Patent Application
20100031700
Natural gas is typically recovered from wells drilled into underground reservoirs. It usually has a major proportion of methane, i.e., methane comprises at least 50 mole percent of the gas. Depending on the particular underground reservoir, the natural gas also contains relatively lesser amounts of heavier hydrocarbons such as ethane, propane, butanes, pentanes and the like, as well as water, hydrogen, nitrogen, carbon dioxide, and other gases.
Most natural gas is handled in gaseous form. The most common means for transporting natural gas from the wellhead to gas processing plants and thence to the natural gas consumers is in high-pressure gas transmission pipelines. In a number of circumstances, however, it has been found necessary and/or desirable to liquefy the natural gas either for transport or for use. In remote locations, for instance, there is often no pipeline infrastructure that would allow for convenient transportation of the natural gas to market. In such cases, the much lower specific volume of LNG relative to natural gas in the gaseous state can greatly reduce transportation costs by allowing delivery of the LNG using cargo ships and transport trucks.
Another circumstance that favors the liquefaction of natural gas is for its use as a motor vehicle fuel. In large metropolitan areas, there are fleets of buses, taxi cabs, and trucks that could be powered by LNG if there were an economical source of LNG available. Such LNG-fueled vehicles produce considerably less air pollution due to the clean-burning nature of natural gas when compared to similar vehicles powered by gasoline and diesel engines (which combust higher molecular weight hydrocarbons). In addition, if the LNG is of high purity (i.e., with a methane purity of 95 mole percent or higher), the amount of carbon dioxide (a “greenhouse gas”) produced is considerably less due to the lower carbon:hydrogen ratio for methane compared to all other hydrocarbon fuels.
The present invention is generally concerned with the liquefaction of natural gas such as that found in high-pressure gas transmission pipelines. A typical analysis of a natural gas stream to be processed in accordance with this invention would be, in approximate mole percent, 89.4% methane, 5.2% ethane and other C2 components, 2.1% propane and other C3 components, 0.5% iso-butane, 0.7% normal butane, 0.6% pentanes plus, and 0.6% carbon dioxide, with the balance made up of nitrogen. Sulfur containing gases are also sometimes present.
There are a number of methods known for liquefying natural gas. For instance, see Finn, Adrian J., Grant L. Johnson, and Terry R. Tomlinson, “LNG Technology for Offshore and Mid-Scale Plants”, Proceedings of the Seventy-Ninth Annual Convention of the Gas Processors Association, pp. 429-450, Atlanta, Ga., Mar. 13-15, 2000 for a survey of a number of such processes. U.S. Pat. Nos. 5,363,655; 5,600,969; 5,615,561; 6,526,777; and 6,889,523 also describe relevant processes. These methods generally include steps in which the natural gas is purified (by removing water and troublesome compounds such as carbon dioxide and sulfur compounds), cooled, condensed, and expanded. Cooling and condensation of the natural gas can be accomplished in many different manners. “Cascade refrigeration” employs heat exchange of the natural gas with several refrigerants having successively lower boiling points, such as propane, ethane, and methane. As an alternative, this heat exchange can be accomplished using a single refrigerant by evaporating the refrigerant at several different pressure levels. “Multi-component refrigeration” employs heat exchange of the natural gas with a single refrigerant fluid composed of several refrigerant components in lieu of multiple single-component refrigerants. Expansion of the natural gas can be accomplished both isenthalpically (using Joule-Thomson expansion, for instance) and isentropically (using a work-expansion turbine, for instance).
While any of these methods could be employed to produce vehicular grade LNG, the capital and operating costs associated with these methods have generally made the installation of such facilities uneconomical. For instance, the purification steps required to remove water, carbon dioxide, sulfur compounds, etc. from the natural gas prior to liquefaction represent considerable capital and operating costs in such facilities, as do the drivers for the refrigeration cycles employed. This has led the inventors to investigate the feasibility of producing LNG from natural gas that has already been purified and is being transported to users via high-pressure gas transmission pipelines. Such an LNG production method would eliminate the need for separate gas purification facilities. Further, such high-pressure gas transmission pipelines are often convenient to metropolitan areas where vehicular grade LNG is in demand.
