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WO2005093017A1 - Compositions combustibles comprenant du gaz naturel et des hydrocarbures synthetiques, et leurs procedes de preparation - Google Patents

Compositions combustibles comprenant du gaz naturel et des hydrocarbures synthetiques, et leurs procedes de preparation Download PDF

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Publication number
WO2005093017A1
WO2005093017A1 PCT/US2005/008982 US2005008982W WO2005093017A1 WO 2005093017 A1 WO2005093017 A1 WO 2005093017A1 US 2005008982 W US2005008982 W US 2005008982W WO 2005093017 A1 WO2005093017 A1 WO 2005093017A1
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WIPO (PCT)
Prior art keywords
natural gas
synthetic hydrocarbon
lng
component
synthetic
Prior art date
Application number
PCT/US2005/008982
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English (en)
Inventor
Michael D. Briscoe
Theo H. Fleisch
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Bp Corporation North America Inc.
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Filing date
Publication date
Priority claimed from US10/805,943 external-priority patent/US20040244279A1/en
Application filed by Bp Corporation North America Inc. filed Critical Bp Corporation North America Inc.
Publication of WO2005093017A1 publication Critical patent/WO2005093017A1/fr

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Classifications

    • 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 OR C10K; LIQUIFIED PETROLEUM GAS; USE OF ADDITIVES TO FUELS OR FIRES; FIRE-LIGHTERS
    • 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
    • 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 OR C10K; LIQUIFIED PETROLEUM GAS; USE OF ADDITIVES TO FUELS OR FIRES; FIRE-LIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/003—Additives for gaseous fuels
    • 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
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/0002—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures characterised by the fluid to be liquefied
    • F25J1/0022—Hydrocarbons, e.g. 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
    • F25J1/00—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures
    • F25J1/02—Processes or apparatus for liquefying or solidifying gases or gaseous mixtures requiring the use of refrigeration, e.g. of helium or hydrogen ; Details and kind of the refrigeration system used; Integration with other units or processes; Controlling aspects of the process
    • F25J1/0243—Start-up or control of the process; Details of the apparatus used; Details of the refrigerant compression system used
    • F25J1/0244—Operation; Control and regulation; Instrumentation
    • F25J1/0254—Operation; Control and regulation; Instrumentation controlling particular process parameter, e.g. pressure, temperature
    • F25J1/0255—Operation; Control and regulation; Instrumentation controlling particular process parameter, e.g. pressure, temperature controlling the composition of the feed or liquefied gas, e.g. to achieve a particular heating value of 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
    • F25J2210/00—Processes characterised by the type or other details of the feed stream
    • F25J2210/04—Mixing or blending of fluids with 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
    • F25J2210/00—Processes characterised by the type or other details of the feed stream
    • F25J2210/62—Liquefied natural gas [LNG]; Natural gas liquids [NGL]; Liquefied petroleum gas [LPG]
    • 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
    • F25J2215/00—Processes characterised by the type or other details of the product stream
    • F25J2215/02—Mixing or blending of fluids to yield a certain product

Definitions

  • the present invention relates to fuel compositions derived from natural gas, and in particular to fuel gas compositions comprising blends of synthetic light hydrocarbons and natural gas, including natural gas components derived from liquefied natural gas (LNG), and also methods for preparation of the fuel blends.
  • LNG liquefied natural gas
  • Natural gas generally refers to rarefied or gaseous hydrocarbons (comprised of methane and light hydrocarbons such as ethane, propane, butane, and the like) which are found in the earth.
  • Non-combustible gases occurring in the earth such as carbon dioxide, helium and nitrogen are generally referred to by their proper chemical names.
  • non-combustible gases are found in combination with combustible gases and the mixture is referred to generally as "natural gas” without any attempt to distinguish between combustible and non-combustible gases. See Pruitt, "Mineral Terms-Some Problems in Their Use and Definition," Rocky Mt. Min. L. Rev. 1 , 16 (1966).
  • Natural gas is often plentiful in regions where it is uneconomical to develop those reserves due to lack of a local market for the gas or the high cost of processing and transporting the gas to distant markets. Such natural gas is accordingly referred to in the energy industry as “stranded gas” or "remote gas”. Recently a number of methods have been investigated and/or proposed to allow for more economic use of such resources by converting the stranded gas into liquid products which are more readily transportable, such as methanol, dimethyl ether or other chemicals, as well as liquid hydrocarbons via Fischer-Tropsch hydrocarbon synthesis.
  • the natural gas is preferably cooled to -240°F (-151 °C) to -260°F (-162°C) where it may exist as a liquid at near atmospheric vapor pressure.
  • Various methods and/or systems exist in the prior art for liquefying natural gas or the like whereby the gas is liquefied by sequentially passing the gas at an elevated pressure through a plurality of cooling stages, and cooling the gas to successively lower temperatures until liquefaction is achieved. Cooling is generally accomplished by heat exchange with one or more refrigerants such as propane, propylene, ethane, ethylene, nitrogen and methane, or mixtures thereof.
