form: (i) an effluent stream including sour components and (ii) a production stream substantially free of sour components; treating the effluent stream in a sulfur recovery unit to produce elemental sulfur and a tail gas stream; and treating the tail gas stream to form a treated tail gas stream. Additionally, the method includes the steps of providing a gas cycling operation, wherein a cycle stream containing at least some hydrocarbon components is injected into a cycle gas reservoir, wherein the cycle stream is at least a portion of a second gas stream from the cycle gas reservoir; substituting, in the gas cycling operation, at least a portion of the cycle stream with the treated tail gas stream; and utilizing the at least a portion of the cycle stream for a non-reservoir application. BRIEF DESCRIPTION OF THE DRAWINGS
[0012] The foregoing and other advantages of the present invention may become apparent upon reviewing the following detailed description and drawings of non-limiting examples of embodiments in which: [0013] FIG. 1 is an illustration of an exemplary embodiment of a typical gas cycling system for producing natural gas from a reservoir;
[0014] FIG. 2 is an illustration of an embodiment of a system for utilizing hydrocarbons including elements of the typical gas cycling operation of FIG. 1 in accordance with certain aspects of the present invention; [0015] FIG. 3 is a schematic illustration of a process for utilizing hydrocarbons using the system of FIGs. 1 and 2 in accordance with certain aspects of the present invention;
[0016] FIG. 4 is an illustration of an exemplary alternative embodiment of a system for utilizing hydrocarbons including elements of the typical gas cycling operation of FIGs. 1 and 2 in accordance with certain aspects of the present invention; and [0017] FIG. 5 is a schematic illustration of an exemplary alternative process for utilizing hydrocarbons using elements of the system of FIGs. 1, 2 and 4 in accordance with certain aspects of the present invention.
DETAILED DESCRIPTION OF THE INVENTION [0018] In the following detailed description section, the specific embodiments of the present invention are described in connection with preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present invention, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the invention is not limited to the specific embodiments described below, but rather, it includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims. [0019] The term "sour gas" refers to natural gas containing sour species such as hydrogen sulfide (H2S) and carbon dioxide (CO2). When a significant portion of the H2S and CO2 have been removed from the natural gas feed stream, the gas is classified as "sweet." The term "sour gas" is applied to natural gases including H2S because of the odor that is emitted even at low concentrations from an unsweetened gas. H2S is a contaminant of natural gas that is removed to satisfy legal requirements, as H2S and its combustion products of sulfur dioxide and sulfur trioxide are also toxic. Furthermore, H2S and/or CO2 in the presence of free water are corrosive to most metals normally associated with production and transportation equipment, including gas pipelines, so that processing and handling of sour gas may lead to premature failure of such equipment.
[0020] The term "acid gas" generally refers to a gas consisting almost entirely (e.g. about 90 volume percent) of sour components such as CO2 and H2S with only a small amount of hydrocarbons or other non-sour components. [0021] The term "gas cycling" refers to a process wherein a gaseous stream is produced from a gas condensate reservoir and a portion of that feed stream including at least some hydrocarbons is reinjected back into the reservoir to maintain reservoir pressure to prevent retrograde condensation. [0022] In one embodiment of the present invention, a method of utilizing hydrocarbons is disclosed. The method includes providing a gas cycling operation comprising a gaseous feed stream from a gas reservoir, treating the feed stream to form a gaseous cycle stream, and injecting the gaseous cycle stream into the gas reservoir, wherein at least a portion of the gaseous cycle stream includes hydrocarbons. The method further includes substituting at least a portion of the gaseous cycle stream with a treated tail gas. The treated tail gas may result from any sulfur recovery process at almost any location. The method further includes utilizing the substituted portion of the gaseous cycle stream for a non-reservoir application, such as sales, fuel, or transport.
[0023] In another embodiment of the present invention, a method of producing hydrocarbons is disclosed. The method includes producing a feed stream comprising hydrocarbons and sour components from a production gas condensate reservoir; separating the feed stream into a gaseous stream and a liquid stream; and removing the liquid stream. The method also includes treating the gaseous stream to form an effluent stream including sour components and a production stream substantially free of sour components; treating the effluent stream in a sulfur recovery unit to produce elemental sulfur and a tail gas stream; and treating the tail gas stream to form a treated tail gas stream. The method further includes providing a gas cycling operation, wherein a cycle stream containing at least some hydrocarbon components is injected into a cycle gas reservoir; substituting, in the gas cycling operation, at least a portion of the cycle stream with the treated tail gas stream; and utilizing the at least a portion of the cycle stream for a non-reservoir application.
