US20050204625A1

US20050204625A1 - Fuel compositions comprising natural gas and synthetic hydrocarbons and methods for preparation of same

Info

Publication number: US20050204625A1
Application number: US10/935,976
Authority: US
Inventors: Michael Briscoe; Theo Fleisch
Original assignee: BP Corp North America Inc
Current assignee: BP Corp North America Inc
Priority date: 2004-03-22
Filing date: 2004-09-08
Publication date: 2005-09-22
Also published as: WO2005093017A1

Abstract

The invention is directed to compositions comprising mixtures of natural gas and synthetic light hydrocarbons, such as C₂to C₅paraffins, olefins and mixtures thereof, obtained via a hydrocarbon synthesis reactions, which are suitable for use as fuel compositions, and particularly to blends of such synthetic light hydrocarbons and a natural gas derived from LNG produced in an LNG process. Alternatively, such blends may also be obtained by liquefaction of the synthetic light hydrocarbons with natural gas in an LNG process. The synthetic light hydrocarbons are added, for example, to a lean natural gas to improve the heat value thereof. In embodiments, the synthetic light hydrocarbons are conveniently derived, at least in part, from low value CO₂contaminant that may be present in a raw natural gas stream used to prepare LNG. Also disclosed are methods to prepare the mixtures.

Description

CROSS REFERENCE TO RELATED APPLICATION

This application claims benefit and is a continuation-in-part of co-pending U.S. patent application Ser. No. 10/805,943, filed Mar. 22, 2004, the teachings of which are incorporated herein by reference in their entirety.

FIELD OF THE INVENTION

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.

BACKGROUND OF THE INVENTION

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. Often, however, 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.
It is also commercially important to cryogenically liquefy natural gas so as to produce LNG for more convenient storage and transport. A fundamental reason for the liquefaction of natural gas is that liquefaction results in a volume reduction of about 1/600, thereby making it possible to store and transport the liquefied gas in containers at low or even atmospheric pressure. Liquefaction of natural gas is of even greater importance in enabling the transport of gas from a supply source to market where the source and market are separated by great distances and pipeline transport is not practical or economically feasible.
In order to store and transport natural gas in the liquid state, 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. For example, processes for preparation of LNG generally are disclosed in U.S. Pat. Nos. 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 C₂-C₅hydrocarbons. Further, 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. As a result, when such lean natural gas is used as a feed to produce LNG, 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.
Historically, to meet the market demand in some markets where increased LNG heating value is desired, 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”. The amount of LPG blended therein is that sufficient to meet the market specification. 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.
As can be seen, it would be desirable to develop alternatives so as to improve the heat value of natural gas and in particular, to utilize lean natural gas sources and increase the heat value of LNG produced therefrom without relying on expensive transport of LPG materials. Such alternatives could make such natural gas supplies a more economical and commercially attractive energy resource from the perspective of both LNG producers and consumers.

SUMMARY OF THE INVENTION

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.
In another aspect, the invention 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.
In embodiments, 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. In further embodiments of the foregoing, 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.

Where the synthetic hydrocarbon component and natural gas component are mixed in the vapor phase, 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. Typically, 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.
In the above-described embodiments of the method, it 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.
In other embodiments where the synthetic hydrocarbon is mixed with a natural gas component in a LNG process, 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° C.) 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.

Where the synthetic hydrocarbon component is mixed with the natural gas feed in a LNG process, 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.
In another aspect, 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.
  In the above-described embodiment, it 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 or the LNG product is produced, and more particularly, at a location near the market for the fuel blend.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic process flow sheet illustrating a process for preparing methanol with a feed that includes all or a portion of CO₂contaminant 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.
FIGS. 2 a and 2 b 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. 2 a, which may also produce liquid products, such as naphtha, diesel, and lube blending stocks. Alternatively, as illustrated by FIG. 2 b, 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.
FIGS. 3 a and 3 b 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. 3 a. Alternatively, as illustrated by FIG. 3 b, 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.