  • the refrigerants are commonly arranged in a cascaded manner, in order of diminishing refrigerant boiling point.
  • processes for preparation of LNG generally are disclosed in U.S. Patents 4,445,917; 5,537,827; 6,023,942; 6,041 ,619; 6,062,041 ; 6,248,794, and UK Patent Application GB 2,357,140 A. The teachings of these patents are incorporated herein by reference in their entirety.
  • Natural gas produced from some subterranean reservoirs can comprise a very lean gas, i.e., a gas wherein the hydrocarbon content is predominately methane with only relatively minor levels (less than about 3 mol%) of higher molecular weight natural, i.e., virgin, hydrocarbons therein, such as those hydrocarbons boiling greater than methane, typically C 2 -C 5 hydrocarbons.
  • higher molecular weight natural i.e., virgin, hydrocarbons therein, such as those hydrocarbons boiling greater than methane, typically C 2 -C 5 hydrocarbons.
  • the natural gas industry including those who produce LNG, may remove at least a portion of the higher molecular weight hydrocarbons present in the natural gas depending on the local market demands, and direct them to other uses.
  • the resulting LNG can have an undesirably low heating value, such as less than 1000 BTU/SCF. Consumers of LNG can typically require a higher heating value, such as from about 1000 BTU/SCF to about 1200 BTU/SCF and even higher.
  • the LNG product heating value has been increased by blending it with selected amounts of light virgin hydrocarbons, such as ethane, propane, or butanes, which are most often supplied as a mixture typically referred to as liquefied petroleum gas or "LPG".
  • LPG liquefied petroleum gas
  • This practice may not always be economical for the LNG producer and/or LNG consumer. For example, if the natural gas is very lean or a source of LPG is not readily available at the site where the natural gas is converted to LNG or where the LNG is re- gasified for use by a consumer thereof, then LPG must be shipped to such sites. At present, a significant quantity of LNG is consumed in the Asian Pacific markets and to meet heating value specifications in this market for some LNG products, LPG is shipped long distances for blending with low heat value LNG products. As a result, this practice increases the costs associated with such LNG products.
  • the foregoing objectives may be attained by the present invention, which in one aspect relates to a composition comprising a natural gas component and a synthetic hydrocarbon component comprised of light synthetic hydrocarbons.
  • the composition may comprise a blend of the natural gas component and the synthetic hydrocarbon component in liquid form, such as that obtained by condensing both the natural gas component and synthetic hydrocarbon component in a LNG process; or in vapor form, such as that obtained by mixing a regasified LNG product with the synthetic hydrocarbon component in the vapor phase, or by mixing a produced natural gas with the synthetic hydrocarbon component in the vapor phase.
  • the invention in another aspect, relates to a method for preparing a fuel blend comprising mixing a natural gas component with a synthetic hydrocarbon component comprised of light synthetic hydrocarbons.
  • the method further comprises preparing the natural gas component by the steps of: pre-treating a natural gas stream comprising acid gases, water and other contaminants therein to remove at least a portion of the contaminants therefrom and provide a natural gas feed; cooling the natural gas feed in a LNG process to liquefy at least a portion of the natural gas feed and thereby produce a LNG product; and re-gasifying the LNG product to obtain the natural gas component.
  • the method also comprises adding the following steps of: providing the synthetic hydrocarbon component; and mixing the synthetic hydrocarbon component with the natural gas component in the vapor phase to obtain the fuel blend.
  • the synthetic hydrocarbon component may be added in any amount to achieve a desired higher heating value, provided, however, that the resulting fuel blend will be maintained below the hydrocarbon dew point for the pressure and temperatures at which the fuel blend is to be stored or conveyed, typically those conditions being specified for the pipeline in which the fuel blend is to be conveyed to market or the ultimate user thereof.
  • the amount of synthetic hydrocarbon added will be less than 25 mol% based on the total fuel blend, including from 1 to 25 mol%, and beneficially from 10-15 mol% of the total fuel blend.
  • the method may be convenient to re-gasify the LNG product and mix it with the synthetic hydrocarbon component at a site remote from a location where the natural gas feed originates, and more particularly, at a location near the market for the fuel blend.
  • the method further comprises: pre-treating a natural gas stream comprising acid gases, water and other contaminants therein to remove at least a portion of the contaminants therefrom and provide a natural gas feed for the LNG process; mixing the synthetic hydrocarbon component into the natural gas feed of the LNG process at a temperature and in an amount such that the synthetic hydrocarbon component does not solidify and form a separate solid phase during liquefaction of the natural gas feed in the LNG process; cooling the resulting natural gas and synthetic hydrocarbon mixture within the LNG process to a temperature of from about -240°F (-151 °C) to about - 260°F (-162 ) or less so as to liquefy at least a portion of the mixture and thereby produce a blended liquid product at substantially atmospheric pressure; and re-gasifying the blended liquid product to produce the fuel blend.