[0024] Referring now to the figures, FIG. 1 is an illustration of an exemplary embodiment of a typical gas cycling system for producing natural gas from a reservoir. In such a system 100, the subsurface hydrocarbon reservoir 102 is accessed. The resulting production or feed stream 104 may include gaseous components, as well as liquid components such as water and hydrocarbons, so it is sent to a liquid separator 106. Liquid separator 106 produces a liquid stream 108 and a separated gaseous stream 110, which is sent to a sour gas removal facility 112 where the sour gas portion 114 is sent to a sulfur recovery unit 116 producing elemental sulfur 118 and tail gas 120. The tail gas may go to a tail gas cleanup unit 122 (e.g. may include elemental sulfur output or recycle stream to unit 116 - not shown) and vented into the atmosphere via a stack, vent or similar unit 125. Meanwhile, the sweet gas stream 126 resulting from the sour gas treatment facility 112 may be compressed in compressor 128 and injected into the reservoir 102 using injection equipment 130. [0025] This type of cycle gas operation 100 is commonly used to prevent retrograde condensation in a gas condensate reservoir 102. If the feed stream is sweet (e.g., less than four parts per million (ppm) H2S), then the sour gas treatment 112 and sulfur recovery 116 units may not be needed. However, the sweet gas stream 126 being injected should be compatible with the reservoir 102 and the injection equipment 130 should also be capable of handling the sweet gas stream 126. More specifically, the injected sweet gas stream 126 should not include any sour components if the gas in the reservoir 102 does not include any sour components. Also, if there are sour components and/or some liquid components in the sweet gas stream 126, the injection equipment 130, the compressor 128, and the piping or tubing carrying the sweet gas stream 126 should be designed to handle that type of stream to prevent fouling or corrosion. [0026] FIG. 2 is an illustration of an exemplary embodiment of a system for utilizing hydrocarbons including elements of the typical gas cycling operation 100 in accordance with certain aspects of the present invention. Hence, FIG. 2 may be best understood with reference to FIG. 1. In the gas processing system 200, the gas reservoir 102 is accessed, producing a feed or production stream 104. The production stream 104 may go through a cycling system such as cycling system 100. However, a source 240 for tail gas stream 242 is provided. The tail gas stream 242 may then be combined with a portion of the cycle gas 126a to form an injection stream 244. Some issues and solutions associated with combining gas streams are more fully disclosed in U.S. Publication No. 2008/0034789, the relevant portions of which are hereby incorporated by reference. The injection stream 244 may then be directed into the reservoir 102 using gas handling equipment, such as compressor 128 and injection equipment 130. Meanwhile, the remainder of the cycle stream 126b may be utilized for a non-reservoir application.
[0027] Alternatively, the tail gas stream 242 may be injected separately from the portion of the cycle gas 126a, depending on the conditions of the reservoir 102, equipment available, and other factors. For example, in some cases it may be advantageous to inject the lighter stream 126a into the gas cap region and inject the tail gas 242 into a lower portion of the reservoir 102. Such an approach is disclosed more fully in U.S. Application No. 2003/0047309, the relevant portions of which are hereby incorporated by reference. [0028] It should be noted that the treated tail gas stream 242 may come from any source 240. More specifically, the source 240 could be any number of reservoirs, a combination of multiple reservoirs, gas processing plants not specifically tied to any production operation (e.g. pipeline straddle plants), refineries, chemical plants and any other sulfur Claus plants. Also, there may be multiple tail gas streams 224 and 242 from different origins used as substitution gas. In such a case, the injection stream 244 may be a combination of streams 126a, 224, and 242. Note that the optional tail gas stream 224 is associated with a tail gas treatment unit 221 (e.g. hydrogenation, reduction, or other treatment process) associated with the gas cycling reservoir 102. The gas cycling system may also include diverting a second portion of the tail gas 223 to a tail gas cleanup unit 122 and a release of some amount of the resulting gas 125 into the atmosphere. [0029] FIG. 3 is a schematic illustration of a process for utilizing hydrocarbons using gas processing system 200 in accordance with certain aspects of the present invention. Hence, FIG. 3 may be best understood with reference to FIGs. 1 and 2. The process 300 includes providing a gas cycling operation 302. The cycling operation may include a gaseous feed stream 104 from a gas reservoir 102, treating the feed stream 104 to produce a gaseous cycle stream 126, wherein the gaseous cycle stream 126 is injected into the gas reservoir 102. Then, substituting 304 at least a portion of the cycle stream 126 with a treated tail gas stream 242 and