In accordance with the present invention, it has been found that LNG with methane purities in excess of 99 percent can be produced from natural gas, even when the natural gas contains significant concentrations of carbon dioxide. The present invention, although applicable at lower pressures and warmer temperatures, is particularly advantageous when processing feed gases in the range of 600 to 1500 psia [4,137 to 10,342 kPa(a)] or higher.
For a better understanding of the present invention, reference is made to the following examples and drawings. Referring to the drawings:
In the following explanation of the above figures, tables are provided summarizing flow rates calculated for representative process conditions. In the tables appearing herein, the values for flow rates (in moles per hour) have been rounded to the nearest whole number for convenience. The total stream rates shown in the tables include all non-hydrocarbon components and hence are generally larger than the sum of the stream flow rates for the hydrocarbon components. Temperatures indicated are approximate values rounded to the nearest degree. It should also be noted that the process design calculations performed for the purpose of comparing the processes depicted in the figures are based on the assumption of no heat leak from (or to) the surroundings to (or from) the process. The quality of commercially available insulating materials makes this a very reasonable assumption and one that is typically made by those skilled in the art.
For convenience, process parameters are reported in both the traditional British units and in the units of the Système International d'Unités (SI). The molar flow rates given in the tables may be interpreted as either pound moles per hour or kilogram moles per hour. The energy consumptions reported as horsepower (HP) and/or thousand British Thermal Units per hour (MBTU/Hr) correspond to the stated molar flow rates in pound moles per hour. The energy consumptions reported as kilowatts (kW) correspond to the stated molar flow rates in kilogram moles per hour. The LNG production rates reported as gallons per day (gallons/D) and/or pounds per hour (Lbs/hour) correspond to the stated molar flow rates in pound moles per hour. The LNG production rates reported as cubic meters per hour (m3/H) and/or kilograms per hour (kg/H) correspond to the stated molar flow rates in kilogram moles per hour.
In the simulation of the
Vapor stream 33 from separator 11 enters a work expansion machine 13 in which mechanical energy is extracted from this portion of the high pressure feed. The machine 13 expands the vapor substantially isentropically to slightly above the operating pressure of LNG purification tower 17, 435 psia [2,999 kPa(a)], with the work expansion cooling the expanded stream 33a to a temperature of approximately −108° F. [−78° C.]. The typical commercially available expanders are capable of recovering on the order of 80-85% of the work theoretically available in an ideal isentropic expansion. The work recovered is often used to drive a centrifugal compressor (such as item 14), that can be used to compress gases or vapors, like stream 35b for example. The expanded and partially condensed stream 33a is divided into two portions, streams 35 and 36.
Stream 36, containing about 35% of the effluent from expansion machine 13, is further cooled in heat exchanger 18 by heat exchange with cold LNG flash vapor at −153° F. [−103° C.] (stream 43b) and cold flash vapor and liquid at −153° F. [−103° C.] (stream 45). The further cooled stream 36a at −140° F. [−96° C.] is thereafter supplied to distillation column 17 at a mid-column feed point. The second portion, stream 35, containing the remaining effluent from expansion machine 13, is directed to heat exchanger 15 where it is warmed to −57° F. [−49° C.] as it further cools the remaining portion (stream 31) of the cooled stream 30a. The further cooled stream 31a at −82° F. [−64° C.] is then flash expanded through an appropriate expansion device, such as expansion valve 16, to the operating pressure of fractionation tower 17, whereupon the expanded stream 31b at −126° F. [−88° C.] is directed to fractionation tower 17 at a lower column feed point.