  • the mixing may be in the vapor phase, the liquid phase, or both, and the synthetic hydrocarbon may be added in an amount to achieve a desired higher heating value when the blended liquid product is regasified, provided, that the amount of synthetic hydrocarbon added will not result in solidification of the synthetic hydrocarbon in the blended liquid product, typically 25 mol% or less based on the total blended liquid product.
  • the blended liquid product according to the foregoing method can be conveniently re-gasified just prior to use to produce the desired fuel blend, and in particular, at a site remote from a location where the natural gas stream originates or the blended liquid product is produced, such as a location near the market for the fuel blend.
  • the invention is directed to a method for preparing a fuel blend comprising natural gas and a synthetic hydrocarbon component.
  • the method comprises: pre-treating a natural gas stream comprising acid gases, water and other contaminants therein to remove at least a portion of the contaminants therefrom and provide a natural gas feed; cooling the natural gas feed in a LNG process to liquefy at least a portion of the natural gas feed and thereby produce a LNG product; providing the synthetic hydrocarbon component; re-gasifying the LNG product to obtain the natural gas component; and mixing the synthetic hydrocarbon component with the natural gas component in the vapor phase to obtain the fuel blend.
  • Figure 1 is a schematic process flow sheet illustrating a process for preparing methanol with a feed that includes all or a portion of CO 2 contaminant that may be separated and recovered from a lean natural gas produced from a subterranean reservoir. At least a portion of the methanol may then be reacted to form light olefins or paraffins (synthetic hydrocarbons) in a hydrocarbon synthesis process, which synthetic hydrocarbons in turn can then be mixed with the natural gas to form a fuel blend composition of higher heat value relative to the lean natural gas.
  • synthetic hydrocarbons synthetic hydrocarbons
  • Figures 2a and 2b are simplified block flow diagrams illustrating embodiments of the present invention, wherein a lean natural gas is blended with a synthetic hydrocarbon component in the vapor phase and then condensed in a natural gas liquefaction process to produce a blended liquid product.
  • the synthetic hydrocarbons can comprise a "synthetic LPG" derived from a Fischer- Tropsch hydrocarbon synthesis process as illustrated in Fig. 2a, which may also produce liquid products, such as naphtha, diesel, and lube blending stocks.
  • Fig. 2a synthetic LPG
  • a Fischer- Tropsch hydrocarbon synthesis process as illustrated in Fig. 2a
  • liquid products such as naphtha, diesel, and lube blending stocks.
  • the synthetic hydrocarbons can comprise olefins and/or paraffins derived from methanol or dimethylether via a methanol to ( olefins process as described hereinafter.
  • the blended liquid product may then be conveniently transported to a distant market, and later re-gasified at a site remote from the location where the blended liquid product is produced or liquefied to provide a fuel composition with greater heat value relative to the lean natural gas.
  • Figures 3a and 3b are simplified block flow diagrams illustrating other embodiments of the present invention, wherein LNG produced from a lean natural gas and a synthetic hydrocarbon component are re-gasified and mixed in the vapor phase to produce a fuel blend according to the invention.
  • the synthetic hydrocarbons can similarly comprise a "synthetic LPG" derived from a Fischer-Tropsch hydrocarbon synthesis process as illustrated in Fig. 3a.
  • the synthetic hydrocarbons can comprise olefins and/or paraffins derived from methanol or dimethylether via a methanol to olefins process.
  • the LNG and synthetic hydrocarbon employed may be manufactured at a location where the raw natural gas used to make the LNG is produced from a subterranean reservoir. The LNG and synthetic hydrocarbon can then be conveniently transported to a distant market, and later re-gasified and mixed to provide a fuel blend composition with greater heat value relative to the lean natural gas.
  • the fuel compositions of the invention are comprised of a natural gas component and a synthetic hydrocarbon component, both as described hereinafter.
  • the natural gas feed employed for preparation of the natural gas component may be any natural or synthetic light hydrocarbon-containing gas, such as produced from natural gas, coal, shale oil, residua or combinations I, thereof, which can be used as a fuel gas.
  • it is a lean virgin natural gas with a relatively low heating value, such as less than 1000 BTU/scf.
  • the term "virgin" in reference to hydrocarbons means hydrocarbons that have not been obtained by hydrocarbon synthesis methods, such as an MTO process or Fischer-Tropsch synthesis as described hereinafter.
  • a “synthetic hydrocarbon” is a hydrocarbon obtained by chemical conversion of another carbon-containing feedstock, such as by a Fischer-Tropsch hydrocarbon synthesis as described hereinafter, or alternatively olefins and/or paraffins derived from methanol and/or dimethylether feed via a methanol to olefins synthesis as described hereinafter.
  • the synthetic hydrocarbon component comprises a blend of C 2 to C synthetic olefins, paraffins, or mixtures thereof in any combination.