utilizing the substituted cycle stream 126b for a non-reservoir application such as fuel or sales. [0030] Treatment and formulation of the tail gas prior to injection may be accomplished by a variety of processes depending on the character of the reservoir 102, local regulations, air quality, and other factors. For example, oxygen-enriched air or pure oxygen may be fed into the sulfur reduction unit 116 to generate a tail gas with lower nitrogen content, which may be more compatible with the uphole equipment or downhole environment. The tail gas treatment unit 221 may include a variety of processes such as hydrogenation, reduction, dehydration (e.g. glycol dehydration and/or interstage free water knockout), or other processes and may be combined with the handling processes to prevent corrosion or fouling of the compressors, tubulars, seals, and other equipment used for treating and handling of tail gas. [0031] In one exemplary embodiment of the present invention, the treatment unit 221 may include on-line monitoring and the capability to divert tail gas to a flare system or incinerator in the event of the potential for SO2 breaking through the treatment unit 221 into the compressor(s) 128. On-line monitoring may be accomplished through a variety of technologies and techniques known to those of skill in the art of gas treatment and handling and may include process analyzers and computers connected via servers or distributed networks and communication links such as Wi-Fi, Ethernet, telephone lines, etc. Such monitoring systems may be located at a central control station (not shown) and may include manual overrides, alarms, probability calculators, and other features. [0032] Handling of the tail gas may include a variety of processes depending on the character of the reservoir 102, local regulations, and other factors. One exemplary handling process may comprise sending the tail gas through a series of compressors, such as compressor 128 or a different compressor, liquid knock-out vessels, and interstage coolers (not shown). The equipment used is preferably compatible with the composition of the tail gas 242 and/or 224 and may be a combined system for handling the injection gas 244. For example, if the stream is a "wet" stream, then piping and equipment should be resistant to corrosion from water condensation. Also, if the stream includes un-reacted SO2, it may leave sulfur deposits on the compressors and other equipment, so anti-fouling coatings or other treatments may be appropriate. [0033] Other beneficial applications of the present invention include sequestering the hydrogen sulfide and carbon dioxide components of the treated tail gas stream, enhancing hydrocarbon production, and pressure maintenance in a gas reservoir. The treated tail gas 224 or 242 may be used for any of these purposes instead of or in combination with gas substitution. [0034] FIG. 4 is an illustration of an exemplary alternative embodiment of a system for utilizing hydrocarbons including elements of a typical gas cycling operation 100 in accordance with certain aspects of the present invention. Hence, FIG. 4 may be best understood with reference to FIGs. 1 and 2. In such a system 400, a production reservoir 402 is accessed at a first location 403. The resulting production stream 404 may include liquid components, so it is sent to a liquid separator 406, which produces a liquid stream 408 and a gaseous stream 410. The gaseous stream 410 then goes to a sour gas treatment facility 412 producing a sweet gas portion 426 and a sour component portion 414, which is sent to a sulfur recovery unit 416 producing elemental sulfur 418 and tail gas 420, which may be sent to a treatment facility 421 resulting in a tail gas stream 424. [0035] Approximately concurrently, a typical gas cycling operation such as cycling operation 100 is conducted at a cycle reservoir 102. The tail gas stream 424 may be combined with a portion of the cycle gas 126a. The combined stream 444 may then be sent to the compressor 128 for compression, then injected using injection equipment 130, therefore allowing the replaced portion of the cycle gas 126b to be used for a non-reservoir application. The cycle gas operation 100 may optionally be modified to add a tail gas treatment unit 221 before the tail gas cleanup unit 122 to produce another source of tail gas 224 to be combined with the cycle gas portion 126a and the tail gas 424 to form the combined stream 444. Alternatively, the cycle stream 126a may be injected separately from the tail gas streams 224 and 424, as discussed above. [0036] In this exemplary system, it should be noted that the sour gas treatment facility 412 and sulfur recovery unit 416 may be remotely located from the first location 403. The sour gas treatment 412 and sulfur recovery unit 416 may be located at or near the cycle reservoir 102 or remotely therefrom depending on a variety of circumstances such as geography, climate, pipeline conditions, pre-existing pipelines or other facilities, and other factors generally know to those of skill in the art.
