Integration of pollutant separation and regasification systems

Abstract

The present invention relates to a method and system for cryogenically separating contaminants and regasifying LNG using a common refrigeration plant and / or fuel. An integrated system comprises: an assembly for separating contaminants from an input feed stream; a heat exchanger coupled to a first pipeline, wherein: the first pipeline is coupled to the assembly for separating contaminants and the heat exchanger cools a first feed stream of the first pipeline; and an LNG regasification system comprising a vaporizer, wherein: the vaporizer heats the LNG stream of the LNG regasification system and the heat exchanger acts as a vaporizer. A method comprises: separating contaminants from an input feed stream using an assembly for separating contaminants; cooling the first feed stream using a heat exchanger, wherein the heat exchanger is coupled to the assembly for separating contaminants; and heating the LNG stream using a vaporizer of the LNG regasification system, wherein the heat exchanger acts as a vaporizer.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims the benefit of priority to U.S. Provisional Patent Application No. 62 / 927,757, filed on October 30, 2019, entitled "Integration of Pollutant Separation and Regasification Systems." Background Art Technical Field

[0004] The present disclosure relates generally to the field of hydrocarbon processing, including fluid processing and separation. More specifically, the present disclosure relates to the processing and separation of fluids, wherein the output includes hydrocarbons in a gaseous state and / or with reduced concentrations of contaminants, such as acid gases, sour gases, and / or flue gases.

[0005] Description of related prior art

[0006] This section is intended to introduce various aspects of this area that may be associated with the disclosure of the present invention. This discussion is intended to provide a framework for better understanding the specific aspects of the disclosure of the present invention. Therefore, it should be understood that this section should be read from this perspective and is not necessarily an admission to the prior art.

[0007] The production of natural gas hydrocarbons (e.g., methane and ethane) from reservoirs is often accompanied by the incidental production of non-hydrocarbon gases. These gases include contaminants such as at least one of carbon dioxide (CO), hydrogen sulfide (H2S), carbonyl sulfide, carbon disulfide, and various mercaptans. When a feed stream produced from a reservoir includes these contaminants mixed with hydrocarbons, the stream is often referred to as "sour gas."

[0008] Many natural gas reservoirs have a relatively low percentage of hydrocarbons and a relatively high percentage of contaminants. Contaminants can act as diluents and reduce the heat content of the hydrocarbons. Some contaminants, such as sulfur compounds, are toxic and can even be fatal. Additionally, some contaminants can become very corrosive in the presence of water.

[0009] It is desirable to remove contaminants from hydrocarbon-containing streams to produce low-sulfur, concentrated hydrocarbons. Specifications for pipeline-quality natural gas typically call for a maximum of 2 to 4% CO2 and 1 / 4 grain H2S per 100 scf (4 ppmv) or 5 mg / Nm 3 Specifications for lower temperature processes, such as natural gas liquefaction plants or denitrification units, typically specify less than 50 ppm CO2.

[0010] The separation of pollutants from hydrocarbons is difficult, and therefore a great deal of work has been done to develop hydrocarbon / pollutant separation methods. These methods can be divided into three main categories: solvent absorption (physical, chemical, and hybrid), solid adsorption, and distillation.

[0011] Separating some mixtures by distillation can be relatively simple and, therefore, widely used in the natural gas industry. However, the distillation of mixtures of natural gas hydrocarbons (primarily methane) and one of the most common contaminants in natural gas (carbon dioxide) can present significant difficulties. Conventional distillation principles and conventional distillation equipment are based on the presence of only gas and liquid phases throughout the distillation column. If pipeline or better quality hydrocarbon products are desired, separating CO2 from methane by distillation involves temperature and pressure conditions that cause the CO2 to solidify. The temperatures involved are cold temperatures, generally referred to as cryogenic temperatures (i.e., any temperature of about -40°C (-40°F) and lower).

[0012] Certain cryogenic distillations can overcome the above-mentioned difficulties. These cryogenic distillations provide a suitable mechanism for handling the formation and subsequent melting of solids during the separation of solid-forming contaminants from hydrocarbons. The formation of solid contaminants in equilibrium with the vapor-liquid mixture of hydrocarbons and contaminants under specific temperature and pressure conditions occurs in the controlled refrigeration zone section of the distillation column. The lower section of the distillation column can also assist in the separation of contaminants from hydrocarbons, but the lower section is operated at a temperature and pressure where solids do not form.

[0013] In known cryogenic distillation applications using a controlled freezing zone section, the feed stream is dried and pre-cooled to a temperature of approximately -51°C (-60°F) before being introduced into the distillation column below the controlled freezing zone section and the melt tray. The vapor component of the cooled feed stream combines with vapor rising from the stripping section of the column and bubbles through the liquid on the melt tray. This has several beneficial purposes, including: the rising vapor stream is cooled and a portion of the CO2 is condensed, resulting in a cooler and cleaner gas stream entering the open portion of the controlled freezing zone spray chamber; the rising vapor stream is evenly distributed across the cross-section of the column as it enters the controlled freezing zone spray chamber; the majority of the required melt tray heat input is provided by sensible heat from cooling the vapor and latent heat from condensing a portion of the CO2 in the gas stream; and the melt tray liquid is vigorously mixed, which facilitates melting of solid CO2 particles falling into the melt tray and a bulk liquid temperature of only 2 to 3°F above the melting point of CO2. However, cryogenic distillation applications using controlled freezing zone sections utilize several different mechanisms to reduce the temperature of the various feed streams. It would be beneficial to provide a more efficient cooling mechanism.

[0014] Pollution can also be a challenge after hydrocarbon combustion (for example, in power plants). The combustion of hydrocarbons produces "flue gas", which includes CO2, water vapor, sulfur dioxide and nitrogen oxides. In the post-combustion recapture process, CO2 is separated and captured from the flue gas produced by combustion. The process of recapturing CO2 from flue gas is similar to the solvent absorption process of separating CO2 from acid gases. For example, a "filter" can help capture CO2 as CO2 travels up a chimney or smokestack. The filter includes a solvent that absorbs CO2. The solvent can then be heated to produce water vapor and a concentrated CO2 stream. The concentrated CO2 stream can be compressed and / or the temperature of the concentrated CO2 stream can be reduced using a heat exchanger. At least a portion of the CO2 is condensed within the heat exchanger, thereby producing a solid or liquid condensed phase CO2 component and a light gas component. The condensed phase CO2 component can then be recovered. However, using such technology to recover CO2 products from flue gas can be expensive due to the high degree of compression that may be involved.

[0015] Once the CO2 has been separated from the acid gas feed or recaptured from the flue gas feed, the CO2 can be injected into a nearby well or storage formation, and / or the CO2 can be transported (e.g., via a pipeline) to a suitable storage location. However, the CO2 must first be cooled and / or compressed for storage and / or transportation, which requires a large amount of energy. It would be beneficial to provide a more efficient CO2 cooling and / or compression mechanism.

[0016] Many natural gas sources are in parts of the world that are far from any commercial market for natural gas. When pipeline transportation is not feasible, the produced natural gas is usually processed into liquefied natural gas (which is called "LNG") for transportation to the market. Therefore, natural gas is transported as LNG to locations where LNG can be used for heating, power generation or industrial purposes. LNG is usually stored and / or transported at a temperature of about -162°C (-260°F) and at essentially atmospheric pressure. However, LNG is usually not available to consumers in very cold liquid form. Therefore, in order to be used as fuel or inserted into market pipelines, LNG must be converted back to a gaseous state for distribution to consumers. LNG is heated and / or vaporized in a process called regasification. Typically, LNG regasification plants are located near seaports, either on land or on floating vessels, so as to facilitate the receipt of LNG from around the world. In order to supply the vaporized gas at pipeline temperature and / or pressure, heat can first be added to the cryogenic LNG stream. The heat can come from a variety of sources, such as: (1) burning the regasified LNG (thereby losing the market value of the portion of the gas consumed), (2) warm water, (3) warm air, or (4) an industrial exothermic process. It would be beneficial to integrate the regasification of LNG with one or more other industrial processes to more efficiently utilize the heat energy that would otherwise be wasted. SUMMARY OF THE INVENTION

[0018] Embodiments of the present disclosure relate to the integration of hydrocarbon refining processes, including liquefied natural gas ("LNG") regasification processes, with processes for separating contaminants from acid gas and / or flue gas feed streams.

[0019]

[0014] Embodiments of the present disclosure relate to processes for cryogenic separation of contaminants and LNG regasification, wherein the two processes utilize or are integrated around common refrigeration equipment and / or fuel gas usage.

[0020]

[0014] Embodiments of the present disclosure relate to methods for separation of contaminants using a solvent and regasification of LNG, wherein the two methods utilize or are integrated around common refrigeration equipment and / or fuel gas usage.

[0021] Embodiments of the present disclosure relate to an integrated system comprising: an assembly for separating contaminants from an input feed stream; a heat exchanger coupled to a first pipeline, wherein: the first pipeline is coupled to the assembly for separating contaminants and the heat exchanger cools a first feed stream of the first pipeline; and an LNG regasification system comprising a vaporizer, wherein: the vaporizer heats an LNG stream of the LNG regasification system and the heat exchanger acts as the vaporizer.