Distillation column 17 serves as an LNG purification tower. It is a conventional distillation column containing a plurality of vertically spaced trays, one or more packed beds, or some combination of trays and packing. This tower recovers nearly all of the hydrocarbons heavier than methane present in its feed streams (streams 36a and 31b) as its bottom product (stream 38) so that the only significant impurity in its overhead (stream 37) is the nitrogen contained in the feed streams. Equally important, this tower also captures in its bottom product nearly all of the carbon dioxide feeding the tower, so that carbon dioxide does not enter the downstream LNG cool-down section where the extremely low temperatures would cause the formation of solid carbon dioxide, creating operating problems. Stripping vapors for the lower section of LNG purification tower 17 are provided by the vapor portion of stream 31b, which strips some of the methane from the liquids flowing down the column.
Reflux for distillation column 17 is created by cooling and condensing the tower overhead vapor (stream 37 at −143° F. [−97° C.]) in heat exchanger 18 by heat exchange with streams 43b and 45 as described previously. The condensed stream 37a, now at −148° F. [−100° C.], is divided into two portions. One portion (stream 40) becomes the feed to the LNG cool-down section. The other portion (stream 39) enters reflux pump 19. After pumping, stream 39a at −148° F. [−100° C.] is supplied to LNG purification tower 17 at a top feed point to provide the reflux liquid for the tower. This reflux liquid rectifies the vapors rising up the tower so that the tower overhead vapor (stream 37) and consequently feed stream 40 to the LNG cool-down section contain minimal amounts of carbon dioxide and hydrocarbons heavier than methane.
The feed stream for the LNG cool-down section (condensed liquid stream 40) enters heat exchanger 51 at −148° F. [−100° C.] and is subcooled by heat exchange with cold LNG flash vapor at −169° F. [−112° C.] (stream 43a) and cold flash vapor at −164° F. [−109° C.] (stream 41). Subcooled stream 40a −150° F. [−101° C.] from heat exchanger 51 is flash expanded through an appropriate expansion device, such as expansion valve 52, to a pressure of approximately 304 psia [2,096 kPa(a)]. During expansion a portion of the stream is vaporized, resulting in cooling of the total stream to −164° F. [−109° C.] (stream 40b). The flash expanded stream 40b enters separator 53 where the flash vapor (stream 41) is separated from the liquid (stream 42). The flash vapor (first flash vapor stream 41) is heated to −153° F. [−103° C.] (stream 41a) in heat exchanger 51 as described previously.
Liquid stream 42 from separator 53 is subcooled in heat exchanger 54 to −168° F. [−111° C.] (stream 42a). Subcooled stream 42a is flash expanded through an appropriate expansion device, such as expansion valve 55, to the LNG storage pressure (90 psia [621 kPa(a)]). During expansion a portion of the stream is vaporized, resulting in cooling of the total stream to −211° F. [−135° C.] (stream 42b), whereupon it is then directed to LNG storage tank 56 where the LNG flash vapor resulting from expansion (stream 43) is separated from the LNG product (stream 44). The LNG flash vapor (second flash vapor stream 43) is then heated to −169° F. [−112° C.] (stream 43a) as it subcools stream 42 in heat exchanger 54. Cold LNG flash vapor stream 43a is thereafter heated in heat exchangers 51, 18, and 10 as described previously, whereupon stream 43d at 95° F. [35° C.] can then be used as part of the fuel gas for the plant.
Tower bottoms stream 38 from LNG purification tower 17 is flash expanded to the pressure of cold flash vapor stream 41a by expansion valve 20. During expansion a portion of the stream is vaporized, resulting in cooling of the total stream from −133° F. [−92° C.] to −152° F. [−102° C.] (stream 38a). The flash expanded stream 38a is then combined with cold flash vapor stream 41a leaving heat exchanger 51 to form a combined flash vapor and liquid stream (stream 45) at −153° F. [−103° C.] which is supplied to heat exchanger 18. It is heated to −119° F. [−84° C.] (stream 45a) as it supplies cooling to expanded stream 36 and tower overhead vapor stream 37 as described previously.