[0037] It should also be noted that the feed stream 404 from the production reservoir 402 is preferably a sour gas feed stream. Higher levels of sour gas will generally result in more tail gas, therefore, more of the cycle gas 126 may be substituted, resulting in a higher percentage of the cycle gas 126 being diverted for sales or fuel 126b. Also, if another source of tail gas (not shown) is compatible with the composition of the cycle reservoir 102, that gas may be used as the substitute for the cycle gas 126 to allow redirection or diversion of an even higher percentage of the cycle gas 126 to sales or fuel 126b. [0038] Referring now to FIGs. 1, 2, and 4 independently or in combination, the liquid separation unit 106 or 406 may comprise any available technology for liquid separation, such as, for example refrigeration, lean oil absorption, or adsorption onto a solid sorbent like silica gel. The resulting liquid product 108 or 408 will depend on the composition of the source reservoir 102 or 402 and the recovery method employed, but will generally comprise water and heavier hydrocarbons, such as propane, butane, pentane, hexanes, or aromatics, natural gasoline, and even crude oil. The resulting gaseous stream 110 or 410 may include a significant portion of sour components such as hydrogen sulfide (H2S) and carbon dioxide (CO2) as well as some light hydrocarbons (e.g. Ci to C3 hydrocarbons) and include small portions of other components such as H2O, nitrogen, mercaptans, and carbonyl sulfide (COS). In at least one exemplary embodiment, the gaseous streams 110 and 410 may include from about 20 mol percent (%) to about 80 mol % sour components, from about 20 mol % to about 70 mol % light hydrocarbons and from about 1 mol % to about 10 mol % other components. [0039] The sour gas removal unit or plants 112 and 412 may comprise any available technology for sour gas removal or separation known to those of skill in the art. Some exemplary technologies include solvent treatment, such as absorbing the sour components in an amine such as Methyldiethanolamine (MDEA); or a physical solvent like refrigerated methanol; Controlled Freeze Zone™ (CFZ™) treatment developed by ExxonMobil; membrane separation technology; amine treatment; and iron sponge technology. These and other sour gas separation techniques and tools are generally known to those of skill in the art and the selection and operation of such units will be dependant on many factors such as cost, geography, climate, availability, and similar considerations.
[0040] The sulfur recovery unit 116 or 416 may comprise any available technology for removing elemental sulfur 118 or 418 from the gaseous stream 114 or 414 containing a significant amount of H2S, such as over 40 mol % H2S. It should be noted that the sulfur recovery unit 416 may not be related to either the production or cycle gas reservoirs 402 or 102, but may be related to another plant or simply positioned at another location depending on geography, climate, local regulations, the presence of groundwater, and like considerations. Some exemplary sulfur recovery processes include the Claus process, partial oxidation recovery technology, and redox recovery technology. Examples of the Claus process may be found in U.S. Pat. Nos. 4,765,407 and 4,382,912. Smaller percentages of H2S may be processed using such a sulfur recovery unit 116 or 416, but other methods may be more efficient. The tail gas 120 or 420 resulting from this process most likely includes high percentages of nitrogen (N2), water (H2O) and carbon dioxide (CO2), the remainder being H2S, SO2, carbonyl sulfide (COS), carbon disulfide (CS2), elemental sulfur, mercaptans, argon, hydrogen (H2), carbon monoxide, and trace amounts of other components. Depending on the technology used, the tail gas stream 120 or 420 may also need to be cooled to a temperature from about 2000F to about 4000F. Note, this cooling may result in some sour water dropout, which may be treated separately depending on legal, environmental, and technological factors.
[0041] Typically, the tail gas 120 or 420 resulting from the sulfur recovery unit 116 or 416 is cleaned up using any of a variety of processes such as sulfur dioxide absorption, amine, and/or other solvent treatments such as CrystaSulfSM from CrystaTech, Inc. The tail gas may also be recycled in the sulfur reduction process until the gaseous stream is more than 99.8% free of sulfur dioxide and hydrogen sulfide as required by many clean air regulations around the world. However, the process of the present invention eliminates the need to provide such a sulfide free stream because the tail gas 120 or 420 is not intended to be combusted and/or vented into the atmosphere. [0042] In one embodiment of the present invention, the nitrogen content of the tail gas 120 or 420 resulting from the sulfur recovery unit (SRU) 116 or 416 may be reduced by enriching the air fed into the SRU 116 or 416 with oxygen or replacing air with oxygen to eliminate nitrogen from the tail gas 120 or 420.
