Patent Application
20110174017
The present invention relates to an improved process for cryogenic separation of natural gas. More particularly, the present invention relates to an improved process for cryogenically removing helium and natural gas liquids (NGLs) from natural gas to produce a product stream enriched in helium, a liquid product stream enriched in NGLs, and a gaseous product stream enriched in methane.
This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present invention. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present invention. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Because of its clean burning qualities and convenience, natural gas has become widely used in recent years. The composition of natural gas can vary significantly. As used in this disclosure, a natural gas stream contains methane (C1 as a major component. The natural gas will typically contain contaminants such as water, carbon dioxide, hydrogen sulfide, dirt, and iron sulfide; hydrocarbons such as ethane (C2), propane (C3), and higher hydrocarbons; and diluent gases such as nitrogen and helium.
In order to produce natural gas of a purity suitable for commercial use, a natural gas stream from a gas-bearing reservoir may have to be separated to enrich the methane content of the gas stream.
Natural gas is often treated to remove impurities such as carbon dioxide, water, and non-hydrocarbon acid gases. Natural gas is often further processed to separate and recover natural gas liquids (NGLs), which may include hydrocarbons such as ethane, propane, butanes, pentanes, and sometimes higher molecular weight components. NGLs are valuable as raw materials for preparing various petrochemicals. NGL is sometimes referred to as C2+.
Various distillation methods have been considered for recovering NGL components from natural gas. The NGL is typically separated from methane and more volatile components such as nitrogen and helium in one or more distillation towers. The towers are often referred to as demethanizer or deethanizer columns. Processes employing a demethanizer column separate methane and other volatile components from ethane and heavier components. The methane fraction is typically recovered as purified gas (containing small amounts of inerts such as nitrogen, CO2, etc.) for pipeline delivery. NGLs are recovered as much as practical from the feed gas.
One NGL recovery process is known as the Gas Subcooled Process (“GSP”), which is disclosed in U.S. Pat. Nos. 4,140,504; 4,157,904; and 4,278,457. In the GSP process, a portion of a natural gas feed stream is condensed and subcooled, flashed down to the demethanizer operating pressure, and supplied to the demethanizer as its top feed for reflux. The remainder of the feed gas is also expanded to lower pressure (typically using a turboexpander for vapor streams) and fed to the demethanizer at one or more intermediate feed points. Another process, known as the Recycle Split-vapor Process (“RSV”), which is disclosed in U.S. Pat. No. 5,568,737, is a residue gas recycle process in which the overhead gas (residue gas) of a demethanizer (or a deethanizer) is compressed and cooled, and is depressurized to make a low-temperature liquid, and then the liquid is supplied as a reflux to the demethanizer (or the deethanizer).
Helium is another component of natural gas in certain natural gas fields, typically present in small concentrations. The presents of helium in the natural gas reduces the heating value of the natural gas. Also, helium may have independent commercial uses if it can be economically separated from the natural gas. Consequently, the separation of helium from natural gas may have a twofold economic benefit, namely, enhancement of the natural gas heating value and production of a marketable gas such as helium.
Numerous processes are known in the art for the cryogenic separation of helium from a natural gas stream. Among these cryogenic processes are the multi-stage flash cycle process and the high pressure distillation process. The cryogenic processes typically subject the helium-bearing natural gas to successively lower temperatures to condense and thereby remove from the natural gas those components therein having boiling points higher than that of helium. These components generally include, in descending order of their boiling points, hydrocarbons heavier than methane, methane itself, and nitrogen.
In the flash cycle, which is disclosed for example in U.S. Pat. No. 3,260,058, feed gas is partially liquefied and phase separated. Dissolved helium in the liquid portion is recovered by several subsequent flash steps in which small amounts of helium-rich vapor are flashed off and eventually added to the bulk helium-rich stream.
In the distillation (high pressure stripping) process, feed gas is at least partially liquefied and fed to a distillation step in which dissolved helium is stripped from the liquid at feed pressure. The high pressure distillation process has the advantage of higher helium content in the helium-enriched stream than the flash cycle. In addition, since the helium-enriched stream is produced at feed pressure, the product streams from the subsequent processing steps can be returned at higher pressure, thereby reducing energy consumption for the crude helium stream recompression.
Processes have been proposed for integrating the recovery of helium with NGL recovery. See, for example, SPE paper number 24292, entitled “Process Requirements and Enhanced Economics of Helium Recovery From Natural Gas”, presented at the SPE Mid-Continent Gas Symposium in Amarillo, Tex., Apr. 13-14, 1992, which discloses operating a NGL section of a process with a nitrogen recovery unit (“NRU”) and a helium recovery unit (“HRU”). In such processes, a natural gas stream is feed to a distillation column that produces a NGL stream and one or more vapor streams that are passed to an integrated NRU/HRU unit. The NRU/HRU unit produces a vapor stream enriched in helium, a vapor stream enriched in nitrogen, and a residual gas stream enriched in methane.