  • the natural gas feed mentioned above may also be conveniently used to prepare LNG and/or a synthetic hydrocarbon component for use in preparing the fuel compositions according to the invention, as described hereinbelow.
  • the natural gas feed contemplated for use herein generally comprises at least 50 mole percent methane, preferably at least 75 mole percent methane, and more preferably at least 90 mole percent methane.
  • the balance of the natural gas feed can generally comprise other combustible hydrocarbons such as, but not limited to, lesser amounts of ethane, propane, butane, pentane, and other higher boiling hydrocarbons, and non- combustible components such as carbon dioxide, hydrogen sulfide, helium and nitrogen.
  • hydrocarbons boiling at a temperature above the boiling point of pentane or hexane are generally directed to crude oil.
  • Hydrocarbon boiling substantially at a temperature above the boiling point of ethane and below the boiling point of pentane or hexane are typically removed from the methane feed to an LNG process, and are sometimes considered to be natural gas liquids or "NGLs". Excessive amounts of these heavier hydrocarbons are also typically removed from natural gas produced from a formation in preparation of a natural gas fuel.
  • the natural gas feed processed in accordance with the present invention is preferably a lean natural gas such that it may be directed to the manufacture of the fuel compositions, LNG or synthetic hydrocarbons without requiring additional processing steps for removal of NGLs.
  • the natural gas may be pre-treated at a natural gas plant for pre- removal of the above components or may be conveyed directly to an LNG or related plant for pre-processing prior to manufacture of fuel products.
  • the natural gas reservoirs that contain significant amounts of non-combustible CO 2 gas therein.
  • commercial scale LNG plants use processes which generally require nearly complete removal of acid gases, including CO 2 , from the feed gas to the LNG process.
  • the CO 2 extracted from the feed gas has been simply vented to the atmosphere.
  • the CO removed from a natural gas feed can be recovered and used to make methanol and synthetic hydrocarbons, such as synthetic olefins and/or paraffins, for use in accordance with the present invention.
  • Pretreatment steps suitable for use with the present invention generally begin with steps commonly identified and known in connection with LMG production or hydrocarbon synthesis, including, but not limited to, removal of acid gases (such as H 2 S and CO 2 ), merca ptans, mercury and moisture from the natural gas feed stream.
  • Acid gases and mercaptans are commonly removed via a sorption process employing an aqueous amine-containing solution or other types of known physical or chemical solvents. This step is generally performed upstream of most of the natural gas processing steps. A substantial portion of the water is generally removed as a liquid through two-phase gas-liqu id separation prior to or after low level cooling, followed by molecular sieve processing for removal of trace amounts of water. Mercury is removed through use of mercury sorbent beds. Residual amounts of water and acid gases are most commonly removed through the use of particularly selected sorbent beds such as regenerable molecular sieves. Such particularly selected sorbent beds are also generally positioned upstream of most of the natural gas processing steps. Preferably, the pretreatment of the natural gas feed results in a C0 2 content of less than 0.1 mole percent, and more preferably less than 0.01 mole percent, based on the total natural gas feed.
  • a CO 2 rich stream for use in the manufacture of methanol and light synthetic hydrocarbons, wherein the C0 2 rich stream has minimal amounts of contaminants, such as H 2 S, mercaptans, and other sulfur-containing compounds.
  • an inhibited amine solution can be used to selectively remove the CO 2 in the natural gas stream, but not H 2 S.
  • the H 2 S can then be removed in a subsequent step.
  • a guard bed such as a ZnO guard bed
  • Such reactors typically employ nickel catalysts which can be susceptible to poisoning by sulfur-containing compounds, such as H 2 S.
  • the natural gas component employed in the present invention may be a stream that is obtained from the natural gas feed after pre-treatment as previously mentioned, or in other embodiments it is a stream arising from an LNG process for the preparation of LNG, or a stream obtained by regasification of an LNG product.
  • the LNG may be prepared according to any known LNG process as previously described.
  • processes for preparation of LNG generally are disclosed in U.S. Patents 4,445,917; 5,537,827; 6,023,942; 6,041 ,619; 6,062,041; 6,248,794, and UK Patent Application GB 2,357,140 A, the teachings of which are incorporated herein by reference in their entirety.
  • Another LNG process which is integrated with other processes to produce liquid products from natural gas is also disclosed in U.S. Patent 6,743,829, and further U.S. Patent Application, Serial No.
  • the synthetic hydrocarbon component can be prepared by any known method, and particularly an indirect synthesis process, wherein the natural gas feed stream is passed to a synthesis gas plant for conversion of the feed stream to synthesis gas, and the synthesis gas is thereafter converted to oxygenates, such as methanol, which may then be converted to hydrocarbons, such as olefins or paraffins. Alternatively, the synthesis gas may be converted directly to such hydrocarbons via Fischer-Tropsch synthesis. If not already removed as previously described, impurities such as sulfur compounds, nitrogen compounds, particulate matter, and condensables are removed so as to ultimately provide a synthesis gas stream reduced in contaminants and containing a molar ratio of hydrogen to carbon oxide (carbon monoxide plus carbon dioxide). A carbon oxide, as used herein, refers to carbon dioxide and/or carbon monoxide. Synthesis gas refers to a combination of hydrogen and carbon oxides produced in a synthesis gas plant from a light hydrocarbon gas as previously described.
