Patent Application
20160187057
This invention relates generally to liquefied natural gas production from rich natural gas.
The combination of horizontal drilling and fracking has caused an oil boom across the United States. The horizontal drilling and fracking process co-produces natural gas. The co-produced gas is traditionally compressed and delivered via a pipeline. However, the pipeline infrastructure has failed to keep pace with shale oil drilling operations. Consequently, large quantities of co-produced gas are flared.
There are several known alternatives to flaring. First, lean natural gas—gas that has a small amount of propane and heavier hydrocarbons—can be used as a fuel for an internal combustion engine that, in turn, drives an electrical generator. The generated electricity can be used for local power or sold to the electrical grid. Second, natural gas can be compressed and sold as Compressed Natural Gas (CNG). Third, natural gas can be liquefied into Liquefied Natural Gas (LNG). Fourth, natural gas can be converted to liquid fuel including methanol. However, the associated gas produced from horizontal drilling and shale basins is rich gas, because the gas contains substantial amounts of heavier hydrocarbons including propane, butane, hexane, heptane and octane. The aforementioned hydrocarbons are known as Natural Gas Liquid (NGL). Rich gas is unsuitable for known flaring alternatives. The heavier hydrocarbons cause the gas energy content to be too high for internal combustion. Specifically, the high energy content causes internal combustion engines to knock. Consequently, rich natural gas is unsuitable for LNG production. The LNG-Pure process removes valuable NGL hydrocarbons for sale and distribution while concurrently producing a purified natural gas suitable for LNG, and is an economical alternative to a turboexpander plant.
Natural gas is compressed, and then cooled repeatedly until the desired pressure is achieved. Each cycle of compression and cooling is called a compression stage, and all of the compressor stages as a whole are known as a compressor train. Water and NGL can be removed from each stage of compression in a separator or removed at the final stage of compression in a single separator. The remaining residue gas contains too much ethane and other hydrocarbons for motor-fuel grade LNG. Ethane is particularly difficult to remove. A turboexpander plant is typically used to remove ethane. The process and system described herein purifies the residue gas into suitable LNG feedstock without the need for a costly turboexpander plant.
The residue gas is purified in two steps. First, the residue gas is passed through a molecular sieve bed to remove the remaining water to prevent ice and solid hydrate formation in the LNG processing equipment. Second, the dehydrated gas is delivered to a refluxed absorber where NGL is removed. The pressure of the absorber is approximately 500 to 600 psi, but can be below the critical pressure of methane. Condenser refrigeration may be integrated within the LNG coldbox, resulting in minimal additional refrigeration cost for the combined LNG-Pure and LNG liquefaction processes. Consequently, motor-fuel grade LNG can be produced from rich natural gas with only a small additional capital cost relative to the LNG liquefaction process. Concurrently, valuable NGL is recovered for a second revenue stream. Alternatively, cooling may be provided by an independent refrigeration system.
This drawing is provided to illustrate various aspects of the invention and is not intended to be limiting of the scope in terms of dimensions, materials, configurations, arrangements or proportions unless otherwise limited by the claims.
While these exemplary embodiments are described in sufficient detail to enable those skilled in the art to practice the invention, it should be understood that other embodiments may be realized and that various changes to the invention may be made without departing from the spirit and scope of the present invention. Thus, the following more detailed description of the embodiments of the present invention is not intended to limit the scope of the invention, as claimed, but is presented for purposes of illustration only and not limitation to describe the features and characteristics of the present invention, to set forth the best mode of operation of the invention, and to sufficiently enable one skilled in the art to practice the invention. Accordingly, the scope of the present invention is to be defined solely by the appended claims.
The terms and phrases as indicated in quotation marks (“ ”) in this section are intended to have the meaning ascribed to them in this Terminology section applied to them throughout this document, including in the claims, unless clearly indicated otherwise in context. Further, as applicable, the stated definitions are to apply, regardless of the word or phrase's case, to the singular and plural variations of the defined word or phrase.
The term “or” as used in this specification and the appended claims is not meant to be exclusive; rather the term is inclusive, meaning either or both.
References in the specification to “one embodiment”, “an embodiment”, “another embodiment, “a preferred embodiment”, “an alternative embodiment”, “one variation”, “a variation” and similar phrases mean that a particular feature, structure, or characteristic described in connection with the embodiment or variation, is included in at least an embodiment or variation of the invention. The phrase “in one embodiment”, “in one variation” or similar phrases, as used in various places in the specification, are not necessarily meant to refer to the same embodiment or the same variation.
The term “couple” or “coupled” as used in this specification and appended claims refers to an indirect or direct physical connection between the identified elements, components, or objects. Often the manner of the coupling will be related specifically to the manner in which the two coupled elements interact.
The term “separator” means a vessel capable of separating a gas phase from a liquid phase into dedicated outlets or a vessel capable of separating a gas phase, hydrocarbon phase and aqueous phase into dedicated outlets.
The term “NGL” means liquid composed predominantly of paraffinic hydrocarbon containing two to eight carbon atoms.
The term “LNG” means liquid composed predominantly of methane.