The prior art has long sought methods for improving efficiency and economics of processes for separating and recovering helium and natural gas liquids from natural gas. Accordingly, there has been a need for more efficient and more economical methods for performing this separation.
In general, in one aspect, the invention relates to a process of producing a helium-enriched vapor stream, a methane-enriched vapor stream, and a liquid stream enriched in hydrocarbons and other compounds heavier than methane from a pressurized, multicomponent, multiphase stream comprising methane (C1), helium (He) and hydrocarbons heavier than methane (C2+). The process comprises cooling the gas stream to produce at least one vapor stream enriched in helium and at least one liquid stream, withdrawing at least a portion of the at least one vapor stream as a helium-enriched product stream, passing at least a portion of the at least one liquid stream to a demethanizer, withdrawing from the demethanizer a vapor enriched in methane (C1), and withdrawing from the demethanizer a liquid enriched in hydrocarbons heavier than methane (C2+).
In another aspect, the invention relates to a process comprising passing a natural gas feed stream containing helium and NGLs into a first phase separator to produce a first vapor phase and a first liquid phase, withdrawing the first vapor phase from the first phase separator, separating the first vapor phase into a second vapor phase and a third vapor phase, cooling the second vapor phase by indirect heat exchange in a heat exchanger, expanding the cooled second vapor phase to produce a reduced-pressure vapor phase and reduced-pressure liquid phase, and passing the reduced-pressure vapor and liquid phases to a second phase separator, withdrawing from the second phase separator a helium-enriched vapor phase, withdrawing liquid from the second phase separator and passing the withdrawn liquid to a first flow regulating device, passing liquid from the first flow regulating device to a demethanizer, expanding the third vapor phase to produce a reduced-pressure vapor phase and reduced-pressure pressure liquid phase, and passing the reduced-pressure vapor and liquid phases to the demethanizer, withdrawing liquid from the first phase separator and passing the withdrawn liquid to a second flow regulating device, passing liquid from the second flow regulating device to the demethanizer, withdrawing from the demethanizer a vapor enriched in methane (C1), and withdrawing from the demethanizer a liquid enriched in hydrocarbons heavier than methane (C2+).
Other aspects and advantages of the invention will be apparent from the following description and the appended claims.
Further features and advantages of the present invention will become apparent from the following detailed description taken in combination with the appended drawings, in which:
While the present disclosure is susceptible to various modifications and alternative forms, specific example embodiments thereof have been shown in the drawings and are herein described in detail. It should be understood, however, that the description herein of specific example embodiments is not intended to limit the disclosure to the particular forms disclosed herein, but on the contrary, this disclosure is to cover all modifications and equivalents as defined by the appended claims. It should also be understood that the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating principles of exemplary embodiments of the present invention. Moreover, certain dimensions may be exaggerated to help visually convey such principles. For purposes of clarity, not every component is labeled in every figure, nor is every component of each embodiment of the invention shown where illustration is not necessary to allow those of ordinary skill in the art to understand the invention. In the drawings, the same reference numerals designate like or corresponding, but not necessarily identical, elements throughout the figures. Various required subsystems such as, but not limited to, valves, pumps, motors, reboilers, flow stream mixers, control systems, and sensors have been deleted from the drawings for the purposes of simplicity and clarity of presentation. Such subsystems would be provided in accordance with standard engineering practice.
In the following detailed description section, the specific embodiments of the present invention are described in connection with preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present invention, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the invention is not limited to the specific embodiments described below, but rather, it includes all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.
In the interest of clarity, not all features of an actual implementation are described in this disclosure. It will of course be appreciated by persons skilled in the art that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Moreover, it will be appreciated by persons skilled in the art that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure.
Various terms as used herein are defined below. To the extent a term used in a claim is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent.
As used herein, “a” or “an” entity refers to one or more of that entity. As such, the terms “a” (or “an”), “one or more”, and “at least one” can be used interchangeably herein unless a limit is specifically stated.
As used herein, the term “enriched” as applied to any stream withdrawn from a process means that the withdrawn stream contains a concentration of a particular component that is higher than the concentration of that component in the feed stream to the process.