[0022] Embodiments of the present disclosure relate to a method comprising: separating contaminants from an input feed stream using an assembly for separating contaminants; cooling the first feed stream using a heat exchanger, wherein the heat exchanger is coupled to the assembly for separating contaminants; and heating the LNG stream using a vaporizer of an LNG regasification system, wherein the heat exchanger functions as the vaporizer.

[0023]

[0011] The foregoing has broadly outlined the features of the present disclosure in order that the detailed description that follows may be better understood. Additional features are also described herein. BRIEF DESCRIPTION OF THE DRAWINGS

[0024] These and other features, aspects, and advantages of the present disclosure will become apparent from the following description, the appended claims, and the accompanying drawings, which are briefly described below.

[0025] Figure 1 is a schematic diagram of a column with sections within a single vessel.

[0026] Figure 2 is a schematic diagram of a column having sections within multiple vessels.

[0027] Figure 3 is a schematic diagram of a column with sections within a single vessel.

[0028] Figure 4 is a schematic diagram of a column having sections within multiple vessels.

[0029] Figure 5 is a schematic diagram of the LNG regasification system.

[0030] Figure 6 is a schematic diagram of the integrated separation and regasification system.

[0031] Figure 7 is a schematic diagram of another integrated separation and regasification system.

[0032] Figure 8 is a schematic diagram of another integrated separation and regasification system.

[0033] It should be noted that the drawings are merely examples and are not intended to limit the scope of the present disclosure. Furthermore, the drawings are generally not drawn to scale, but are drawn for convenience and clarity to illustrate various aspects of the present disclosure.

[0034] Detailed description

[0035] In order to promote the understanding of the principle of the present disclosure, now will refer to the features shown in the accompanying drawings, and will use specific language to describe these features. However, it should be understood that it is not intended to limit the scope of the present disclosure thus. Any change and further modification of the principle of the present disclosure as described herein and any further application are all that the technical personnel of the field of the present disclosure usually think of. For those skilled in the relevant art, it is obvious that, for the sake of clarity, some features not relevant to the present disclosure may not be shown in the drawings.

[0036] As referred to in this application, the terms "stream," "gas stream," "vapor stream," and "liquid stream" refer to different stages of one or more feed streams when processing the feed stream (for example, in a distillation column separating methane (the primary hydrocarbon in natural gas) from contaminants). Although the phrases "gas stream," "vapor stream," and "liquid stream" may refer to situations where gas, vapor, or liquid, respectively, is primarily present in the stream, other phases may also be present within the stream. For example, gas may also be present in a "liquid stream." In some cases, the terms "gas stream" and "vapor stream" may be used interchangeably.

[0037] The term "natural gas" refers to a multi-component gas obtained from a crude oil well (associated gas) or a multi-component gas obtained from an underground gas-bearing formation (non-associated gas). The composition and pressure of raw natural gas can vary significantly. A typical natural gas stream contains methane (C1 carbon content) as an important component. Raw natural gas may also contain ethane (C2 carbon content), higher molecular weight hydrocarbons, acid gases (such as carbon dioxide, hydrogen sulfide, carbonyl sulfide, carbon disulfide and mercaptans) and small amounts of contaminants such as water, nitrogen, iron sulfide, wax and crude oil. As used herein, natural gas includes gas produced by the regasification of liquefied natural gas ("LNG") that has been purified to remove contaminants such as water, acid gases and most higher molecular weight hydrocarbons.

[0038] As referred to herein, a "heat exchanger" broadly refers to any device capable of transferring heat from one medium to another, and specifically includes any structure commonly referred to as a heat exchanger, such as any device. Heat exchangers include "direct heat exchangers" and "indirect heat exchangers." Thus, a heat exchanger may be a plate and frame, shell and tube, spiral, hairpin, core, core-kettle, tube-in-tube, or any other type of known heat exchanger. A "heat exchanger" may also refer to any column, tower, unit, or other arrangement suitable for allowing one or more streams to pass therethrough and effecting direct or indirect heat exchange between one or more refrigerant lines and one or more feed streams.

[0039] As used herein, the terms "approximately," "about," "substantially," and similar terms are intended to have a broad meaning consistent with common and accepted usage by those of ordinary skill in the art to which the subject matter of this disclosure pertains. Those skilled in the art reading this disclosure should understand that these terms are intended to allow certain features to be described and claimed without limiting the scope of those features to the precise numerical ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the described subject matter are considered to be within the scope of this disclosure.

[0040] The articles "the," "a," and "an" are not necessarily limited to referring to only one, but are inclusive and open-ended so as to optionally include a plurality of such elements.

[0041] Among the many potential advantages of embodiments of the present disclosure is that temperature control resources can be shared by multiple processes, thereby reducing both costs and environmental impact. Other potential advantages include one or more of the following, particularly as will be apparent to those skilled in the art having the benefit of this disclosure: reduction and / or elimination of separate refrigeration equipment for cryogenic distillation applications using controlled refrigeration zones; reduction and / or elimination of separate refrigeration equipment for solvent absorption applications; and reduction and / or elimination of separate vaporization equipment for LNG regasification systems. Thus, embodiments of the present disclosure may be used for the recovery and / or refining of hydrocarbons from subsurface formations.

[0042] Part of the present disclosure relates to systems and methods for separating feed streams in a distillation column. Such systems and methods help to optimally match the location at which a feed stream enters a distillation column based on the concentration of components in the feed stream in order to improve energy efficiency and / or optimally determine the size of the distillation column. The systems and methods can also help to prevent undesirable solids accumulation in the controlled freezing zone section of the distillation column. Figure 1-4 Various aspects of such systems and methods are shown.

[0043] The system and method can separate methane from contaminants in an acid gas and / or flue gas feed stream (e.g., a gas having a CO2 concentration of about 10% to about 80%). The exemplary separation system 101, 201, 301, 401 can include a distillation column 104, 204 ( Figure 1-4 ). The separation system 101, 201, 301, 401 can prepare a feed stream (eg, an acid gas and / or flue gas feed stream), and the distillation column 104, 204 can then separate the contaminants from the methane.

[0044] The distillation column 104, 204 can be divided into three functional sections: a lower section 106, an intermediate controlled freezing zone section 108, and an upper section 110. When the upper section 110 is needed and / or desired, the distillation column 104, 204 can include three functional sections.

[0045] When upper section 110 is not needed and / or desired, distillation column 104, 204 can include only two functional sections. When the distillation column does not include upper section 110, a portion of the vapors exiting intermediate controlled freezing zone section 108 can be condensed in condenser 122 and returned as a liquid stream via injection assembly 129. In addition, lines 18 and 20 can be eliminated, elements 124 and 126 can be the same, and elements 150 and 128 can be the same. The stream in line 14 (now taking vapors exiting intermediate controlled freezing zone 108) directs these vapors to condenser 122.

[0046] The lower section 106 may also be referred to as a stripper section. The intermediate controlled freezing zone section 108 may also be referred to as a controlled freezing zone section. The upper section 110 may also be referred to as a rectifier section.

[0047] The sections of the distillation column 104 may be contained within a single vessel ( Figure 1 and Figure 3 For example, the lower section 106 , the intermediate controlled freezing zone section 108 , and the upper section 110 may be housed within a single container 164 .

[0048] The sections of the distillation column 204 may be housed in multiple vessels to form a split column configuration ( Figure 2 and 4 ). Each container can be separated from the other containers. Pipes and / or other suitable mechanisms can connect one container to another container. In this case, the lower section 106, the intermediate controlled freezing zone section 108 and the upper section 110 can be accommodated in two or more containers. For example, Figure 2 and Figure 4 As shown, the upper section 110 can be housed in a single vessel 254, and the lower controlled freezing zone section 106 and the intermediate controlled freezing zone section 108 can be housed in a single vessel 164. When this is the case, the liquid stream exiting the upper section 110 can exit through the liquid outlet bottom 260. The liquid outlet bottom 260 is located at the bottom of the upper section 110. Although not shown, each section can be housed in its own separate vessel, one or more sections can be housed in separate vessels, or the upper and intermediate controlled freezing zone sections can be housed in a single vessel while the lower section can be housed in a single vessel, etc. When the sections of the distillation column are housed in multiple vessels, the multiple vessels can be arranged side by side horizontally and / or stacked vertically.