  • the reaction of synthesis gas to oxygenates such as methanol is exothermic, can be conducted in the gas phase or liquid phase, and is favored by low temperature and high pressure over a heterogeneous catalyst.
  • the methanol synthesis reactions employed on an industrial scale can be illustrated by the following equations:
  • the catalyst formulations employed typically include copper oxide (60-70%), zinc oxide (20-30%) and alumina (5-15%).
  • Chapter 3 of Methanol Production and Use edited by Wu-Hsun Cheng and Harold H. Kung, Marcel Dekker, Inc., New York, 1994, pages 51-73, provides a summary of conventional methanol production technology with respect to catalyst, reactors, typical yields operating conditions. The above reference is hereby incorporated by reference.
  • Methanol is generally produced in what is known as a "synthesis loop" which incorporates the generation of the synthesis gas.
  • synthesis gas may also be produced from coal gasification and partial oxidation
  • the primary route employed currently by industry is via the steam reforming of natural gas.
  • the steam reformer is essentially a large process furnace in which catalyst-filled tubes are heated externally by direct firing to provide the necessary heat for the following reaction, known as the water-gas shift reaction to take place:
  • n is the number of cafbon atoms per molecule of hydrocarbon.
  • oxygenates primarily methanol
  • the process steps can include: synthesis gas preparation, methanol synthesis, and if needed, methanol distillation.
  • the hydrocarbon gas feedstock is purified to remove sulfur and other potential catalyst poisons prior to being converted into synthesis gas.
  • the conversion to synthesis gas generally takes place at high temperatures over a nickel-containing catalyst to produce a synthesis gas containing a combination of hydrogen, carbon monoxide, and carbon dioxide.
  • the pressure at which synthesis gas is produced ranges from about 20 to about 75 bar and the temperature at which the synthesis gas exits the reformer ranges from about 700°C to 1100°C.
  • the synthesis gas is subsequently compressed to a methanol synthesis pressure as described below.
  • the compressed synthesis gas is converted to methanol, water, and minor amounts of by-products.
  • the synthesis gas preparation may take place in a single-step wherein all of the energy consuming reforming reactions are accomplished in a single tubular steam reformer.
  • the single-step reformer r&sults in a production of surplus hydrogen and a substantial heat surplus.
  • the synthesis gas preparation may take place in a two-step reforming process wherein the primary reforming in a tubular steam reformer is combined with an oxygen-fired secondary reforming step which produces a synthesis gas with a deficiency in hydrogen. With this combination it is possible to adjust the synthesis gas composition to the most suitable composition for methanol synthesis.
  • autothermal reforming wherein a stand-alone, oxygen-fired reformer produces synthesis gas havingi a hydrogen deficiency followed by the downstream removal of carbon dioxid e to restore the desired ratio of hydrogen to carbon oxide - can result in a simplified process scheme with lower capital cost.
  • low-pressure methanol synthesis is based on a copper oxide-zinc oxide-alumina catalyst that typically operates at a nominal pressure of 5-10 MPa (50-100 bar) and temperatures ranging from about 150°C (302°F) to about 450°C (842°F) over a variety of catalysts, including CuO/ZnO/AI 2 O 3 , CuO/ZnO/Cr 2 O 3 , ZnO/Cr 2 O 3 , Fe, Co, Ni, Ru, Os, Pt, and Pd. Catalysts based on ZnO for the production of methano l and dimethyl ether are preferred.
  • the low-pressure, copper-based methanol synthesis catalyst is commercially available from suppliers such as BASF, ICI Ltd. , and Haldor- Topsoe. Methanol yields from copper-based catalysts are genera lly over 99.5% of the combined CO+CO 2 present as methanol in the crude product stream. Water is a by-product of the conversion of the synthesis gas to oxygenates. Methanol and other oxygenates produced in the above manner are herein further referred to as an oxygenate feedstock.
  • a methanol production process comprising conversion of the natural gas to synthesis gas (H 2 and CO) and then conversion of the synthesis gas to methanol.
  • the non-combustible CO 2 gas separated from the raw natural gas prior to being fed to the LNG process is recovered and subsequently utilized in the production of methanol.
  • the CO 2 can be converted to methanol by any known synthesis method, such as those previously described.
  • CO 2 which would otherwise have been vented to atmosphere can be advantageously converted to higher value products, such as methanol and dimethyl ether.