[0043] The tail gas treatment unit 221 or 421 may include a variety of technologies such as hydrogenation, compression, dehydration, and other similar technologies. The treatment results in a stream 224, 242, or 424 that is compatible with the gas reservoir 102 for injection in sufficient quantity to maintain sufficient pressure to prevent retrograde condensation and to enhance gas production operations. In one exemplary embodiment, the treatment unit 221 may include on-line monitoring and the capability to divert tail gas to a flare system or incinerator in the event of SO2 breaking through the treatment unit 221. The monitoring may also be utilized to ensure proper compatibility with the injection reservoir 102 prior to injection. Further, the treatment unit 221 may be adjustable manually, in real-time, or automatically to ensure compatibility, adjust oxygen-enrichment, avoid breakthrough, and account for other potential events. [0044] By "compatible with the reservoir," it is meant that the stream 224, 242, or 424 is not too sour for the reservoir composition. In one exemplary embodiment, the treated tail gas may comprise from at least about 60 mol percent (%) nitrogen (N2) to about 90 mol % N2, from at least about 10 mol % carbon dioxide (CO2) to about 30 mol % CO2, from at least about 0.5 mol % hydrogen sulfide (H2S) to about 5 mol % H2S, and may be injected at from about 1,000 pounds per square inch gauge (psig) to about 6,000 psig and a temperature of from about 8O0F to about 16O0F. More specifically, the treated tail gas may comprise from at least about 70 mol percent (%) nitrogen (N2) to about 75 mol % N2, from at least about 20 mol % carbon dioxide (CO2) to about 25 mol % CO2, from at least about 0.5 mol % hydrogen sulfide (H2S) to about 1.0 mol % H2S, from at least about 0.0 mol % sulfur dioxide (SO2) to about 0.5 mol % SO2.
[0045] Meanwhile, the sweet gas 126 or 426 resulting from the sour gas treatment 112 or 412 preferably comprises a significant hydrocarbon component, most likely a light hydrocarbon component such as methane and/or ethane (Ci and/or C2). The composition of the sweet gas 126 or 426 may vary greatly and is dependent largely on the composition of the reservoir. An exemplary sweet gas composition comprises from at least about 85 mol percent (%) methane plus ethane (Ci + C2) to about 99.9 mol % Ci + C2 and from at least about 0.1 mol % nitrogen (N2) to about 15 mol % N2. Note, the nitrogen is generally inert and is typically compatible with almost any gas reservoir, but nitrogen content has an effect on the miscibility of the injected gas with the gas already in place in the reservoir. A more thorough discussion of the affect of nitrogen injection into a gas reservoir and miscibility may be found in U.S. Pat. No. 4,765,407 at FIG. 1, col. 1, and col. 2.
[0046] Depending on the content of the reservoirs 102 and 402 and the particular economic, political, technological and other considerations at a particular location anywhere from at least about 20 volume percent (vol%) to over 80 vol% of the cycle gas 126 may be substituted by the treated tail gas 224, 242, or 424. The amount of substitution will also depend on the compositions of the reservoirs 102 and 402 as well as the content of the treated tail gas 224, 242, or 424 and the cycle gas 126. In at least one exemplary embodiment, at least about 50 vol% of the cycle gas 126 is substituted with the treated tail gas 424 for use in a non-reservoir application [0047] The composition of the production gas reservoir 402 may vary significantly, but preferably includes light and heavy hydrocarbons, some gas condensate components, and some sour components such as hydrogen sulfide (H2S) and carbon dioxide (CO2). One exemplary composition includes from at least about 50 mol percent (%) hydrocarbons to about 80 mol % hydrocarbons, from at least about 5 mol % H2S to about 30 mol % H2S, and from at least about 5 mol % CO2 to about 20 mol % CO2.
[0048] The cycle reservoir 102 may have a similar composition to the production gas reservoir 402, but preferably is a gas condensate reservoir and preferably includes a lower percentage of sour components than the production gas reservoir 402. The composition of the cycle reservoir 102 may also vary significantly, but may include light and heavy hydrocarbons.
[0049] FIG. 5 is a schematic illustration of an exemplary alternative process for utilizing hydrocarbons using elements of the system 400 in accordance with certain aspects of the present invention. Hence, FIG. 5 may be best understood with reference to FIGs. 1, 2, and 4. The process 500 includes producing 502 a first feed stream 404 from a production subsurface reservoir 402, then separating 504 the first feed stream 404 into a liquid stream 408 and a gaseous stream 410 (if necessary). The liquid stream 408 is removed 506. In general, the liquid stream 408 would likely comprise water and heavier hydrocarbons and be used for sale, energy, or other purposes, but may be another type of liquid. The gaseous stream 410 is treated 508 to form a sour gas portion (effluent stream) 414 containing acid gas components and a production stream 426, then the sour gas portion (effluent stream) 414 is directed 510 to a sulfur recovery unit 416 to produce a tail gas stream 420 and an elemental sulfur stream 418, and the tail gas stream 420 is treated 512. A gas cycling operation is provided 514 at a cycle subsurface reservoir 102, wherein the cycle gas 126 is from a portion of the cycle feed stream 104 from the cycle reservoir 102 and includes at least some hydrocarbon components. Next, at least a portion of the cycle gas 126 is substituted 516 with the treated tail gas 424 and the substituted cycle gas 126b is used for a non-reservoir application 518, such as fuel or sales. [0050] While the present invention may be susceptible to various modifications and alternative forms, the exemplary embodiments discussed above have been shown only by way of example. However, it should again be understood that the invention is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present invention includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