[0049] In the case where the height of the distillation column should be considered, movement considerations and / or transportation issues (e.g., for remote locations), a split tower configuration may be beneficial. This split tower configuration allows for independent operation of one or more sections. For example, when the upper section is contained in a single container and the lower and intermediate controlled freezing zone sections are contained in a single container, reflux liquid can be independently generated in the upper section using a substantial portion of the hydrocarbon stream that is substantially free of contaminants from a filling gas pipeline or an adjacent hydrocarbon pipeline. Reflux can be used to cool the upper section, establish an appropriate temperature distribution in the upper section, and / or accumulate a liquid inventory at the bottom of the upper section as an initial source of spray liquid for the intermediate controlled freezing zone section. In addition, the intermediate controlled freezing zone and the lower section can be independently prepared in the following manner: quench the feed stream, feed the feed stream to the optimal position (in the lower section or in the intermediate controlled freezing zone section), generate liquid for the lower and intermediate controlled freezing zone sections, and dispose of the vapor leaving the intermediate controlled freezing zone section when the vapor does not meet specifications and the contaminant content is too high. Additionally, liquid from the upper section may be injected intermittently or continuously to establish a liquid level at the bottom of the intermediate controlled freezing zone section and to cause the contaminant content in the intermediate controlled freezing zone section to decrease and approach a steady-state level, so that two vessels may be connected to convey a vapor stream from the intermediate controlled freezing zone section to the upper section, continuously injecting liquid from the bottom of the upper section into the intermediate controlled freezing zone section and stabilizing the operation to a steady-state condition. The split column configuration may utilize the upper section sump as a liquid receiver for pump 128, thereby eliminating the need for a separate pump. Figure 1 and Figure 3 The need for holding container 126 is met.

[0050] The system may further include a heat exchanger 100 ( Figure 1-4 A feed stream 10 (e.g., an acid gas feed stream, a flue gas feed stream) can enter a heat exchanger 100 before entering a distillation column 104, 204. For example, the feed stream 10 can be a feed stream from a reservoir, or the feed stream 10 can be from the outlet of a gas facility. The feed stream 10 can be cooled within the heat exchanger 100. The heat exchanger 100 helps reduce the temperature of the feed stream 10 to a level suitable for introduction into the distillation column 104, 204.

[0051] The system may include an expander device 102 ( Figure 1-4). The feed stream 10 may enter the expander device 102 before entering the distillation column 104, 204. After leaving the heat exchanger 100, the feed stream 10 may be expanded in the expander device 102, thereby further cooling it. The expander device 102 helps reduce the temperature of the feed stream 10 to a level suitable for introduction into the distillation column 104, 204. The expander device 102 may be any suitable device, such as a valve. If the expander device 102 is a valve, the valve may be any suitable valve that can assist in cooling the feed stream 10 before it enters the distillation column 104, 204. For example, the valve may include a Joule-Thompson (JT) valve.

[0052] The system may include a feed separator 103 ( Figure 3-4 ). The feed stream may enter a feed separator before entering the distillation column 104, 204. The feed separator may separate the feed stream having a mixed liquid and vapor stream into a liquid stream and a vapor stream. Line 12 may extend from the feed separator to the distillation column 104, 204. One of the pipelines 12 may receive a vapor stream from the feed separator. Another of the pipelines 12 may receive a liquid stream from the feed separator. Each of the pipelines 12 may extend to the same and / or different sections (i.e., the intermediate controlled freezing zone and the lower section) of the distillation column 104, 204. The expander device 102 may or may not be downstream of the feed separator 103. The expander device 102 may include a plurality of expander devices 102 such that each pipeline 12 has an expander device 102.

[0053] The system may include a dehydration unit 261 ( Figure 1-4 ). The feed stream 10 may enter a dehydration unit 261 before entering the distillation columns 104, 204. The feed stream 10 enters the dehydration unit 261 before entering the heat exchanger 100 and / or the expander device 102. The dehydration unit 261 removes water from the feed stream 10 to prevent water from causing problems later in the heat exchanger 100, the expander device 102, the feed separator 103, or the distillation columns 104, 204. Water can be problematic by forming a separate aqueous phase (i.e., ice and / or hydrates) that plugs lines or equipment or adversely affects the distillation process. The dehydration unit 261 dehydrates the feed stream to a sufficiently low dew point to ensure that a separate aqueous phase is not formed at any point downstream during the remainder of the process. The dehydration unit may be any suitable dehydration mechanism, such as a molecular sieve or a glycol dehydration unit.

[0054] The system may include a filtration unit (not shown). The feed stream 10 may enter the filtration unit before entering the distillation column 104, 204. The filtration unit may remove undesirable contaminants from the feed stream before entering the distillation column 104, 204. Depending on the contaminants to be removed, the filtration unit may be before or after the dehydration unit 261 and / or before or after the heat exchanger 100.

[0055] The system may include lines 12. Each line may be referred to as an inlet line 12. The feed stream is introduced into the distillation column 104, 204 through one of the lines 12. One or more lines 12 may extend to the lower section 106 or the intermediate controlled freezing zone section 108 of the distillation column 104, 204 to another line 12. For example, the line 12 may extend to the lower section 106 so that the feed stream 10 may enter the lower section 106 ( Figure 1-4 ). Each pipeline 12 can extend directly or indirectly to the lower section 106 or the intermediate controlled freezing zone section 108. Each pipeline 12 can extend to the outer surface of the distillation column 104, 204 before entering the distillation column.

[0056] If the system includes a feed separator 103 ( Figure 3-4 ), the pipeline 12 may include multiple pipelines 12. Each pipeline may be the same pipeline as one of the pipelines extending from the feed separator to a specific portion of the distillation column 104, 204.

[0057] Before entering the distillation column 104, 204, a sample of the feed stream 10 can enter an analyzer (not shown). The sample of the feed stream 10 can be a small sample of the feed stream 10. The feed stream 10 can include feed from multiple feed sources or feed from a single feed source. Each feed source can include, for example, a separate reservoir, one or more wellbores within one or more reservoirs, etc. The analyzer can determine the percentage of CO2 in the sample of the feed stream 10, and therefore determine the content of CO2 in the feed stream 10. The analyzer can be connected to multiple pipelines 12 so that after the sample of the feed stream 10 leaves the analyzer, the feed stream 10 can be sent to one or more sections 106, 108 of the distillation column 104, 204. If the analyzer determines that the percentage of CO2 is greater than about 20% or greater, the analyzer can direct the feed stream to the pipeline 12 extending from the lower section 106. If the analyzer determines that the percentage of CO2 is less than about 20% or less than 20%, the analyzer can direct the feed stream to the pipeline 12 extending from the intermediate controlled freezing zone section 108. The analyzer can be any suitable analyzer. For example, the analyzer can be a gas chromatograph or an infrared (IR) analyzer. The analyzer can be positioned before the feed stream 10 enters the heat exchanger 100. The feed stream 10 entering the analyzer can be single-phase.

[0058] While the feed stream 10 can be introduced into any section of the distillation column 104, 204 regardless of the percentage of CO2 in the feed stream 10, it is more efficient to introduce the feed stream 10 into the section of the distillation column 104, 204 where the best energy utilization will be employed. For this reason, it is preferred to introduce the feed stream into the lower section 106 when the percentage of CO2 in the feed stream is greater than about 20% or any percentage greater than 20%, and it is preferred to introduce the feed stream into the intermediate controlled freezing zone section 108 when the percentage of CO2 in the feed stream is less than about 20% or any percentage less than 20%.

[0059] The feed stream may be fed directly or indirectly to one of the sections 106, 108. Therefore, for optimal use of energy, it is best to introduce the feed stream into the distillation column 104, 204 at a point in the distillation process of the distillation column 104, 204 that matches the relevant percentage or content of CO2 in the feed stream.

[0060] The feed stream 10 can enter a feed separator 103. The feed separator 103 separates the feed stream vapor portion from the feed stream liquid portion before the feed stream is introduced into the distillation column 104, 204. The feed stream vapor portion can be fed to a different section or portion within the section of the distillation column 104, 204 than the feed stream liquid portion. For example, the feed stream vapor portion can be fed to the upper controlled freezing zone section 39 of the intermediate controlled freezing zone section 108, and / or the feed stream liquid portion can be fed to the lower controlled freezing zone section 40 of the intermediate controlled freezing zone section 108 or to the lower section 106 of the distillation column.

[0061] The lower section 106 is constructed and arranged to separate the feed stream 10 into a bottom liquid stream (i.e., liquid stream) enriched in contaminants and a refrigerated vapor stream (i.e., vapor stream). The lower section 106 separates the feed stream at a temperature and pressure that does not form solids. The liquid stream may contain a greater amount of contaminants than methane. The vapor stream may contain a greater amount of methane than the contaminants. In any case, the vapor stream is lighter than the liquid stream. As a result, the vapor stream rises from the lower section 106, and the liquid stream descends to the bottom of the lower section 106.

[0062] The lower section 106 may include and / or be connected to equipment for separating the feed stream. The equipment may include any suitable equipment for separating methane from contaminants, such as one or more packed sections 181, or one or more distillation trays with perforations, downcomers, and / or weirs. Figure 1-4 ).

[0063] The apparatus may include components that apply heat to the stream to form a vapor stream and a liquid stream. For example, the apparatus may include a first reboiler 112 that applies heat to the stream. The first reboiler 112 may be located external to the distillation column 104 or 204. The apparatus may also include a second reboiler 172 that applies heat to the stream. The second reboiler 172 may be located external to the distillation column 104 or 204. Line 117 may lead from the distillation column to the second reboiler 172. Line 17 may lead from the second reboiler 172 to the distillation column. Additional reboilers configured similarly to the second reboiler described above may also be used.