As used herein, the term “expansion device” refers to one or more devices suitable for reducing the pressure of a fluid in a line (for example, a liquid stream, a vapor stream, or a multiphase stream containing both liquid and vapor). Unless a particular type of expansion device is specifically stated, the expansion device may be (1) at least partially by isenthalpic means, or (2) may be at least partially by isentropic means, or (3) may be a combination of both isentropic means and isenthalpic means. Suitable devices for isenthalpic expansion of natural gas are known in the art and generally include, but are not limited to, manually or automatically actuated throttling devices such as, for example, valves, control valves, Joule-Thomson (J-T) valves, or venturi devices. Suitable devices for isentropic expansion of natural gas are known in the art and generally include equipment such as expanders or turbo expanders that extract or derive work from such expansion. Suitable devices for isentropic expansion of liquid streams are known in the art and generally include equipment such as expanders, hydraulic expanders, liquid turbines, or turbo expanders that extract or derive work from such expansion. An example of a combination of both isentropic means and isenthalpic means may be a Joule-Thomson valve and a turbo expander in parallel, which provides the capability of using either alone or using both the J-T valve and the turbo expander simultaneously. Isenthalpic or isentropic expansion can be conducted in the all-liquid phase, all-vapor phase, or mixed phases, and can be conducted to facilitate a phase change from a vapor stream or liquid stream to a multiphase stream (a stream having both vapor and liquid phases). In the description of the drawings herein, the reference to more than one expansion device in any drawing does not necessarily mean that each expansion device is the same type or size.
As used herein, the term “demethanizer” refers broadly to any distillation column to separate methane and other volatile components from ethane and heavier components. The distillation column contains a plurality of vertically spaced trays, one or more packed beds, or some combination of trays and packing. The trays and/or packing provide the necessary contact between the liquids falling downward in the column and the vapors rising upward. The column also includes one or more reboilers (not shown in the drawings) which heat and vaporize a portion of the liquids flowing down the column to provide the stripping vapors which flow up the column. These vapors strip the methane from the liquids, so that the bottom liquid product is substantially devoid of methane and comprised of the majority of the ethane, propane, and heavier hydrocarbons contained in one or more feed streams to the column.
As used herein the term “indirect heat exchange” means the bringing of two fluids into heat exchange relation without any physical contact or intermixing of the fluids with each other.
As used herein the terms “turboexpansion” and “turboexpander” mean respectively method and apparatus for the flow of high pressure fluid through a turbine to reduce the pressure and the temperature of the fluid, thereby generating refrigeration and useful work.
As used herein, the term “reboiler” refers to an indirect heat exchange means used to at least partially vaporize a stream withdrawn near the bottom of a demethanizer.
As used herein the term “compressor” means a machine that increases the pressure of a gas by the application of work.
As used herein the term “cryogenic pump” means a device for increasing the head of a fluid stream at cryogenic temperatures.
As used herein, the term “bottoms reboiler” refers to an indirect heat exchange means used to at least partially vaporize a stream withdrawn near the bottom of a distillation column.
As used herein, the term “bottoms stream” or “bottoms product” refers to an at least partially liquid stream withdrawn from at or near the bottom port of a distillation column.
As used herein, the terms “comprising,” “comprises,” and “comprise” are open-ended transition terms used to transition from a subject recited before the term to one or elements recited after the term, where the element or elements listed after the transition term are not necessarily the only elements that make up of the subject.
As used herein, the terms “containing,” “contains,” and “contain” have the same open-ended meaning as “comprising,” “comprises,” and “comprise.” As used herein, the terms “distillation” or “fractionation” refer to the process of physically separating chemical components into a vapor phase and a liquid phase based on differences in the components' boiling points at specified temperature and pressure.
As used herein, a “flow regulating device” is any device capable of regulating flow of liquid from a separator to maintain a desired liquid level in the separator, including but not limited to such devices as a liquid regulator, expansion valve, flow regulating pump, or a combination of such devices.
As used herein, the terms “having,” “has,” and “have” have the same open-ended meaning as “comprising,” “comprises,” and “comprise.” As used herein, the terms “including,” “includes,” and “include” have the same open-ended meaning as “comprising,” “comprises,” and “comprise.”
As used herein, the term “indirect heat exchange” refers to a process wherein the refrigerant cools the substance to be cooled without actual physical contact between the refrigerating agent and the substance to be cooled. Core-in-kettle heat exchangers and brazed aluminum plate-fin heat exchangers are specific examples of equipment that facilitate indirect heat exchange.
As used herein, the terms “natural gas liquids”, “NGL” or “NGLs” refer to mixtures of hydrocarbons whose components are, for example, typically ethane and heavier. Some examples of hydrocarbon components of NGL streams include ethane, propane, butane, and pentane isomers, benzene, toluene, other aromatic molecules, and possibly small amounts of methane, CO2, and other components.