Claims

Claims:What is claimed is:
1. A method of utilizing hydrocarbons, comprising: providing a gas cycling operation comprising (i) providing a gaseous feed stream from a gas reservoir, (ii) treating the gaseous feed stream to form at least a gaseous cycle stream, and (iii) injecting the gaseous cycle stream into the gas reservoir; substituting at least a portion of the gaseous cycle stream with a treated tail gas; and utilizing the at least a portion of the gaseous cycle stream for a non-reservoir application.
2. The method of claim 1 , wherein the treated tail gas results from at least one of treating at least a portion of the gaseous feed stream, treating a portion of a second gaseous feed stream from a second gas reservoir, and treating a tail gas stream from a refinery.
3. The method of any of claims 1 -2, wherein the treated tail gas is produced by a sulfur recovery unit.
4. The method of any of claims 1 -3 , wherein the treated tail gas is produced by any one of a Claus process, a partial oxidation recovery technology, an oxygen-enriched Claus process, and a redox recovery technology.
5. The method of any one of claims 3-4, further comprising additionally treating the treated tail gas, wherein the additionally treated tail gas is produced by any one of a hydrogenation and a reduction process.
6. The method of claim 5, further comprising monitoring at least one of the treated tail gas and the additionally treated tail gas; and diverting at least one of the treated tail gas and the additionally treated tail gas to a flare system or incinerator in the event of a sulfur dioxide breakthrough.
7. The method of any of claims 1-6, wherein the gaseous feed stream includes at least one sour component.
8. The method of any of claims 1-7, wherein the portion of the gaseous cycle stream is utilized for any combination of sales and fuel.
9. The method of claim 8, wherein the portion of the gaseous cycle stream utilized for sales comprises an amount greater than about 50 percent of the amount of the substituted treated tail gas injected into the first gas reservoir.
10. The method of any of claims 1-9, wherein the gaseous feed stream comprises from at least about 50 mol percent (%) hydrocarbons to about 80 mol % hydrocarbons, from at least about 5 mol % hydrogen sulfide (H2S) to about 30 mol % H2S, and from at least about 5 mol % carbon dioxide (CO2) to about 20 mol % CO2.
11. The method of any of claims 1-10, wherein the gaseous cycle stream includes at least one light hydrocarbon component.
12. The method of any of claims 1-11, wherein the gaseous cycle stream comprises from at least about 85 mol percent (%) methane plus ethane (Ci + C2) to about 99.9 mol % Ci + C2 and from at least about 0.1 mol % nitrogen (N2) to about 15 mol % N2.
13. The method of any of claims 1-12, wherein from at least about 20 volume percent (vol %) to about 80 vol % of the gaseous cycle stream is substituted with the treated tail gas.
14. The method of any of claims 1-13, wherein the treated tail gas is compatible with the first gas reservoir.
15. The method of claim 14, wherein the treated tail gas includes sour components compatible with the first gas reservoir.
16. The method of any of claims 1-15, wherein the treated tail gas is compressed prior to being injected into one of the first gas reservoir and the second gas reservoir.
17. The method of any of claims 1-16, wherein the treated tail gas comprises from at least about 60 mol percent (%) nitrogen (N2) to about 80 mol % N2, from at least about 10 mol % carbon dioxide (CO2) to about 30 mol % CO2, from at least about 0.5 mol % hydrogen sulfide (H2S) to about 5 mol % H2S.
18. The method of any of claims 1-17, wherein the treated tail gas is injected into the first reservoir for any one of sequestering the hydrogen sulfide and carbon dioxide components of the treated tail gas stream, enhancing hydrocarbon production, and pressure maintenance in the first gas reservoir.
19. The method of any of claims 1-18, wherein the injected portion of the gaseous cycle stream is injected into the gas reservoir separately from the treated tail gas.
20. A method of producing hydrocarbons, comprising:
(a) producing a first feed stream comprising hydrocarbons and sour components from a production gas reservoir;
(b) separating the first feed stream into a gaseous stream and a liquid stream; (c) removing the liquid stream;
(d) treating the gaseous stream to form (i) an effluent stream including sour components and (ii) a production stream substantially free of sour components;
(e) treating the effluent stream in a sulfur recovery unit to produce elemental sulfur and a tail gas stream; (f) treating the tail gas stream to form a treated tail gas stream;
(g) providing a gas cycling operation, wherein a cycle stream containing at least some hydrocarbon components is injected into a cycle gas reservoir, wherein the cycle stream is at least a portion of a second gas stream from the cycle gas reservoir; (h) substituting, in the gas cycling operation, at least a portion of the cycle stream with the treated tail gas stream; and
(i) utilizing the at least a portion of the cycle stream for a non-reservoir application.
21. The method of claim 20, wherein the feed stream comprises from at least about 50 mol percent (%) hydrocarbons to about 80 mol % hydrocarbons, from at least about 5 mol % hydrogen sulfide (H2S) to about 30 mol % H2S, and from at least about 5 mol % carbon dioxide (CO2) to about 20 mol % CO2.
22. The method of any of claims 20-21 , wherein the production and cycle gas reservoirs are gas condensate reservoirs.
23. The method of any of claims 20-22, wherein the cycle stream comprises from at least about 85 mol percent (%) ethane plus methane (Ci + C2) to about 99.9 mol % Ci + C2 and from at least about 0.1 mol % nitrogen (N2) to about 15 mol % N2.
24. The method of any of claims 20-23, wherein from at least about 20 volume percent
(vol %) to about 80 vol % of the cycle stream is substituted with the treated tail gas stream.
25. The method of any of claims 20-24, wherein the treated tail gas stream includes sour components compatible with the cycle gas reservoir.
26. The method of any of claims 20-25, wherein the treated tail gas is produced by any one of a Claus process, partial oxidation recovery technology, an oxygen-enriched Claus process, and redox recovery technology.
27. The method of any one of claims 25-26, further comprising additionally treating the treated tail gas from step f), wherein the additionally treated tail gas is produced by any one of a hydrogenation and a reduction process.
28. The method of claim 27, further comprising monitoring at least one of the treated tail gas and the additionally treated tail gas; and diverting at least one of the treated tail gas and the additionally treated tail gas to a flare system or incinerator in the event of a sulfur dioxide breakthrough.
29. The method of any of claims 20-28, wherein the treated tail gas stream is compressed prior to being injected into the cycle gas reservoir.
30. The method of any of claims 20-29, wherein the treated tail gas stream comprises from at least about 60 mol percent (%) nitrogen (N2) to about 80 mol % N2, from at least about 10 mol % carbon dioxide (CO2) to about 30 mol % CO2, from at least about 0.5 mol % hydrogen sulfide (H2S) to about 5 mol % H2S.
31. The method of any of claims 20-30, wherein the portion of the cycle stream is utilized for any combination of sales and fuel.
32. The method of claim 31 , wherein the portion of the cycle stream utilized for sales comprises an amount greater than about 50 percent of the amount of the substituted treated tail gas injected into the cycle gas reservoir.
33. The method of any of claims 20-32, wherein the gaseous stream is separated using a process selected from the group of technologies comprising physical solvents, chemical solvents, mole sieves, iron sponge, and membranes technologies to produce an effluent stream rich in sour components.
PCT/US2008/070333 2007-08-29 2008-07-17 Tail-gas injection in a gas cycle operation WO2009029353A1 (en)