DETAILED DESCRIPTION OF THE INVENTION

As mentioned above, 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 thereof, which can be used as a fuel gas. Advantageously it is a lean virgin natural gas with a relatively low heating value, such as less than 1000 BTU/scf. As used herein, 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. In embodiments, the synthetic hydrocarbon component comprises a blend of C₂to C₅synthetic 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, as mentioned briefly hereinabove, 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.
The presence of an excessive amount of heavier virgin hydrocarbons such as ethane, propane, butane, pentane, and hydrocarbons boiling at a boiling point above pentane, which may be present in some natural gas feeds can optionally be reduced through gas-liquid separation steps, particularly in the event such hydrocarbons have greater value for use outside the production of a fuel composition, LNG or synthetic hydrocarbons as mentioned below. 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.
For most markets, it is also desirable to minimize the presence of non-combustibles and contaminants in the LNG or fuel gas, such as carbon dioxide, helium and nitrogen and hydrogen sulfide. Depending on the quality of a given natural gas reservoir (which may contain as much as 50% to 70% carbon dioxide), 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. Typically, as mentioned above, there are many natural gas reservoirs that contain significant amounts of non-combustible CO₂gas therein. At present, commercial scale LNG plants use processes which generally—require nearly complete removal of acid gases, including CO₂, from the feed gas to the LNG process. In the past, the CO₂extracted from the feed gas has been simply vented to the atmosphere. However, current concerns over global warming, internationally driven initiatives to reduce greenhouse emissions, and other environmental factors make venting of such CO₂undesirable. As mentioned below, the CO₂removed 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 LNG production or hydrocarbon synthesis, including, but not limited to, removal of acid gases (such as H₂S and CO₂), mercaptans, 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-liquid 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 CO₂content of less than 0.1 mole percent, and more preferably less than 0.01 mole percent, based on the total natural gas feed.
In accordance with some embodiments of the invention, it is desirable to prepare a CO₂rich stream for use in the manufacture of methanol and light synthetic hydrocarbons, wherein the CO₂rich stream has minimal amounts of contaminants, such as H₂S, mercaptans, and other sulfur-containing compounds.
As known in the art, an inhibited amine solution can be used to selectively remove the CO₂in the natural gas stream, but not H₂S. The H₂S can then be removed in a subsequent step. Also, it is desirable to employ a guard bed (such as a ZnO guard bed) for removal of any remaining, residual sulfur-containing compounds that may be present in the CO₂rich stream prior to feeding the stream to points within a hydrocarbon synthesis process, such as upstream of a pre-reforming reactor or reforming reactor. Such reactors typically employ nickel catalysts which can be susceptible to poisoning by sulfur-containing compounds, such as H₂S.
In some embodiments, 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.
In general, where the natural gas component is derived from LNG, the LNG may be prepared according to any known LNG process as previously described. For example, processes for preparation of LNG generally are disclosed in U.S. Pat. Nos. 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. Pat. No. 6,743,829, and further U.S. patent application Ser. No. 10/805,943, filed Mar. 22, 2004 discloses an integrated process wherein CO₂present in natural gas feedstreams for preparation of LNG is recovered for use in making methanol and methanol derivatives, such as dimethyl ether. The teachings of the foregoing patent and patent application are incorporated herein by reference in their entirety.
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:
CO+2H₂⇄CH₃OH
or
CO₂₊₃H₂⇄CH₃OH+H₂O
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. Although 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:
C_nH_2n+2 +nH₂O⇄nCO+(2n+1)H₂
wherein n is the number of carbon atoms per molecule of hydrocarbon.
Generally, the production of oxygenates, primarily methanol, takes place as a combination of process steps. The process steps can include: synthesis gas preparation, methanol synthesis, and if needed, methanol distillation.
In the synthesis gas preparation step, 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. Typically, 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 contains a stoichiometric molar ratio of hydrogen to carbon oxide, generally expressed as follows:
S_n=[H₂—CO₂]/[CO+CO₂]
which is generally from 2 to 3 and more typically from about 2.0 to 2.3. The synthesis gas is subsequently compressed to a methanol synthesis pressure as described below. In the methanol synthesis step, 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 results in a production of surplus hydrogen and a substantial heat surplus. In another preferred alternative, 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. As an alternative, autothermal reforming—wherein a stand-alone, oxygen-fired reformer produces synthesis gas having a hydrogen deficiency followed by the downstream removal of carbon dioxide to restore the desired ratio of hydrogen to carbon oxide—can result in a simplified process scheme with lower capital cost.
As disclosed in U.S. Pat. No. 3,326,956, 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/Al₂O₃, CuO/ZnO/Cr₂O₃, ZnO/Cr₂O₃, Fe, Co, Ni, Ru, Os, Pt, and Pd. Catalysts based on ZnO for the production of methanol 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 generally over 99.5% of the combined CO+CO₂present 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.