  • FIG. 1 An embodiment of the invention derived from the process disclosed in U.S. Serial No. 10/805,943 is illustrated in Fig. 1. Separation of the CO 2 from the natural gas as produced from a reservoir is not shown on Fig. 1 for convenience, but may be done by any of a number of pre-treatment steps known to the art as mentioned hereinabove.
  • all or a portion of the CO 2 recovered from such pretreatment steps may be conveyed by lines 8 and 10 and then combined with a natural gas stream in line 4 to produce a blended feed stream which is conveyed by line 12 to a heater 20.
  • the blended feed stream is then conveyed by line 25 to a guard bed vessel 30 wherein any residual amount of sulfur-containing contaminants present in the blended feed stream may be removed by contact with an adsorbent bed, typically of zinc oxide.
  • the CO 2 stream conveyed by lines 8 and 10 and n atural gas stream conveyed by line 4 could be treated individually in such guard beds.
  • Pre-reformer reactor vessel 50 typically contains a nickel-based reforming catalyst, but may be any of a number of reforming catalysts as known in the art, and is designed to convert higher hydrocarbons which may be present in the blended feed stream and produce a predominately methane-containing feed stream.
  • Effluent from pre-reformer reactor vessel 50 is conveyed by line 55 to a heater 70 which heats the effluent to a temperature suitable for steam reforming of the methane-containing stream into synthesis gas, typically a temperature of from 400°C (T52°F) to 500°C (932°F).
  • a temperature suitable for steam reforming of the methane-containing stream into synthesis gas typically a temperature of from 400°C (T52°F) to 500°C (932°F).
  • the methane-containing stream is conveyed by line 75 to steam reformer vessel 80.
  • Steam reformer vessel 80 typically contains a nickel-containing steam reforming catalyst, but may be any of those known in the art, which converts the methane- containing stream into one rich in synthesis gas, i.e., hydrogen gas and carbon oxides.
  • the synthesis gas stream exiting steam reformer vessel 80 is conveyed by line 85 to a heat exchanger 90 where excess heat therein is recovered for other uses, such as in heaters 20 and 40.
  • the synthesis gas stream is then conveyed by line 95 to a cooler 100 wherein the temperature is further reduced.
  • the so-cooled synthesis gas stream is conveyed by line 105 to separator 110 wherein condensed water may be removed from the process by line 115.
  • the synthesis gas stream is thereafter conveyed by line 120 to synthesis gas compressor 130 which compresses the stream to a pressure suitable for methanol production, such as 35 to 150 bar.
  • the compressed synthesis gas stream is then conveyed by lines 135 and 140 to heat exchanger 150 wherein the temperature is adjusted to that suitable for methanol production, such as from 200°C (392°F) to 300°C (572°F).
  • Methanol synthesis reactor 160 After adjustment of temperature, the synthesis gas stream is conveyed by line 155 to methanol synthesis reactor 160.
  • Methanol synthesis reactor 160 generally utilizes a catalyst, such as a copper-zinc-alumina catalyst as mentioned above, but may be any of those known in the art.
  • Effluent from the methanol synthesis reactor 160 comprised primarily of methanol, water, and unreacted synthesis gas is conveyed by line 165 to heat exchanger 150 wherein excess heat is recovered therefrom, and thereafter the effluent is conveyed by line 170 to cooler 175. Thereafter, the effluent is conveyed by line 178 to separator 180 wherein a crude methanol product is recovered through line 210 and a gaseous stream exits by line 185.
  • a purge gas stream which may be used as fuel gas, is taken off via line 190 and the remainder of the gaseous stream comprised of unreacted synthesis gas is directed by line 195 to recycle compressor 200 which recompresses the gaseous stream to that suitable for methanol synthesis as previously described.
  • the compressed gaseous stream is directed by line 205 to line 135 and mixed with fresh synthesis gas.
  • the resulting crude methanol product from line 210 can then be purified by methods as known in the art, such as distillation, and then readily converted to olefins by known methods.
  • Molecular sieves such as the microporous crystalline zeolite and non- zeolitic catalysts, particularly silicoaluminophosphates (SAPO), are known to promote the conversion of oxygenates, such as methanol, to olefins and other hydrocarbon mixtures.
  • SAPO silicoaluminophosphates
  • the above-described oxygenate conversion process may also be generally conducted in the presence of one or more diluents which may be present in the oxygenate feed in an amount between about 1 and about 99 molar percent, based on the total number of moles of all feed and diluent components fed to the reaction zone (or catalyst).
  • Diluents include-but are not limited to- helium, argon, nitrogen, carbon monoxide, carbon dioxide, hydrogen, water, paraffins, hydrocarbons (such as methane and the like), aromatic compounds, or mixtures thereof.
  • Patents 4,861 ,938 and 4,677,242 particularly emphasize the use of a diluent combined with the feed to the reaction zone to maintain sufficient catalyst selectivity toward the production of light olefin products, particularly ethylene.
  • the foregoing U.S. Patents are incorporated herein by reference in their entirety.