[0064] The first reboiler 112 can apply heat to the liquid stream exiting the lower section 106 through the liquid outlet 160 of the lower section 106. The liquid stream can travel from the liquid outlet 160 through line 28 to the first reboiler 112 ( Figure 1-4 The amount of heat applied to the liquid stream by the first reboiler 112 can be increased to separate more methane from the contaminants. The more heat applied to the stream by the reboiler 112, the more methane will be separated from the liquid contaminants, but more contaminants will also be vaporized.

[0065] The first reboiler 112 can apply heat to the stream within the distillation column 104, 204. Specifically, the heat applied by the first reboiler 112 raises the temperature of the lower section 106. This heat travels upward along the lower section 106 and supplies heat to heat the melt tray assembly 139 ( Figure 1-4 ) of the solid so that the solid forms a liquid and / or slurry mixture.

[0066] The second reboiler 172 applies heat to the stream within the lower section 106. This heat is applied closer to the intermediate controlled freezing zone section 108 than the heat applied by the first reboiler 112. As a result, the heat applied by the second reboiler 172 reaches the intermediate controlled freezing zone section 108 more quickly than the heat applied by the first reboiler 112. The second reboiler 172 also facilitates energy integration.

[0067] The apparatus may include one or more chimney assemblies 135 ( Figure 1-4 ). When descending to the bottom of the lower section 106, the liquid stream may encounter one or more chimney assemblies 135.

[0068] Each chimney assembly 135 includes a chimney tray 131 that collects the liquid stream within the lower section 106. The liquid stream collected on the chimney tray 131 can be fed to the second reboiler 172. After heating the liquid stream in the second reboiler 172, the stream can be returned to the intermediate controlled freezing zone section 108 to supply heat to the intermediate controlled freezing zone section 108 and / or the melting tray assembly 139. The unvaporized stream exiting the second reboiler 172 can be fed back to the distillation column 104, 204 below the chimney tray 131. The vapor stream exiting the second reboiler 172 can be routed below or above the chimney tray 131 as the vapor stream enters the distillation column 104, 204.

[0069] The chimney tray 131 may include one or more chimneys 137. The chimneys 137 serve as passages for the vapor stream in the lower section 106. The vapor stream travels through an opening in the chimney tray 131 at the bottom of the chimney 137 to the top of the chimney 137. The opening is closer to the bottom of the lower section 106 than to the bottom of the intermediate controlled freezing zone section 108. The top is closer to the bottom of the intermediate controlled freezing zone section 108 than to the bottom of the lower section 106.

[0070] Each chimney 137 has a chimney cap 133 attached. The chimney cap 133 covers the chimney top opening 138 of the chimney 137. The chimney cap 133 prevents liquid flow from entering the chimney 137. Vapor flow exits the chimney assembly 135 through the chimney top opening 138.

[0071] After descending to the bottom of the lower section 106, the liquid stream exits the distillation column 104, 204 through the liquid outlet 160. The liquid outlet 160 is located within the lower section 106 ( Figure 1-4 The liquid outlet 160 may be located at the bottom of the lower section 106 .

[0072] After exiting through liquid outlet 160, the feed stream may proceed to first reboiler 112 via line 28. The feed stream may be heated by first reboiler 112 before the vapor reenters lower section 106 via line 30. Unvaporized liquid may continue to exit the distillation process via line 24.

[0073] The system may include an expander device 114 ( Figure 1-4 ). After entering line 24, the heated liquid stream can be expanded in expander device 114. Expander device 114 can be any suitable device, such as a valve. Valve 114 can be any suitable valve, such as a JT valve.

[0074] The system may include a heat exchanger 116 ( Figure 1-4). The liquid stream heated by the first reboiler 112 can be cooled or heated by heat exchanger 116. Heat exchanger 116 can be a direct heat exchanger or an indirect heat exchanger. Heat exchanger 116 can include any suitable heat exchanger. After leaving heat exchanger 116, the liquid stream exits the distillation process via line 26.

[0075] The vapor stream in the lower section 106 rises from the lower section 106 to the intermediate controlled freezing zone section 108. The intermediate controlled freezing zone section 108 is constructed and arranged to separate the feed stream 10 introduced into the intermediate controlled freezing zone section or introduced into the top of the lower section 106 into a solid stream and a vapor stream. The intermediate controlled freezing zone section 108 forms solids, which may include more contaminants than methane. The vapor stream (i.e., a methane-rich vapor stream) may contain more methane than contaminants.

[0076] The intermediate controlled freezing zone section 108 includes a lower section 40 and an upper section 39. The lower section 40 is below the upper section 39. The lower section 40 is directly adjacent to the upper section 39. The lower section 40 is primarily, but not exclusively, a heating section of the intermediate controlled freezing zone section 108. The upper section 39 is primarily, but not exclusively, a cooling section of the intermediate controlled freezing zone section 108. The temperature and pressure of the upper section 39 are selected so that solids can form in the intermediate controlled freezing zone section 108.

[0077] The intermediate controlled freezing zone section 108 may include a melting tray assembly 139 ( Figure 1-4 The melting tray assembly 139 is located in the lower section 40 of the intermediate controlled freezing zone section 108. The melting tray assembly 139 is not located in the upper section 39 of the intermediate controlled freezing zone section 108.

[0078] The melting tray assembly 139 is constructed and arranged to melt the solids formed in the intermediate controlled freezing zone section 108. As the hot vapor stream rises from the lower section 106 to the intermediate controlled freezing zone section 108, the vapor stream immediately encounters the melting tray assembly 139 and provides heat to melt the solids. Figure 1-4 As shown, melt tray assembly 139 may include at least one of melt tray 118 , bubble cap 132 , liquid 130 , one or more discharge openings, one or more return inlets, and optionally, heating mechanism 134 .

[0079] The liquid and / or slurry mixture can be collected by the melt tray 118. The melt tray 118 separates at least a portion of the intermediate controlled freezing zone section 108 from the lower section 106. The melt tray 118 is located at the bottom 45 of the intermediate controlled freezing zone section 108.

[0080] One or more bubble caps 132 can serve as a passage for the vapor stream rising from the lower section 106 to the intermediate controlled freezing zone section 108. The bubble caps 132 can provide a path for the vapor stream to travel up the riser 140 and then down and around the riser 140 to the melting tray 118. The riser 140 is covered by a cap 141. The cap 141 prevents the liquid 130 from traveling into the riser and also helps prevent solids from traveling into the riser 140. The passage of the vapor stream through the bubble caps 132 allows the vapor stream to transfer heat to the liquid 130 within the melting tray assembly 139.

[0081] One or more heating mechanisms 134 can further heat the liquid 130 to promote melting of the solid into a liquid and / or slurry mixture. The heating mechanism 134 can be located anywhere within the melting tray assembly 139. For example, Figure 1-4 As shown, a heating mechanism 134 can be positioned around the bubble cap 132. The heating mechanism 134 can be any suitable mechanism, such as a heating coil. The heat source of the heating mechanism 134 can be any suitable heat source.

[0082] The liquid 130 in the melting tray assembly is heated by the vapor stream. The liquid 130 may also be heated by one or more heating mechanisms 134. The liquid 130 helps melt the solids formed in the intermediate controlled freezing zone section 108 into a liquid and / or slurry mixture. Specifically, the heat transferred by the vapor stream heats the liquid, thereby enabling the heat to melt the solids. The temperature of the liquid 130 may be at a level sufficient to melt the solids.

[0083] The thermal duty cycle of heat exchanger 100 can be maximized to provide the most efficient operation. As a precautionary measure, feed gas bypass line 147 and bypass valve 148 can be used to allow feed gas 10 to bypass heat exchanger 100, thereby increasing the temperature of the feed gas. This option can be used if the feed gas riser, which introduces the feed gas above the level of liquid 130, experiences fouling from solid CO2 in a low CO2 environment.

[0084] The intermediate controlled freezing zone section 108 may also include a spray assembly 129. Spray assembly 129 cools the vapor stream rising from the lower section 40. Spray assembly 129 sprays a liquid that is cooler than the vapor stream onto the vapor stream to cool the vapor stream. Spray assembly 129 is located within the upper section 39. Spray assembly 129 is not located within the lower section 40. Spray assembly 129 is above melting tray assembly 139. In other words, melting tray assembly 139 is below spray assembly 129.

[0085] The spray assembly 129 includes one or more spray nozzles 120 ( Figure 1-4Each spray nozzle 120 sprays liquid onto the vapor stream. The spray assembly 129 may also include a spray pump 128 ( Figure 1-4 ). Instead of a jet pump 128, gravity can induce flow in the liquid.

[0086] The liquid injected from the injection assembly 129 contacts the vapor stream at a temperature and pressure where solids are formed. When the injected liquid contacts the vapor stream, solids containing primarily contaminants are formed. The solids fall toward the melt tray assembly 139.

[0087] As the vapor stream travels from the bottom of the intermediate controlled freezing zone section 108 to the top of the intermediate controlled freezing zone section 108, the temperature in the intermediate controlled freezing zone section 108 cools. Methane in the vapor stream rises from the intermediate controlled freezing zone section 108 to the upper section 110. Some contaminants may remain in the methane and also rise. Contaminants in the vapor stream tend to condense or solidify at the cooler temperature and fall to the bottom of the intermediate controlled freezing zone section 108.