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US96673107P 2007-08-29 2007-08-29
US60/966,731 2007-08-29
US218907P 2007-11-07 2007-11-07
US61/002,189 2007-11-07

Publications (1)

Publication Number Publication Date
WO2009029353A1 true WO2009029353A1 (en) 2009-03-05

Family

ID=40387685

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2008/070333 WO2009029353A1 (en) 2007-08-29 2008-07-17 Tail-gas injection in a gas cycle operation

Country Status (1)

Country Link
WO (1) WO2009029353A1 (en)

Cited By (20)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
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
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
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
US9751767B2 (en) 2013-10-02 2017-09-05 Pilot Energy Solutions, Llc Catalytic reactor for converting contaminants in a displacement fluid and generating energy
US9752827B2 (en) 2013-12-06 2017-09-05 Exxonmobil Upstream Research Company Method and system of maintaining a liquid level in a distillation tower
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
US9869511B2 (en) 2013-12-06 2018-01-16 Exxonmobil Upstream Research Company Method and device for separating hydrocarbons and contaminants with a spray assembly
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
US9874395B2 (en) 2013-12-06 2018-01-23 Exxonmobil Upstream Research Company Method and system for preventing accumulation of solids in a distillation tower
US9964352B2 (en) 2012-03-21 2018-05-08 Exxonmobil Upstream Research Company Separating carbon dioxide and ethane from a mixed stream
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
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
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
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

Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4382912A (en) * 1981-09-10 1983-05-10 Gulf Research & Development Company Selective combusting of hydrogen sulfide in carbon dioxide injection gas
US4765407A (en) * 1986-08-28 1988-08-23 Amoco Corporation Method of producing gas condensate and other reservoirs
US6505683B2 (en) * 2000-04-27 2003-01-14 Institut Francais Du Petrole Process for purification by combination of an effluent that contains carbon dioxide and hydrocarbons