  • Fig. 1 all or a portion of the crude methanol product can be conveyed via line 210 to olefin synthesis reactor 220, wherein the crude methanol (or oxygenate feedstock) is converted to light olefins as described above.
  • a portion of the crude methanol may be taken off via line 215 and purified by distillation or other unit operation (not shown).
  • the olefin-containing reaction product from olefin synthesis reactor 220 exits via line 225 and is conveyed to separator 230 wherein the olefins may be separated as desired, for example, into respective olefin product streams 234, 236, and 238. All or any portion of the respective olefin product streams may then be used as the synthetic hydrocarbon component in accordance with the present invention.
  • a by-product (water) stream exits separator 230 via line 232.
  • the light olefins obtained as described above may be hydrogenated by well-known methods and thereby converted into light paraffinic hydrocarbons. Such methods and catalysts therefor are described in U.S. Patent 4,075,251 , the teachings of which are incorporated herein by reference. Catalysts include various transition metal catalysts as mentioned in the foregoing U.S. Patent, and are commercially available. In general, olefins may be converted to paraffins by contact with the foregoing catalysts and hydrogen or hydrogen-containing gases at temperatures ranging from about 0°F (-17.8°C) to about 1000°F (537.8°C), more typically temperatures ranging from about 100°F (37.8°C) to about 500°F (260°C).
  • the reactions can be conducted at lower than atmospheric pressures or greater than atmospheric pressures, but generally pressures ranging from as low as about 1 atmosphere (1 bar) to about 500 atmospheres (506.6 bar), and specifically from about 1 atmosphere (1 bar) to about 50 atmospheres (50.7 bar) are suitable.
  • the catalysts and feedstock can be contacted as slurries or fixed beds, movable beds and fluidized beds, in liquid phase or vapor phase, in batch, continuous or staged operations.
  • the natural gas feed can also be converted into synthetic hydrocarbons, such as paraffins and olefins, via well-known Fischer- Tropsch technology as illustrated generally by US Patents 6,248,794; 6,774,148 and 6,743,962, the teachings of which are incorporated by reference herein in their entirety.
  • Fischer-Tropsch synthesis in general exothermically reacts synthesis gas, i.e., hydrogen and carbon monoxide, over either an iron or cobalt based catalyst to produce a range of synthetic hydrocarbon products.
  • synthesis gas i.e., hydrogen and carbon monoxide
  • the specific hydrocarbon product distribution depends strongly on both the catalyst and the reactor temperature. Generally, the higher the reactor temperature, the shorter the average hydrocarbon product chain length.
  • Reactor temperatures are generally in excess of 350°F (176.7°C), generally from about 350°F (176.7°C) to about 650°F (343.3°C), and more typically from about 400°F (204.4°C) to about 500°F (260°C).
  • the reaction pressure is generally maintained at between 200 psig (13.8 bar) and 600 psig (41.4 bar), and is typically from 300 psig (20.7 bar) and 500 psig (34.5 bar).
  • the Fischer-Tropsch reaction can be conducted in any of several known reaction devices such as, but not limited to, a slurry reactor, an ebullated bed reactor, a fluidized bed reactor, a circulating fluidized bed reactor, and a multi-tubular fixed bed reactor.
  • the Fischer-Tropsch reaction can generate significant amounts of light synthetic hydrocarbons, either paraffins or olefins, which are usually not as desirable in and of themselves, as such Fischer-Tropsch processes are typically directed toward making higher molecular weight materials, i.e., distillate fuels.
  • light synthetic hydrocarbons can be used as a synthetic hydrocarbon component ("synthetic LPG") in making the fuel compositions according to the present invention.
  • synthetic LPG synthetic hydrocarbon component
  • the synthetic hydrocarbon component can be derived from any other source or method known in the art. Direct methods for synthesis of hydrocarbons from methane are known and may also be utilized.
  • the natural gas component mixed therewith may be derived from LNG or simply comprise natural gas produced from a subterranean reservoir or formation with or without pretreatment to remove contaminants as described herein.
  • the synthetic hydrocarbon component may be blended into the feed stream to be liquefied in the LNG process at a point before the methane gas stream is cooled to about the freezing point of the highest boiling hydrocarbon present in the synthetic hydrocarbon component.
  • the synthetic hydrocarbon should be blended into the feed stream above this temperature so that a separate, solid phase of synthetic hydrocarbon is not formed in the natural gas feed stream.
  • Figs. 2a and 2b illustrate in simple terms the method of blending of synthetic hydrocarbon into natural gas during production of a LNG product in a natural gas liquefaction process according to the embodiment just mentioned.
  • the natural gas component may be a natural gas obtained by re-gasification of an LNG product, or it may be a natural gas obtained from another source, such as by production from a subterranean reservoir, with or without the one or more of the pre-treatment steps previously mentioned.
  • the synthetic hydrocarbon is to be blended with the LNG after re-gasification, then a larger amount of such contaminants can be tolerated so long as the contaminants do not inhibit the intended use of such blend, as in for example, use as a fuel composition.