The liquid (stream 34) from separator 11 is flash expanded to the pressure of stream 45a by expansion valve 12, cooling stream 34a to −102° F. [−74° C.]. The expanded stream 34a is combined with heated flash vapor and liquid stream 45a to form cool flash vapor and liquid stream 46, which is heated to 94° F. [35° C.] in heat exchanger 10 as described previously. The heated stream 46a is then re-compressed in two stages, compressor 23 and compressor 25 driven by supplemental power sources, with cooling to 120° F. [49° C.] between stages supplied by cooler 24, to form the compressed first residue gas (stream 46d).
The heated expanded vapor (stream 35b) at 95° F. [35° C.] from heat exchanger 10 is the second residue gas. It is re-compressed in two stages, compressor 14 driven by expansion machine 13 and compressor 22 driven by a supplemental power source, with cooling to 120° F. [49° C.] between stages supplied by cooler 21. The compressed second residue gas (stream 35e) combines with the compressed first residue gas (stream 46d) to form residue gas stream 47. After cooling to 120° F. [49° C.] in discharge cooler 26, the residue gas product (stream 47a) returns to the natural gas transmission pipeline at 900 psia [6,205 kPa(a)].
A summary of stream flow rates and energy consumption for the process illustrated in
The total compression power for the
In addition, the present invention produces LNG of higher purity than most prior art processes due to the inclusion of LNG purification tower 17. The purity of the LNG is in fact limited only by the concentration of gases more volatile than methane (nitrogen, for instance) present in feed stream 30, as the operating parameters of LNG purification tower 17 can be adjusted as needed to keep the concentration of heavier hydrocarbons in the LNG product as low as desired.
Some circumstances may favor splitting the feed stream prior to cooling in heat exchanger 10. Such an embodiment of the present invention is shown in
In accordance with this invention, external refrigeration may be employed to supplement the cooling available to the feed gas from other process streams, particularly in the case of a feed gas richer than that described earlier. The particular arrangement of heat exchangers for feed gas cooling must be evaluated for each particular application, as well as the choice of process streams for specific heat exchange services.
It will also be recognized that the relative amount of the feed stream 30 that is directed to the LNG cool-down section (stream 40) will depend on several factors, including feed gas pressure, feed gas composition, the amount of heat which can economically be extracted from the feed, and the quantity of horsepower available. More feed to the LNG cool-down section may increase LNG production while decreasing the purity of the LNG (stream 44) because of the corresponding decrease in reflux (stream 39) to LNG purification tower 17.
Subcooling of liquid stream 42 in heat exchanger 54 reduces the quantity of LNG flash vapor (stream 43) generated during expansion of the stream to the operating pressure of LNG storage tank 56. This generally reduces the specific power consumption for producing the LNG by keeping the flow rate of stream 43 low enough that it can be consumed as part of the plant fuel gas, eliminating any power consumption for compression of the LNG flash gas. However, some circumstances may favor elimination of heat exchanger 54 (shown dashed in
In
Although individual stream expansion is depicted in particular expansion devices, alternative expansion means may be employed where appropriate. For example, conditions may warrant work expansion of the further cooled portion of the feed stream (stream 31a in
While there have been described what are believed to be preferred embodiments of the invention, those skilled in the art will recognize that other and further modifications may be made thereto, e.g. to adapt the invention to various conditions, types of feed, or other requirements without departing from the spirit of the present invention as defined by the following claims.
This invention relates to a process and apparatus for processing natural gas to produce liquefied natural gas (LNG) that has a high methane purity. In particular, this invention is well suited to production of LNG from natural gas found in high-pressure gas transmission pipelines. The applicants claim the benefits under Title 35, United States Code, Section 119(e) of prior U.S. Provisional Application No. 61/086,702 which was filed on Aug. 6, 2008.
| Number | Date | Country | |
|---|---|---|---|
| 61086702 | Aug 2008 | US |