As used herein, the terms “overhead stream” or “overhead product” refers to an at least partially vapor stream withdrawn from at or near the top port of a fluid separation vessel such as a phase separator, demethanizer or distillation column.
As used herein, the term “reflux” refers to an at least partially liquid stream introduced into the upper portion of a distillation column in order to increase separation efficiency.
As used herein, the term “side reboiler” refers to an indirect heat exchange means used to heat and at least partially vaporize a stream withdrawn from between the upper and lower portions of a distillation column.
As used herein, the term “turboexpander” refers to any device for expanding a stream that is capable of generating useful work.
In general, the invention relates to a process for producing a helium-enriched vapor stream, a methane-enriched vapor stream, and a liquid stream enriched in hydrocarbons heavier than methane from a pressurized, multicomponent, multiphase stream comprising methane (C1), helium (He), and NGLs, The recovery of helium can be from any stream in the NGL recovery process that is primarily liquid during the processing by passing the liquid to a phase separator and flashing out a helium-enriched vapor stream.
Pretreatment is the first consideration in cryogenic processing of natural gas. A raw natural gas feed stock suitable for the process of this invention may comprise natural gas obtained from a crude oil well (associated gas) or from a gas well (non-associated gas). The composition of the natural gas can vary significantly. Natural gas will typically contain methane (C1) as the major component, and will typically also contain ethane (C2), propane (C3), and higher hydrocarbons, diluents such as nitrogen, argon, and helium, and contaminants such as water, carbon dioxide, mercury, mercaptans, hydrogen sulfide, and iron sulfide. The solubilities of these contaminants vary with temperature, pressure, and composition. At cryogenic temperatures, CO2, water, and other contaminants can form solids, which can plug flow passages in cryogenic heat exchangers and other equipment. These potential difficulties can be avoided by removing such contaminants. In the following description, it is assumed that the natural gas stream has been suitably treated to remove unacceptable levels of mercury, sulfides, carbon dioxide, and other contaminates, and dried to remove water using conventional and well-known processes to produce a “sweet, dry” natural gas stream. Alternatively, some level of these contaminants may be left in the feed gas and become distributed into the product stream which may require additional treatment at a later stage depending on the intended use of the product.
Referring to
Feed stream 14 is passed to one or more phase separators 80 which separate the multiphase feed stream 14 into vapor stream 16 and a liquid stream 30. The separator 80 has a liquid level control means (not shown in the drawing) which operates in a known manner to control one or more flow regulating devices 72. Flow regulating device 72 can be any device capable of regulating the flow of liquid from the separator 80 to maintain a desired liquid level in separator 80, such as but not limited to a liquid regulator, expansion device, or flow regulating pump, or a combination of such equipment. Flow from the flow regulating device 72 to demethanizer 88 occurs via stream 31. If the pressure of stream 30 is higher than the pressure in the demethanizer 88, the flow regulating device 72 can be used to depressurize the liquid to a pressure at or near the pressure of the demethanizer 88. If the pressure of the stream 30 is lower than the pressure in demethanizer 88, a flow regulating pump may be used to increase the pressure of stream 30 to a pressure at or near the pressure of the demethanizer 88.
A first fraction of vapor stream 16 may optionally be withdrawn and passed as stream 25 to an expansion device 71 wherein the pressure of the vapor stream 25 is reduced, thereby effecting a reduction in temperature of this stream 25. Stream 26 exiting the expansion device 71 is passed to the demethanizer 88. A second fraction of vapor stream 16 is passed as stream 18 to one or more heat exchangers 63 wherein stream 18 is cooled by indirect heat exchange against a suitable coolant, preferably overhead vapor from demethanizer 88 (not shown in
Referring still to
Referring still to
Liquid stream 149 exiting the phase separator 173 is passed to a flow regulating device 174, preferably a J-T valve, wherein the pressure of the liquid stream 149 is reduced, thereby effecting a reduction in temperature of this stream. Stream 150 exiting the flow regulating device 174 is passed through heat exchanger 171 to provide additional refrigeration duty for vapor stream 145. Stream 152 exiting heat exchanger 171 is passed through heat exchanger 163 to provide cooling for vapor stream 118. Vapor stream 153 exits heat exchanger 163 as low pressure (LP) fuel which may supply a portion of the power needed to drive compressors and pumps in the separation process or may be further compressed to join stream 144 as methane-enriched product.