U.S. patent application Ser. No. 10/805,943 filed on Mar. 22, 2004, previously incorporated herein by reference, discloses a process for integration of LNG processes with other processes to prepare liquid products from natural gas, such as a methanol production process comprising conversion of the natural gas to synthesis gas (H₂and CO) and then conversion of the synthesis gas to methanol. In the disclosed process, the non-combustible CO₂gas 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 CO₂can be converted to methanol by any known synthesis method, such as those previously described. As a result, CO₂which would otherwise have been vented to atmosphere can be advantageously converted to higher value products, such as methanol and dimethyl ether.
An embodiment of the invention derived from the process disclosed in U.S. Ser. No. 10/805,943 is illustrated in FIG. 1. Separation of the CO₂from 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.
As shown in FIG. 1, all or a portion of the CO₂recovered from such pre-treatment 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. After being heated in 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. Alternatively, the CO₂stream conveyed by lines 8 and 10 and natural gas stream conveyed by line 4 could be treated individually in such guard beds.
After treatment in the guard bed 30, steam is added to the blended feed stream via line 38. The blended feed stream is then conveyed by line 35 to heater 40 wherein the temperature thereof is further adjusted to from 300° C. (572° F.) to 450° C. (842° F.) prior to introducing the blended feed stream via line 45 to pre-reformer reactor vessel 50. 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. (752° F.) to 500° C. (932° F.). In the event that the CO₂feed in line 8 is substantially free of sulfur-containing compounds, such as less than 1 ppm, it is possible to add CO₂to the process at the location identified as 60 on FIG. 1, by conveying all or part of the CO₂to this location via line 58.
After being heated to a temperature suitable for steam reformation, 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.).
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 exchan ger 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. Numerous patents describe this type of process which also employ various types of catalysts, see, e.g., U.S. Pat. Nos. 3,928,483; 4,025,575; 4,252,479; 4,496,786; 4,547,616; 4,677,243; 4,843,183; 4,499,314; 4,447,669; 5,095,163; 5,126,308; 4,973,792; and 4,861,938, the teachings of which are incorporated herein by reference. Such processes are referred to in the art as “MTO” (methanol-to-olefin) type processes, which typically result in conversion of light oxygenates, such as methanol, to light olefins.
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. U.S. Pat. Nos. 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.
In 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.
If desired, 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. Pat. No. 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.
In addition to oxygenates, 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 U.S. Pat. Nos. 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. 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. However, such light synthetic hydrocarbons can be used as a synthetic hydrocarbon component (“synthetic LPG”) in making the fuel compositions according to the present invention.
While the foregoing has been described somewhat in detail, it should be understood that 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.
In accordance with the foregoing embodiment of the present invention, during production of LNG in a natural gas liquefaction process as previously mentioned, 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. Also, in this embodiment, it is important to maintain the synthetic hydrocarbon content within the feed stream being liquefied below a saturation point so that the synthetic hydrocarbon does not solidify and create a separate solid phase. Generally, this concentration is about 25 mole % based on total amount of blended liquid product.
FIGS. 2 a and 2 b 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.
Mixing of the synthetic hydrocarbon and LNG product in the liquid phase after production of the LNG is not as desirable, due to the limited solubility of the synthetic hydrocarbon therein, and also greater tendency of the synthetic hydrocarbon to form an undesirable solid phase.
It is generally more favorable and convenient to mix the synthetic hydrocarbon into a natural gas component in the vapor phase. In this case, 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. If 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. Also, 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. Just prior to use, the synthetic hydrocarbon may be re-gasified, such as by reduction of pressure, and then mixed with the natural gas component. Alternatively, the synthetic hydrocarbon may be directly injected and mixed with the re-gasified LNG.
In accordance with the foregoing embodiment of the invention wherein synthetic hydrocarbon is mixed with a natural gas component in the gas phase, the blending of the synthetic hydrocarbon can be generally accomplished without significant attention to keeping the synthetic hydrocarbon concentration relatively low. As such, mixtures having a relatively larger amount of synthetic hydrocarbon mixed with the natural gas component can be prepared by this embodiment. Typically, in commercial practice and as a preferred embodiment of the invention, 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.
More importantly, 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. As such, 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. In this embodiment, 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. 3 a and 3 b 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. Preferably, 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. Further, 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:

- less than 2 mole percent nitrogen and preferably less than 1 mole percent nitrogen;
- less than 1 mole percent and preferably less than 0.5 mole percent helium;
- less than 3 mole percent and preferably less than 1.5 mole percent of the total of nitrogen and helium; and
- less than 25 mole percent of synthetic hydrocarbon within the blended liquid product.

Where the synthetic hydrocarbon is blended into a regasified LNG product, according to one aspect of the invention, the resulting fuel blend preferably comprises:

- less than 0.3 mole percent nitrogen and preferably less than 0.2 mole percent nitrogen;
- less than 0.2 mole percent and preferably less than 0.1 mole percent helium;
- less than 0.5 mole percent and preferably less than 0.2 mole percent of the total of nitrogen and helium; and
- less than 25 mol % synthetic hydrocarbon, based on the total fuel blend, typically less than 20 mol %, and beneficially from 10 to 15 mol % synthetic hydrocarbon based on the total fuel blend.

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.
As can be seen, 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.
Other embodiments and benefits of the invention will be apparent to those skilled in the art from a consideration of this specification or from practice of the invention disclosed herein. It is intended that this specification be considered as exemplary only with the true scope and spirit of the invention being indicated by the following claims.

Claims

1. A composition comprising a virgin natural gas component and a synthetic hydrocarbon component comprised of light hydrocarbons.

2. The composition of claim 1 wherein the virgin natural gas component is a lean natural gas.

3. The composition of claim 2 wherein the lean natural gas employed comprises less than about 3 mol % of C₂to C₅virgin light hydrocarbons, with the balance of the lean natural gas being essentially methane, based on the composition of the lean natural gas.

4. The composition of claim 1 wherein the synthetic hydrocarbon component is present in an amount of less than 25 mol % based on the total composition.

5. The composition of claim 1 wherein the natural gas component is derived from a regasified LNG product produced in an LNG process.

6. The composition of claim 1 having a heating value of from about 1000 BTU/scf to about 1200 BTU/scf.

7. The composition of claim 1 wherein the synthetic hydrocarbon component comprises C₂to C₅hydrocarbons selected from paraffins, olefins, and mixtures thereof.

8. The composition of claim 7 wherein the synthetic hydrocarbon component is derived from a Fischer-Tropsch process.

9. The composition of claim 7 wherein the synthetic hydrocarbon component is derived from an MTO process.

10. A method for preparing a fuel blend comprising mixing a virgin natural gas component and a synthetic hydrocarbon component comprised of light synthetic hydrocarbons.

11. The method of claim 10 wherein the virgin natural gas component is derived from a regasified LNG product prepared in a LNG process.

12. The method of claim 11 further comprising:

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 the LNG process to liquefy at least a portion of the natural gas component and thereby produce a LNG product; and

re-gasifying the LNG product to obtain the natural gas component.

13. The method of claim 12 further comprising:

providing the synthetic hydrocarbon component; and

mixing the synthetic hydrocarbon component with the virgin natural gas component to obtain the fuel blend.

14. The method of claim 13 wherein mixing of the virgin natural gas component and the synthetic hydrocarbon component occurs at a site remote from the location where the virgin natural gas component originates.

15. The method of claim 11 wherein the synthetic hydrocarbon component is blended in an amount such that the concentration of the synthetic hydrocarbon component in the fuel blend is less than 25 mol % based on the total fuel blend.

16. The method of claim 11 wherein the fuel blend has a heating value of from about 1000 BTU/scf to about 1200 BTU/scf.

17. The method of claim 10 further comprising:

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 a LNG process;

mixing the synthetic hydrocarbon component into the natural gas feed within a LNG process at a temperature and in an amount such that the synthetic hydrocarbon does not solidify and form a separate solid phase during liquefaction of the natural gas feed in the LNG process; and

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° C.) 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.

18. The method of claim 17 wherein the fuel blend comprises the synthetic hydrocarbon component in an amount of 25 mole % or less based on the total fuel blend.

19. A method for preparing a fuel blend comprising virgin natural gas and synthetic hydrocarbons, the method comprising:

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 a synthetic hydrocarbon component;

re-gasifying the LNG product to obtain a virgin natural gas component; and