[0088] While in the liquid 130, the solids form a liquid and / or slurry mixture. The liquid and / or slurry mixture flows from the intermediate controlled freezing zone section 108 to the lower section 106. At least a portion of the liquid and / or slurry mixture flows from the bottom of the intermediate controlled freezing zone section 108 to the top of the lower section 106 via line 22 ( Figure 1-4 ). Line 22 can be an external line. Line 22 can extend from distillation column 104, 204. Line 22 can extend from intermediate controlled freezing zone section 108. The line can extend into lower section 106. Line 22 can extend from the outer surface of distillation column 104, 204.

[0089] like Figure 1-4 As shown, the vapor stream that rises in the intermediate controlled freezing zone section 108 and does not form solids or otherwise fall to the bottom of the intermediate controlled freezing zone section 108 rises to the upper section 110. The upper section 110 operates at a temperature, pressure, and contaminant concentration that does not form solids. The upper section 110 is constructed and arranged to cool the vapor stream to separate methane from the contaminants. The reflux in the upper section 110 cools the vapor stream. The reflux is introduced into the upper section 110 via line 18. Line 18 can extend into the upper section 110. Line 18 can extend from the outer surface of the distillation column 104, 204.

[0090] After contacting the reflux in the upper section 110, the feed stream forms a vapor stream and a liquid stream. The vapor stream primarily contains methane. The liquid stream contains relatively more contaminants. The vapor stream rises in the upper section 110, and the liquid descends to the bottom of the upper section 110.

[0091] To facilitate separation of methane from contaminants as the stream contacts the reflux, the upper section 110 may include one or more mass transfer devices 176. Each mass transfer device 176 facilitates separation of methane from contaminants. Each mass transfer device 176 may comprise any suitable separation device, such as a tray having perforations, or a section of random or structured packing to facilitate contact between the gas and liquid phases.

[0092] After ascending, the vapor stream can exit the distillation column 104, 204 via line 14. Line 14 can emanate from the upper portion of the upper section 110. Line 14 can extend from the outer surface of the upper section 110. From line 14, the vapor stream can enter a condenser 122 (e.g., a heat exchanger). Condenser 122 cools the vapor stream to form a cooled stream. Condenser 122 at least partially condenses the stream. After exiting condenser 122, the cooled stream can enter a separator 124. Separator 124 separates the vapor stream into a liquid stream and a vapor stream. The separator can be any suitable separator capable of separating a stream into a liquid stream and a vapor stream, such as a reflux drum. Once separated, the vapor stream can exit separator 124 as an output product. The output product can proceed via line 16 for subsequent sale to a pipeline and / or condensation into LNG. Once separated, the liquid stream can be returned to the upper section 110 via line 18 as reflux. The reflux can be pumped via any suitable mechanism, such as a reflux pump 150 ( Figure 1 and Figure 3 ) or gravity ( Figure 2 and Figure 4 ) proceeds to the upper section 110.

[0093] The liquid stream that falls to the bottom of the upper section 110 (i.e., the frozen zone liquid stream) is collected at the bottom of the upper section 110. The liquid may be collected on tray 183 ( Figure 1 and Figure 3 ) or the bottommost portion of the upper section 110 ( Figure 2 and Figure 4 The collected liquid can be removed through line 20 ( Figure 1 and 3 ) or liquid outlet bottom 260 ( Figure 2 and 4 ) exits the distillation column 104, 204. The line 20 may issue from the upper section 110. The line 20 may issue from the bottom end of the upper section 110. The line 20 may extend from the outer surface of the upper section 110.

[0094] Line 20 and / or liquid outlet bottom 260 are connected to line 41. Line 41 leads to spray assembly 129 in intermediate controlled freezing zone section 108. Line 41 is connected from holding vessel 126 ( Figure 1 and Figure 3) is emitted. The pipeline 41 can extend to the outer surface of the intermediate controlled freezing zone section 108.

[0095] The line 20 and / or the liquid outlet bottom 260 may be directly or indirectly ( Figure 1-4 ) is connected to line 41. When line 20 and / or liquid outlet bottom 260 are directly connected to line 41, the liquid spray can be pumped to spray nozzle 120 via any suitable mechanism (e.g., spray pump 128 or gravity). When line 20 and / or liquid outlet bottom 260 are indirectly connected to line 41, lines 20, 41 and / or liquid outlet bottom 260 and line 41 can be directly connected to holding vessel 126 ( Figure 1 and 3 The holding container 126 can contain at least some of the liquid spray before the liquid is sprayed through the nozzle. The liquid spray can be sprayed by any suitable mechanism (e.g., spray pump 128 ( Figure 1-4 ) or gravity) is pumped from the holding vessel 126 to the injection nozzle 120. The holding vessel 126 may be required when there is not a sufficient amount of liquid flow at the bottom of the upper section 110 to supply the injection nozzle 120.

[0096] It should be understood that the various components of separation systems 101, 201, 301, and 401 are used to reduce the temperature of their feed streams. These components include heat exchanger 100 and condenser 122. For example, heat exchanger 100 can reduce the temperature of feed stream 10 before it enters distillation columns 104 and 204. As another example, a vapor stream from line 14 can enter condenser 122, which cools the vapor stream and at least partially condenses it. After exiting condenser 122, the cooled vapor stream can enter separator 124. Each of these temperature reduction components can utilize a cooling fluid stream to provide a heat sink to reduce the temperature of the corresponding feed stream.

[0097]

[0011] Part of the present disclosure relates to systems and methods for LNG regasification. Figure 5A simplified diagram of an LNG regasification system 502 is shown in FIG. Generally, regasification converts LNG from a liquid state to a gaseous state. As shown, regasification system 502 includes a storage tank 510 (e.g., a tank on land, a ship, or a railcar), a pump 520 (e.g., a high-pressure pump), and a vaporizer 530. The regasification process typically transfers liquid LNG from storage tank 510 to vaporizer 530 via the action of pump 520. For example, pump 520 extracts liquid LNG from storage tank 510 via line 51. The liquid LNG in line 51 can be at a temperature in the range of approximately -270°F to approximately -250°F, or more specifically, at a temperature of approximately -162°C (-260°F). Pump 520 then directs the liquid LNG to vaporizer 530 via line 52. At vaporizer 530, a heat source (e.g., a heat exchanger) is used to regasify the liquid LNG. Vaporizer 530 converts the LNG into a gaseous state by heating it to a temperature greater than approximately -100°C, or possibly greater than approximately -50°C. For example, ambient air or seawater can be used to heat the LNG into a gaseous state. The gaseous LNG (or simply "natural gas") can be at a temperature greater than approximately -100°C, or possibly approximately -45.5°C (-50°F). The natural gas can be transported via pipeline 53 for consumption or storage.

[0098] Some embodiments provide integrated systems and methods for separating contaminants from gaseous feed streams (e.g., acid gas, flue gas) and for LNG regasification. Integration can reduce costs, complexity, geographic footprint, waste, overall return on investment, improve scalability, and / or provide redundancy and resilience for hydrocarbon processing operations. It is currently believed that by integrating the refrigeration system with the LNG regasification system, the cost of operating a cryogenic distillation column using a controlled refrigeration zone section can be reduced by approximately 25% to approximately 75%.

[0099] Figure 6 An exemplary integrated separation and regasification system 603 is shown. As shown, system 603 generally includes components of the LNG regasification system 502 and components of the separation system 201. It should be understood that the following discussion is equally applicable to any separation system, including any separation systems 101, 201, 301, 401. However, for simplicity, only the separation system 201 will be discussed in detail. As with the separation system 201, the integrated system 603 may include a dehydration unit 261. The feed stream 10 (e.g., an acid gas feed stream) may enter the dehydration unit 261 before entering the heat exchanger 600 as the feed stream 11. The dehydration unit 261 dehydrates the feed stream 10 to a sufficiently low dew point to ensure that a separate aqueous phase is not formed at any point downstream during the remainder of the process. The dehydration unit 261 may be any suitable dehydration mechanism, such as a molecular sieve or a glycol dehydration unit. In some embodiments, such as when the feed stream 10 already has a sufficiently low dew point, the dehydration unit 261 may be omitted.

[0100] Similar to separation system 201, integrated system 603 may include heat exchanger 600. Feed stream 11 may enter heat exchanger 600 before entering distillation column 204. Feed stream 11 may be cooled within heat exchanger 600 to a temperature suitable for introduction into distillation column 204 (e.g., about -62°C to about -35°C (about -80°F to about -30°F), or more specifically, about -51°C (-60°F)). Upon exiting heat exchanger 600, feed stream line 12 may extend to the exterior surface of distillation column 204 before entering the distillation column. The cooling fluid stream for heat exchanger 600 may be provided by regasification system 502. For example, liquid LNG (at a temperature of about -170°C to about -30°C, or more specifically, about -162°C) may be delivered to heat exchanger 600 via line 64. Liquid LNG in line 64 from storage tank 510 may be used as the cooling fluid stream for feed stream 11. In other words, feed stream 11 can be used as a heat source to assist in vaporizing the liquid LNG in line 64. Therefore, heat exchanger 600 can also be used as and / or referred to as vaporizer 631. Liquid LNG can be partially converted into gaseous LNG at vaporizer 631. In some embodiments, pipeline 65 returns both liquid LNG and gaseous LNG to storage tank 510. In some embodiments, storage tank 510 and / or its associated components can utilize any gaseous LNG from line 65 as fuel. For example, storage tank 510 can be located on a ship, and the gaseous LNG from line 65 can be used as fuel for the ship's engines. As another example, storage tank 510 can utilize associated pumps, compressors, and / or condensers, and the gaseous LNG from line 65 can be used as fuel for the associated pumps, compressors, and / or condensers.