Liquid stream 122 exiting phase separator 165 is passed to one or more flow regulating devices 166, preferably an expansion device wherein the pressure of the liquid stream 122 is reduced, thereby effecting a reduction in temperature of this stream. Stream 123 exiting the flow regulating device 166 is passed to the demethanizer 188. Stream 135 leaves the demethanizer 188 as enriched methane and stream 136 leaves the demethanizer substantially demethanized liquid product enriched in NGL. The demethanizer bottoms stream 136 may be passed to a conventional fractionation plant (not shown), the general operation of which is known to those skilled in the art. The fractionation plant may comprise one or more fractionation columns which separate liquid bottom stream 136 into predetermined amounts of ethane, propane, butane, pentane, and hexane.
Vapor stream 135 removed from the demethanizer 188 provides refrigeration duty for heat exchanger 163. Warmed stream 135 exits heat exchanger 163 as stream 138, a portion of which is passed as stream 139 through heat exchanger 162 to cool part stream 112. Stream 140 exits heat exchanger 162 and is recombined with stream 138. A part of the vapor stream 138 may be withdrawn from the system as fuel gas (stream 141). The remaining portion of vapor stream 138 is compressed by one or more compressors. Two compressors 169 and 170 are shown in
Liquid stream 249 exiting the phase separator 273 is passed to flow regulating device 274, preferably a Joule-Thomson valve, wherein the pressure of the liquid stream 249 is reduced, thereby effecting a reduction in temperature of this stream. Stream 250 exiting the expansion device 274 is passed through heat exchanger 271 to provide refrigeration assistance for stream 223 entering heat exchanger 271. Stream 252 exiting heat exchanger 271 is passed through heat exchanger 263 to provide refrigeration duty for cooling vapor stream 218. Vapor stream 253 exits heat exchanger 263 as a gas which, for example, can be used as low pressure (LP) fuel, which may supply a portion of the power needed to drive compressors and pumps in the separation process.
Vapor stream 235 removed from the demethanizer 288 provides refrigeration duty for heat exchanger 263. Warmed stream 235 exits heat exchanger 263 as stream 238, a first portion of which is passed as stream 239 through heat exchanger 262 to cool part of the feed stream 212. Stream 240 exits heat exchanger 262 and is recombined with stream 238. A second portion of stream 238 is passed through heat exchanger 276 and recombined with stream 240. A portion of the vapor stream 238 may be withdrawn from the system as fuel gas (stream 241). The remaining portion of vapor stream 238 is compressed by one or more compressors. Two compressors 269 and 270 are shown in
Liquid stream 222 from phase separator 265 is passed to flow regulating device 266, preferably a pressure reduction means, and more preferably a Joule-Thomson valve, wherein the pressure of the stream 222 is reduced, thereby effecting a reduction in temperature of this stream. Stream 224 exiting the flow regulating device 266 is passed to demethanizer 288.
Liquid stream 236 leaves the demethanizer 288 as substantially demethanized liquid product enriched in NGL. The demethanizer bottoms stream 236 may be passed to a conventional fractionation plant (not shown), the general operation of which is known to those skilled in the art. The fractionation plant may comprise one or more fractionation columns which separate liquid bottom stream 236 into predetermined amounts of ethane, propane, butane, pentane, and hexane.
Referring still to
The embodiments disclosed herein can be used for new plant designs or can be used to retrofit existing NGL recovery plants to recover helium. For example, any of the embodiments of
One benefit of using the invention over methods used in the past is the ability to integrate helium recovery with existing units or processes in a natural gas plant. Helium recovery schemes in the past typically have separate unit operations from NGL recovery units or processes. Integration of helium recovery and NGL recovery minimizes the capital cost associated with the entire facility, which afford more helium recovery in gas plants.
A simulated mass and energy balance was carried out to illustrate the embodiments illustrated in the
The data were obtained using a commercially available process simulation program called HYSYS™, version 2004.1 (13.2.0.6510), available from Hyprotech Ltd.; however, other commercially available process simulation programs can be used to develop similar data, including for example HYSIM™, PROII™, and ASPEN PLUS™, all of which are familiar to those of ordinary skill in the art.
It should be understood that the preceding is merely a detailed description of specific embodiments of this invention and that numerous changes, modifications, and alternatives to the disclosed embodiments can be made in accordance with the disclosure here without departing from the scope of the invention. The preceding description, therefore, is not meant to limit the scope of the invention. Rather, the scope of the invention is to be determined only by the appended claims and their equivalents.
This application claims the benefit of U.S. Provisional Application No. 61/103,436, filed 7 Oct. 2008.
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/US09/51968 | 7/28/2009 | WO | 00 | 3/14/2011 |
| Number | Date | Country | |
|---|---|---|---|
| 61103436 | Oct 2008 | US |