Patent Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4382912A (en) * 1981-09-10 1983-05-10 Gulf Research & Development Company Selective combusting of hydrogen sulfide in carbon dioxide injection gas
US4765407A (en) * 1986-08-28 1988-08-23 Amoco Corporation Method of producing gas condensate and other reservoirs
US6505683B2 (en) * 2000-04-27 2003-01-14 Institut Francais Du Petrole Process for purification by combination of an effluent that contains carbon dioxide and hydrocarbons

Cited By (26)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
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
US10222121B2 (en) 2009-09-09 2019-03-05 Exxonmobil Upstream Research Company Cryogenic system for removing acid gases from a hydrocarbon gas stream
EP2525892A1 (en) * 2010-01-22 2012-11-28 Exxonmobil Upstream Research Company Removal of acid gases from a gas stream, with co2 capture and sequestration
EP2525892A4 (en) * 2010-01-22 2014-01-22 Exxonmobil Upstream Res Co Removal of acid gases from a gas stream, with co2 capture 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
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
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
US9964352B2 (en) 2012-03-21 2018-05-08 Exxonmobil Upstream Research Company Separating carbon dioxide and ethane from a mixed stream
US10323879B2 (en) 2012-03-21 2019-06-18 Exxonmobil Upstream Research Company Separating carbon dioxide and ethane from a mixed stream
US9751767B2 (en) 2013-10-02 2017-09-05 Pilot Energy Solutions, Llc Catalytic reactor for converting contaminants in a displacement fluid and generating energy
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
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
US9869511B2 (en) 2013-12-06 2018-01-16 Exxonmobil Upstream Research Company Method and device for separating hydrocarbons and contaminants with a spray assembly
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
US9874395B2 (en) 2013-12-06 2018-01-23 Exxonmobil Upstream Research Company Method and system for preventing accumulation of solids 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
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
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
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
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
US10323495B2 (en) 2016-03-30 2019-06-18 Exxonmobil Upstream Research Company Self-sourced reservoir fluid for enhanced oil recovery
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

Similar Documents

Publication Publication Date Title
WO2009029353A1 (en) Tail-gas injection in a gas cycle operation
CA2823242C (en) Use of gas-separation membranes to enhance production in fields containing high concentrations of hydrogen sulfides
US8282707B2 (en) Natural gas purification system
US9149761B2 (en) Removal of acid gases from a gas stream, with CO2 capture and sequestration
US9994452B2 (en) Integrated process for native CO2 recovery from a sour gas comprising H2S and CO2
US7803215B2 (en) Adsorber for pretreatment of natural gas containing bulk hydrogen sulfide
Ebenezer et al. Removal of carbon dioxide from natural gas for LNG production
US7678263B2 (en) Gas stripping process for removal of sulfur-containing components from crude oil
US20110041687A1 (en) Multi-stage membrane separation process
CA2577387A1 (en) Combined use of external and internal solvents in processing gases containing light, medium and heavy components
US20210086131A1 (en) Removal of Acid Gases From A Gas Stream, With O2 Enrichment For Acid Gas Capture and Sequestration
Kargari et al. Application of membrane gas separation processes in petroleum industry
US20120240650A1 (en) Stabilization and remote recovery of acid gas fractions from sour wellsite gas
JP2016188161A (en) Production equipment for carbon dioxide and production method for carbon dioxide
JP4758711B2 (en) Pretreatment method for gas hydrate production
US10363517B2 (en) Systems and methods to dehydrate high acid gas streams using membranes in an oil and gas processing plant
EP3946687A1 (en) Improving sulfur recovery operation with improved carbon dioxide recovery
EP3883670A1 (en) Co-current gas absortion method and system with an enhanced absorbent
KR102372751B1 (en) The System and Method for Carbon Dioxide Separation from Natural Gas before Gas Liquefaction Process on LNG-FPSO
Mckay et al. Acid Gas Dehydration-Is There a Better Way?
Tierling et al. Considerations for the use of carbon dioxide removal membranes in an offshore environment
KR102372754B1 (en) The Method for Carbon Dioxide Removal from Natural Gas
Echt Part 1: hybrid separation schemes for C [O. sub. 2] removal: conditioning natural gas: the savings in capital and operating expenses can be obtained via hybrid systems consisting of membranes and any downstream solvent process.(Cover Story)
Alhameli Process simulation and modeling for gas processing plant
Peters Natural Gas-The Cinderella Hydrocarbon

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 08796238

Country of ref document: EP

Kind code of ref document: A1

NENP Non-entry into the national phase

Ref country code: DE

122 Ep: pct application non-entry in european phase

Ref document number: 08796238

Country of ref document: EP

Kind code of ref document: A1