[0101] In some embodiments, the liquid LNG in lines 64 and 65 can cool an intermediate cooling medium (e.g., ethane, propane, a chlorofluorocarbon refrigerant such as R-134A), and the intermediate cooling medium can then be used as the cooling fluid in heat exchanger 600. For example, the intermediate cooling medium can be contained in a closed refrigerant circuit with an intermediate heat exchanger between the liquid LNG in lines 64 and 65 and the intermediate cooling medium. In some embodiments, the liquid LNG in line 64 can be pumped to delivery pressure before being delivered to heat exchanger / vaporizer 600 / 631.

[0102] Similar to separation system 201, integrated system 603 may include line 14 for a vapor stream exiting upper section 110 of distillation column 204. Line 14 may emanate from an upper portion of upper section 110. Line 14 may extend from an outer surface of upper section 110. From line 14, the vapor stream may enter heat exchanger 622. Heat exchanger 622 cools the vapor stream to form a cooling stream, which exits heat exchanger 622 via line 15. Heat exchanger 622 at least partially condenses the vapor stream. The cooling fluid stream for heat exchanger 622 may be provided by regasification system 502. For example, liquid LNG (at a temperature of about -170°C to about -30°C, or more specifically, about -162°C) may be delivered to heat exchanger 622 via line 62. The liquid LNG in line 62 may serve as a cooling fluid stream for the vapor stream in line 14. In other words, the vapor stream in line 14 can be used as a heat source to assist in vaporizing the liquid LNG in line 62. Thus, heat exchanger 622 can also be used and / or referred to as vaporizer 632. The liquid LNG can be at least partially converted to gaseous LNG at vaporizer 632. In some embodiments, line 63 conveys both the liquid LNG and the gaseous LNG from vaporizer 632 to line 15 to be combined with the cooled stream from heat exchanger 622. In some embodiments (not shown), line 63 conveys both the liquid LNG and the gaseous LNG from vaporizer 632 to the output product in line 16 to be combined with the separated vapor stream from separator 124.

[0103] A combined stream comprising the cooled stream from heat exchanger 622 and the liquid LNG and gaseous LNG from vaporizer 632 may be passed through line 15 to enter separator 124. Separator 124 separates the combined stream into a liquid stream and a vapor stream. The separator may be any suitable separator capable of separating the combined stream into a liquid stream and a vapor stream, such as a reflux drum. Once separated, the separated vapor stream may exit separator 124 as an output product. The output product may be passed through line 16 for subsequent gas transport (e.g., via a pipeline) and / or condensed into LNG. Once separated, the separated liquid stream may be returned to upper section 110 via line 18 as reflux. The reflux may be passed to upper section 110 via any suitable mechanism (e.g., a reflux pump 150 and / or gravity). Note that, unlike the reflux of separation system 201, the reflux of integrated system 603 may include liquid originating from storage tank 510 as LNG. In some embodiments, separator 124 and / or its associated components can utilize as fuel any gaseous LNG from line 15. For example, separator 124 can utilize associated pumps, compressors, and / or condensers, and gaseous LNG from line 15 can serve as fuel for the associated pumps (e.g., reflux pump 150), compressors, and / or condensers.

[0104] In some embodiments, the output product in line 16 may contain a fractional amount of CO2 within a specified range (e.g., from about 1.5% to about 2.5%, or more particularly, from about 1.9% to about 2.1%). For example, the heat exchanger / vaporizer 622 / 632 and / or the separator 124 may be used to produce a mixture of the vapor stream in line 14 and the liquid / gas LNG in line 63, resulting in the output product in line 16 having a fractional amount of CO2 within a specified range. For example, the set point and / or operating parameters of the distillation column 204 may be specified to control the separation efficiency, thereby affecting the amount of CO2 in the vapor stream in line 14. As another example, the flow rate of the liquid LNG in line 62 may be controlled to affect the amount of CO2 in the vapor stream in line 14. As another example, a slip stream of LNG may be withdrawn from the storage tank 510, vaporized, and mixed with the output product in line 16 to dilute the CO2 content. Any or all of these techniques may be used in various embodiments to influence the amount of CO 2 fraction in the output product in line 16 .

[0105] Figure 7 Another exemplary integrated separation and regasification system 703 is shown. Like the integrated system 603, the integrated system 703 can include a dehydration unit 261. The feed stream 10 (e.g., an acid gas feed stream) can enter the dehydration unit 261 before entering the heat exchanger 600 as the feed stream 11. The dehydration unit 261 dehydrates the feed stream 10 to a sufficiently low dew point to ensure that a separate aqueous phase is not formed at any point downstream during the remainder of the process. The dehydration unit 261 can be any suitable dehydration mechanism, such as a molecular sieve or a glycol dehydration unit. In some embodiments, for example, when the feed stream 10 already has a sufficiently low dew point, the dehydration unit 261 can be omitted.

[0106] Similar to the integrated system 603, the integrated system 703 may include a heat exchanger 600. The feed stream 11 may enter the heat exchanger 600 before entering the distillation column 204. The feed stream 11 may be cooled within the heat exchanger 600 to a temperature level suitable for introduction into the distillation column 204 (e.g., about -62°C to about -35°C (about -80°F to about -30°F), or more particularly about -51°C (-60°F). Upon exiting the heat exchanger 600, the feed stream line 12 may extend into the outer surface of the distillation column 204 before entering the distillation column. The cooling fluid stream for the heat exchanger 600 may be provided by liquid LNG. For example, liquid LNG (at a temperature of about -170°C to about -30°C, or more particularly about -162°C) may be provided by Line 72 delivers from storage tank 510 to heat exchanger 600. The liquid LNG in line 72 can be used as a cooling fluid stream for feed stream 11. In other words, feed stream 11 can be used as a heat source to assist in vaporizing the liquid LNG in line 72. Therefore, heat exchanger 600 can also be used as and / or referred to as vaporizer 631. Pump 520 can draw liquid LNG from storage tank 510 via line 71. Pump 520 can then direct the liquid LNG to vaporizer 631 via line 72. The liquid LNG can be at least partially converted to gaseous LNG at vaporizer 631. In some embodiments, line 73 delivers both liquid LNG and gaseous LNG to the upper section 110 of the distillation column 204. The LNG from line 73 can assist in cooling the upper section 110 and any fluids therein. For example, the LNG from line 73 can cool a vapor stream that rises in the intermediate controlled freezing zone section 108 and does not form solids or otherwise fall to the bottom of the intermediate controlled freezing zone section 108. Additionally, the LNG from line 73 can cool the upper section 110, separating the methane from the contaminants. Compared to integrated system 603, integrated system 703 can utilize only LNG from line 73 to cool upper section 110, thereby eliminating condenser 122, heat exchanger 622, separator 124, reflux pump 150, and / or any associated piping. In some embodiments, distillation column 204 and / or its associated components can utilize any gaseous LNG from line 73 as fuel. For example, distillation column 204 can utilize associated pumps, compressors, and / or condensers, and gaseous LNG from line 73 can be used as fuel for the associated pumps, compressors, and / or condensers.

[0107] Figure 8Another exemplary integrated separation and regasification system 804 is shown. As with integrated systems 603 and 703, integrated system 804 can both separate contaminants from a gas feed stream and regasify LNG. For integrated system 804, the input gas feed stream 80 can have a CO2 concentration of about 2% to about 70%. For example, the input gas feed stream 80 can be flue gas (e.g., the output of a power plant). As another example, the input gas feed stream 80 can be an associated gas having a slightly lower CO2 concentration than the input feed streams applicable to integrated systems 603 and 703. A filter system 840 (e.g., comprising a membrane filter or a solvent filter) can separate the feed stream 80 into a natural gas stream 81 and a CO2 concentrate stream 82.

[0108] The natural gas stream 81 may include water vapor and hydrocarbon components (e.g., ethane, methane). The dehydration unit 261 may dehydrate the natural gas stream 81 to a sufficiently low dew point to ensure that a separate water phase is not formed at any point downstream. The dehydration unit 261 may be any suitable dehydration mechanism, such as a molecular sieve or a glycol dehydration unit. In some embodiments, for example, when the natural gas stream 81 already has a sufficiently low dew point, the dehydration unit 261 may be omitted. The dehydrated stream 83 may leave the dehydration unit 261 as an output product. The output product may be passed through line 16 for subsequent sale to a pipeline and / or condensation into LNG.