The term “coldbox” means a cryogenic heat exchanger or refrigerated condenser. Although a refrigerated unit can have a single coolant loop and a single cooled fluid loop, in some cases, the coldbox can include one or more of each fluid loop. For example, in one case, the coldbox can include two cooled fluid loops (e.g. item 6 in
The term “vent gas” means gas produced downstream of a Joule-Thompson or other pressure reducing cooling valve.
The term “fuel gas” means gas removed from the top of the stabilizer. Generally, the fuel gas can include methane and ethane.
Subsequent to dewatering, dry natural gas can generally have less than 0.05 vol % water, and in most cases less than about 0.1 vol % water. The dry natural gas 3 from molecular sieve bed 2 flows into the refluxed absorber 4. Natural gas and NGL flow, counter-currently through the refluxed absorber 4. Although other absorber configurations can be used, the refluxed absorber can often be multistage separation column containing random packing, structure packing or trays. In one example, the packed bed absorber can have from 5 to 10 theoretical stages. Advantageously, the refluxed absorber 4 also does not include a reboiler. Purified natural gas 5 flows from the top of refluxed absorber 4 into a section of LNG coldbox 6. The purified natural gas 5 can typically have a composition which is rich in methane, and can often have 3 to 10% ethane and 1 to 6% nitrogen. The LNG coldbox 6 can typically operate sufficient to partially liquefied stream 5. Typically this entails a temperature reduction to about −100 to −130° F. Typically a suitable refrigerant can be used to withdraw heat from the coldbox 6.
A liquid/vapor mixture 7 is withdrawn from the LNG coldbox 6, and the vapor and liquid are separated in overhead separator 9. The resulting liquid stream 10, comprising primarily methane, is refluxed to refluxed absorber 4. The liquid stream can generally have at least 75 mol % methane, and often more than 85 mol % methane, at a temperature between typically −100° F. and −130° F. and a pressure typically between 500 to about 650 psi. Purified natural gas 8 flows from the top of overhead separator 9 back into coldbox 6. The purified natural gas 8 can typically have from 70 to 95 vol % methane, and most often from 85 to 90 vol % methane. At this stage, the purified natural gas 8 can also have a temperature from −110 to −130° F. Additional cooling in coldbox 6 produces stream 11 to achieve a fully liquefied precursor to LNG. Stream 11 is cooled sufficiently to prevent large quantities of methane from evaporating when stream 11 is depressurized. Stream 11 can be cooled even further by Joule Thompson valve 22. Although operating parameters can vary, stream 19 can have a temperature from −250 to −270° F. Stream 19 from Joule Thompson valve 22 can also consist of a two-phase mixture of LNG and gas. The two-phase mixture 19 is separated in separator 20. Vent gas 21 is removed from the top of separator 20. Motor-fuel grade LNG 23 flows from the bottom of separator 20. Although actual product LNG compositions can vary based on feedstock and operating parameters, the motor-fuel grade LNG 23 can typically have 90 to 99 vol % methane, and often more than 93 vol % methane.
NGL 12 from refluxed absorber 4 is ethane rich, e.g. typically from 30 to 60 vol % ethane although other components such as propane and butane can also be present. The NGL 12 is fed to stabilizer 13 in order to remove a majority of the ethane. The stabilizer can generally be operated at 100 to 200 psi. The stabilizer can be a vapor/liquid mass transfer column with 5 to 10 theoretical stages. NGL 14 flows from the bottom of stabilizer 13 into reboiler 15. Reboiler 15 vaporizes part of the NGL 14. Typically the reboiler 15 can be operated such that the ethane in the NGL is controlled to a desired composition, typically 2 to 8 mole %. The gas 16 from reboiler 15 flows into stabilizer 13. The countercurrent flow of liquid and gas in stabilizer 13 purifies NGL 17 that flows from reboiler 14 to NGL storage tank 18. The purified NGL 17 can typically have a composition of mole percent ethane, 2 to 8 and most often 3 to 5 mole percent ethane. Fuel gas 14 flows out of the top of stabilizer 13. Although conditions can vary, fuel gas 14 can have 15 to 40 vol % and most often 20 to 30 vol % methane.
The various embodiments and variations thereof, illustrated in the accompanying FIGURES and/or described above, are merely exemplary and are not meant to limit the scope of the invention. It is to be appreciated that numerous other variations of the invention have been contemplated, as would be obvious to one of ordinary skill in the art, given the benefit of this disclosure. All variations of the invention that read upon appended claims are intended and contemplated to be within the scope of the invention.
For instance, for some embodiments, an independent refrigeration system may be used instead of the LNG coldbox 8. Similarly, the molecular sieve bed 2 can be any suitable water scavenger unit. Non-limiting examples of suitable water scavenging units can include water retention membranes, emulsive beds and the like. In another optional aspect, the Joule Thompson valve 22 can be any pressure reducing valve or mechanism which allows a reduction in pressure to form the two phase mixture.
This application claims priority to and incorporates by reference U.S. Provisional Patent Application No. 62/096,319, filed Dec. 23, 2014 and having the same inventor as the present application.
| Number | Date | Country | |
|---|---|---|---|
| 62096319 | Dec 2014 | US |