  • the synthetic hydrocarbon has physical properties more like LPG, and thus it may be stored as a liquid under pressures similar to those used in connection with storage of LPG.
  • the synthetic hydrocarbon may be re-gasified, such as by reduction of pressure, and then mixed with the natural gas component.
  • the synthetic hydrocarbon may be directly injected and mixed with the re-gasified LNG.
  • the blending of the synthetic hydrocarbon can be generally accomplished without significant attention to keeping the synthetic hydrocarbon concentration relatively low.
  • mixtures having a relatively larger amount of synthetic hydrocarbon mixed with the natural gas component can be prepared by this embodiment.
  • it would only necessary to blend in enough synthetic hydrocarbon so that the ultimate, blended natural gas product has a higher heating value which meets a consumer's specification, as the synthetic hydrocarbon is a higher value component relative to the natural gas. Typical desired heating values are mentioned herein.
  • the upper limit for the amount of synthetic hydrocarbon added will be that which allows the resulting fuel blend to be maintained below the hydrocarbon dew point for the pressure and temperature at which the fuel blend is to be stored or conveyed, typically those conditions being specified for the pipeline in which the fuel blend is to be conveyed to market or the ultimate user thereof.
  • the customer specification can usually be attained by preferably blending in a minor amount of synthetic hydrocarbon, such as less than 25 mol% based on the total fuel composition, generally less than 20 mol%, and beneficially from 15 mol% to 10 mol% due to these considerations.
  • the synthetic hydrocarbon may be conveniently added at any temperature up to the applicable dew point of the natural gas component employed so that no liquids condense from the gas phase.
  • Mixing of the synthetic hydrocarbon and natural gas component in the gas phase according to this embodiment of the invention may be conducted in any process vessel, such as a pipe or tank.
  • Figs. 3a and 3b illustrate in simple terms the blending of synthetic hydrocarbon into a natural gas component derived from LNG in the vapor phase after re-gasification of the LNG at, for example, a re-gasification facility near a market site for such gas product.
  • Re-gasification methods for LNG are generally known in the art.
  • the synthetic hydrocarbon employed will be stored in a liquid state, which is also more convenient and economical for transport of the synthetic hydrocarbon composition to a market site, and then the synthetic hydrocarbon is re-gasified prior to or during blending with the re-gasified LNG.
  • Re-gasification methods for LNG can also be used to re-gasify the synthetic hydrocarbon.
  • such re-gasification methods can also be used to re-gasify a synthetic hydrocarbon/LNG blend which is in a liquid state according to the aspect of the invention previously mentioned.
  • a particular blended synthetic hydrocarbon/LNG liquid product in accordance with the present invention, generally comprises:
  • the resulting fuel blend preferably comprises:
  • a typical gross heating value for the fuel composition produced in accordance with the present invention generally ranges from about 1000 Btu/scf to about 1200 Btu/scf, and more typically from about 1030 Btu/scf to about 1170 Btu/scf, and particularly from about 1050 BTU/scf to about 1150 BTU/scf.
  • the present invention relates to alternative products and methods which may be used to provide more economical and convenient fuel compositions having improved heating values.

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Abstract

L'invention concerne des compositions comprenant des mélanges de gaz naturel et d'hydrocarbures légers synthétiques, tels que des paraffines C2 à C5, des oléfines et des mélanges de celles-ci, obtenus par des réactions de synthèse d'hydrocarbures, convenant à l'utilisation en tant que compositions combustibles. L'invention porte notamment sur des mélanges desdits hydrocarbures synthétiques légers et d'un gaz naturel dérivé du gaz naturel liquéfié produit dans un procédé de production de GNL. Lesdits mélanges peuvent également être obtenus par liquéfaction des hydrocarbures synthétiques légers avec du gaz naturel dans un procédé de production de GNL. Les hydrocarbures synthétiques légers sont ajoutés, par exemple, à un gaz naturel pauvre, de sorte que sa valeur thermique en soit améliorée. Dans certains modes de réalisation, les hydrocarbures synthétiques légers sont dérivés de manière appropriée, au moins en partie, de contaminant à faible teneur en CO2 susceptibles d'être présents dans un courant de gaz naturel brut, utilisé pour la préparation de GNL. L'invention porte également sur des procédés de préparation desdits mélanges.
PCT/US2005/008982 2004-03-22 2005-03-18 Compositions combustibles comprenant du gaz naturel et des hydrocarbures synthetiques, et leurs procedes de preparation WO2005093017A1 (fr)

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US10/805,943 US20040244279A1 (en) 2003-03-27 2004-03-22 Fuel compositions comprising natural gas and dimethyl ether and methods for preparation of the same
US10/935,976 US20050204625A1 (en) 2004-03-22 2004-09-08 Fuel compositions comprising natural gas and synthetic hydrocarbons and methods for preparation of same
US10/935,976 2004-09-08

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