[0109] It is currently believed that pumping liquid CO2 may require about 50% to about 80% less injection horsepower than pumping gaseous CO2. Therefore, in preparation for storage and / or transportation, the CO2 concentrate stream 82 can be compressed in compressor 850 to form a compressed feed stream 84, and the feed stream 84 can then be cooled in heat exchanger 823 to form a cooling stream 85. The cooling stream 85 may include liquid CO2. The heat exchanger 823 can be a condenser. The heat exchanger 823 can output the cooling stream 85 at a temperature of about -57°C (-70°F) and a pressure greater than about 80 psia. The liquid CO2 pump 870 can then pump the cooling stream 85 through pipeline 86 to a storage and / or transportation facility 880 (e.g., an injection well).

[0110] The cooling fluid stream for heat exchanger 823 can be provided by liquid LNG. For example, liquid LNG (at a temperature of about -170°C to about -30°C, or more particularly about -162°C) can be transported from storage tank 510 to heat exchanger 823 via pipeline 72. The liquid LNG in pipeline 72 can be used as a cooling fluid stream for feed stream 84. In other words, feed stream 84 can be used as a heat source to assist in vaporizing the liquid LNG in line 72. Therefore, heat exchanger 823 can also be used as and / or referred to as vaporizer 833. Pump 520 can extract liquid LNG from storage tank 510 via pipeline 71. Pump 520 can then direct the liquid LNG to vaporizer 833 via pipeline 72. The liquid LNG can be at least partially converted into gaseous LNG at vaporizer 833. In some embodiments, line 87 conveys both liquid LNG and gaseous LNG from vaporizer 833 to line 16 for combination with dehydrated stream 83. The combined stream comprising the dehydrated stream from dehydration unit 261 and the liquid LNG and gaseous LNG from vaporizer 833 can be passed as output products through line 16. The output products can be passed through line 16 for subsequent gas delivery (e.g., by pipeline) and / or condensed into LNG.

[0111] In some embodiments, the integrated separation and regasification system can include a distillation column juxtaposed with the LNG regasification terminal. For example, the cold energy from vaporizing the LNG can be used instead of the refrigeration in the distillation process to separate pollutants (e.g., CO2, H2S) from the acid gas feed. In some embodiments, the heat exchanger used to vaporize the LNG can be shared as a cooling component of a controlled freezing zone system. In some embodiments, all independent refrigeration and heat exchangers for the separation system can be omitted and replaced by shared heat exchangers. In some embodiments, the integrated system can be located onshore. For example, the integrated system can be located within about 300 km to about 500 km of the production site. As another example, the integrated system can be located within about 300 km to about 500 km of a combustion plant that emits acid gases as waste. In some embodiments, the integrated system can be deployed on a floating vessel at sea. In some embodiments, the integrated system can be constructed to move between different CO2-containing production sites.

[0112] The disclosed aspects can be used in hydrocarbon management activities. As used herein, "hydrocarbon management" or "managing hydrocarbons" includes hydrocarbon extraction, hydrocarbon production, hydrocarbon exploration, identifying potential hydrocarbon resources, identifying well locations, determining well injection and / or extraction rates, identifying reservoir connectivity, acquiring, disposing of, and / or abandoning hydrocarbon resources, reviewing previous hydrocarbon management decisions, and any other hydrocarbon-related actions or activities. The term "hydrocarbon management" also applies to the injection or storage of hydrocarbons or CO2, such as CO2 sequestration, as well as reservoir assessment, development planning, and reservoir management. The disclosed methods and techniques can be used to produce hydrocarbons from a feed stream extracted from, for example, a subterranean region. The extracted feed stream can be processed and separated into hydrocarbons and contaminants in a distillation column 104, 204. The separated hydrocarbons can exit the intermediate controlled freezing zone section 108 or the upper section 110 of the distillation column. Some or all of the exiting hydrocarbons are produced. Hydrocarbon extraction can be performed to remove the feed stream from, for example, a subterranean region. This can be accomplished by drilling a well using oil well drilling equipment. Equipment and techniques for drilling and / or extracting hydrocarbons are well known to those skilled in the relevant art. Other hydrocarbon extraction activities, and more generally, other hydrocarbon management activities, may be performed according to known principles.

[0113] It should be understood that many changes, modifications, and substitutions may be made to the foregoing disclosure without departing from the scope of the present disclosure. Therefore, the foregoing description is not intended to limit the scope of the present disclosure. On the contrary, the scope of the present disclosure is determined solely by the appended claims and their equivalents. It is also contemplated that the structures and features of the present embodiments may be changed, rearranged, replaced, deleted, copied, combined, or added to one another.

[0114] Additionally or alternatively, the present invention relates to:

[0115] Embodiment 1: An integrated system comprising: an assembly for separating contaminants from an input feed stream; a heat exchanger coupled to a first pipeline, wherein: the first pipeline is coupled to the assembly for separating contaminants, and the heat exchanger is configured to cool a first feed stream of the first pipeline; and a liquefied natural gas ("LNG") regasification system including a vaporizer, wherein: the vaporizer is configured to heat an LNG stream of the LNG regasification system, and the heat exchanger functions as the vaporizer.

[0116] Embodiment 2: The integrated system of Embodiment 1, wherein the component for separating the contaminants comprises a cryogenic distillation column.

[0117] Embodiment 3: An integrated system of embodiment 2, wherein the cryogenic distillation tower comprises: a distillation section that allows vapor to rise upward therefrom; one or more pipelines for directing an input feed stream into the cryogenic distillation tower; a controlled freezing zone section located above the distillation section, the controlled freezing zone being constructed and arranged to form a solid from the input feed stream, the controlled freezing zone section comprising a spray assembly in an upper section of the controlled freezing zone and a melting tray assembly in a lower section of the controlled freezing zone, wherein the melting tray assembly comprises: at least one vapor stream riser that directs vapor from the distillation section into liquid retained by the melting tray assembly, and one or more discharge openings positioned to allow a portion of the liquid retained by the melting tray assembly to exit the controlled freezing zone section; a tower heat exchanger arranged to heat the portion of the liquid by indirect heat exchange with a heating fluid; and one or more return inlets for returning the portion of the liquid to the melting tray assembly after the portion of the liquid has been heated in the tower heat exchanger.

[0118] Embodiment 4: The integrated system of any of Embodiments 1-3, wherein the pollutant comprises carbon dioxide.

[0119] Embodiment 5: The integrated system of any of Embodiments 2-4, wherein the first line directs the first feed stream from the heat exchanger to the cryogenic distillation column.

[0120] Embodiment 6: The integrated system of any of Embodiments 2-4, wherein the first line directs the first feed stream from the cryogenic distillation column to the heat exchanger.

[0121] Embodiment 7: The integrated system of any one of Embodiments 2-6, further comprising a second heat exchanger coupled to the second pipeline, wherein: the second pipeline is coupled to a cryogenic distillation tower, the second heat exchanger cools a second feed stream of the second pipeline, the LNG regasification system further comprises a second vaporizer, the second vaporizer heats a second LNG stream of the LNG regasification system, the second heat exchanger serves as a second vaporizer, the first pipeline directs the first feed stream from the heat exchanger to the cryogenic distillation tower, and the second pipeline directs the second feed stream from the cryogenic distillation tower to the second heat exchanger.

[0122] Embodiment 8: The integrated system of Embodiment 7, further comprising: a storage tank of the LNG regasification system; a first LNG pipeline directing an LNG stream from the storage tank to the vaporizer; and a second LNG pipeline directing a second LNG stream from the storage tank to the second vaporizer.

[0123] Embodiment 9: The integrated system of any one of Embodiments 2-6, further comprising: a storage tank of the LNG regasification system; and an LNG pipeline directing the LNG stream from the storage tank to the vaporizer.

[0124] Embodiment 10: The integrated system of embodiment 9, further comprising a pump between the storage tank and the vaporizer.

[0125] Embodiment 11: The integrated system of Embodiment 9 or 10, further comprising a second LNG line directing the output from the vaporizer to a storage tank.

[0126] Embodiment 12: The integrated system of Embodiment 2 further comprising: a separator, wherein: the output from the vaporizer is directed to the separator, and the output from the heat exchanger is directed to the separator; and a reflux pump, wherein: the non-gaseous output from the separator is directed to the reflux pump, and the output from the reflux pump is directed to the cryogenic distillation column.

[0127] Embodiment 13: The integrated system of Embodiment 12, wherein the gaseous output of the separator is directed to an output line as the output product.

[0128] Embodiment 14: The integrated system of any of Embodiments 2-4, wherein: a first pipeline directs the first feed stream from the heat exchanger to a cryogenic distillation column, the output from the vaporizer is directed to the cryogenic distillation column, and the gaseous output of the cryogenic distillation column is directed to an output pipeline as an output product.

[0129] Embodiment 15: The integrated system of Embodiment 1, wherein: the component for separating the contaminants comprises a filter system, the contaminants comprise carbon dioxide, the first line comprises a first carbon dioxide line, and the first feed stream comprises a first carbon dioxide stream.

[0130] Embodiment 16: The integrated system of Embodiment 15, wherein a first carbon dioxide line directs the first carbon dioxide stream from the filter system to the heat exchanger.

[0131] Embodiment 17: The integrated system of Embodiment 15, further comprising a compressor coupled to the first carbon dioxide line between the filter system and the heat exchanger.

[0132] Embodiment 18: The integrated system of any one of Embodiments 15-17, further comprising: a liquid carbon dioxide pump; and a second carbon dioxide pipeline coupled to the heat exchanger and the liquid carbon dioxide pump.

[0133] Embodiment 19: The integrated system of any one of Embodiments 15-18, further comprising: a storage tank of the LNG regasification system; and an LNG pipeline directing the LNG stream from the storage tank to the vaporizer.

[0134] Embodiment 20: The integrated system according to embodiment 19 further includes an LNG pump between the storage tank and the vaporizer.

[0135] Embodiment 21: The integrated system of any of Embodiments 15-20, wherein the gaseous output of the filter system is directed to an output line as an output product.

[0136] Embodiment 22: The integrated system of Embodiment 21, further comprising a dehydration unit between the filter system and the output line.

[0137] Embodiment 23: The integrated system of Embodiment 21 or 22, wherein the gaseous output of the vaporizer is directed to the output line as the output product.

[0138] Embodiment 24: A method comprising: separating contaminants from an input feed stream using an assembly for separating contaminants; cooling the first feed stream using a heat exchanger, wherein the heat exchanger is coupled to the assembly for separating contaminants; and heating the LNG stream using a vaporizer of an LNG regasification system, wherein the heat exchanger acts as the vaporizer.

[0139] Embodiment 25: The method of Embodiment 24, wherein separating the contaminants comprises cryogenically separating the contaminants, and the assembly for separating the contaminants comprises a distillation column.

[0140] Embodiment 26: The method of Embodiment 25, wherein cryogenic separation of contaminants comprises: directing an input feed stream to a distillation tower; allowing vapor to rise upward from a distillation section of the distillation tower; forming a solid in a controlled freezing zone section of the distillation tower, the controlled freezing zone section being located above the distillation section, wherein the solid comprises the contaminants in the input feed stream; directing vapor from the distillation section into liquid retained by a melting tray assembly using at least one vapor stream riser; melting the solid using the liquid retained by the melting tray assembly; allowing a portion of the liquid retained by the melting tray assembly to exit the controlled freezing zone section; heating the portion of the liquid by indirect heat exchange with a heating fluid in a tower heat exchanger; and returning the portion of the liquid to the melting tray assembly after the liquid has been heated in the tower heat exchanger.

[0141] Embodiment 27: The method of any of Embodiments 24-26, wherein the pollutant comprises carbon dioxide.

[0142] Embodiment 28: The method of any of Embodiments 25-27, wherein cooling the first feed stream precedes cryogenic separation of contaminants.

[0143] Embodiment 29: The method of any of Embodiments 25-27, wherein cryogenically separating the contaminants precedes cooling the first feed stream.

[0144] Embodiment 30: The method of any one of Embodiments 25-29, further comprising: cooling the second feed stream using a second heat exchanger; and heating the second LNG stream using a second vaporizer of the LNG regasification system, wherein: the second heat exchanger is connected to the distillation tower, cooling the first feed stream precedes cryogenic separation of contaminants, cryogenic separation of contaminants precedes cooling the second feed stream, and the second heat exchanger acts as a second vaporizer.

[0145] Embodiment 31: The method of Embodiment 30, further comprising: directing an LNG stream from a storage tank of the LNG regasification system to a vaporizer; and directing a second LNG stream from the storage tank to a second vaporizer.

[0146] Embodiment 32: The method of any of Embodiments 25-29, further comprising directing the LNG stream from a storage tank of the LNG regasification system to the vaporizer.

[0147] Embodiment 33: The method of Embodiment 32, wherein directing the LNG stream from the storage tank to the vaporizer comprises pumping the LNG stream with a pump coupled between the storage tank and the vaporizer.

[0148] Embodiment 34: The method of Embodiment 32 or 33, further directing the output from the vaporizer to a storage tank.

[0149] Embodiment 35: The method of Embodiment 25, further comprising: separating the output from the vaporizer and the output from the heat exchanger into an output product stream and a reflux stream; and directing the reflux stream to the cryogenic distillation column.

[0150] Embodiment 36: The method of Embodiment 35, wherein directing the reflux to the cryogenic distillation column comprises pumping the reflux stream with a reflux pump.

[0151] Embodiment 37: The method of Embodiment 35 or 36, wherein the reflux stream comprises a non-gaseous stream.

[0152] Embodiment 38: The method of any of Embodiments 35-37, wherein the output product stream comprises CO2 in a fractional amount ranging from 1.5% to 2.5%.

[0153] Embodiment 39: The method of any of Embodiments 25-27, wherein cooling the first feed stream precedes cryogenic separation of the contaminants; the method further comprising: directing the output from the vaporizer to a cryogenic distillation column; and producing an output product stream comprising the gaseous output of the cryogenic distillation column.

[0154] Embodiment 40: The method of Embodiment 39, wherein the output product stream comprises CO2 in a fractional amount ranging from 1.5% to 2.5%.

[0155] Embodiment 41: The method of Embodiment 24, wherein: the contaminants comprise carbon dioxide, the assembly for separating the contaminants comprises a filter system, and the first feed stream comprises a first carbon dioxide stream.

[0156] Embodiment 42: The method of Embodiment 41, further comprising compressing the first carbon dioxide stream.

[0157] Embodiment 43: The method of Embodiment 41 or 42, wherein cooling the first carbon dioxide stream produces a liquid carbon dioxide stream, the method further comprising pumping the liquid carbon dioxide stream with a liquid carbon dioxide pump.

[0158] Embodiment 44: The method of any of Embodiments 41-43, further comprising directing the LNG stream from a storage tank of the LNG regasification system to the vaporizer.

[0159] Embodiment 45: The method of Embodiment 44, wherein directing the LNG stream from the storage tank to the vaporizer comprises pumping the LNG stream with an LNG pump coupled between the storage tank and the vaporizer.

[0160] Embodiment 46: The method of any of Embodiments 41-45, further comprising generating an output product comprising a gaseous output of the filter system.

[0161] Embodiment 47: The method of Embodiment 46, wherein generating the output product comprises dehydrating the gaseous output of the filter system.

[0162] Embodiment 48: The method of Embodiment 46 or 47, wherein the output product further comprises a gaseous output of the vaporizer.

[0163] Embodiment 49: The method of any of Embodiments 46-48, wherein the output product comprises CO2 in a fractional amount ranging from 1.5% to 2.5%.

Claims

1. An integrated system comprising: an assembly for separating contaminants from an input feed stream, the assembly for separating contaminants comprising a cryogenic distillation column, and the contaminants comprising carbon dioxide; a first heat exchanger coupled to the first pipeline, wherein: The first line is coupled to an assembly for separating contaminants, and a first heat exchanger cooling a first feed stream in a first line; and A liquefied natural gas ("LNG") regasification system comprising a storage tank and a first vaporizer, in: a first vaporizer heating an LNG stream received from a storage tank of an LNG regasification system via a first LNG pipeline, and The first heat exchanger acts as a first vaporizer; a second heat exchanger coupled to the second pipeline, in: The second pipeline is connected to a cryogenic distillation tower, a second heat exchanger cools a second feed stream in a second line, The LNG regasification system further includes a second vaporizer that heats a second LNG stream received from the storage tank of the LNG regasification system via a second LNG pipeline. The second heat exchanger acts as a second vaporizer, a first line directing the first feed stream from the first heat exchanger to a cryogenic distillation column, and a second line directing a second feed stream from the cryogenic distillation column to a second heat exchanger; and separator, in: directing the output from the second vaporizer to a separator, and directing the output from the second heat exchanger to a separator; and Reflux pump, in: The non-gaseous output from the separator is directed to a reflux pump, directing the output from the reflux pump to a cryogenic distillation column, and The gaseous output from the separator is directed to an output line as output product.

2. The integrated system of claim 1 , wherein the cryogenic distillation column comprises: a distillation section through which vapor is allowed to rise; one or more lines for directing an input feed stream to a cryogenic distillation column; a controlled freezing zone section located above the distillation section, the controlled freezing zone being constructed and arranged to form solids from the input feed stream, the controlled freezing zone section comprising: a spray assembly in the upper section of the controlled freezing zone, and A melting tray assembly in a lower section of the controlled freezing zone, wherein the melting tray assembly comprises: directing vapor from the distillation section to at least one vapor stream riser into the liquid retained by the melt tray assembly, and one or more discharge openings positioned to allow a portion of the liquid retained by the melt tray assembly to exit the controlled freezing zone section; a tower heat exchanger arranged to heat the portion of the liquid by indirect heat exchange with a heating fluid; and The portion of liquid is returned to the one or more return inlets of the melting tray assembly after it has been heated in the tower heat exchanger.

3. The integrated system according to claim 1 or claim 2, further comprising: LNG pump between the storage tank and the first vaporizer.

4. A method for separating contaminants from an input feed stream, comprising: separating contaminants from an input feed stream using an assembly for separating contaminants, wherein the assembly for separating contaminants comprises a cryogenic distillation column, separating the contaminants comprises cryogenically separating the contaminants, and the contaminants comprise carbon dioxide; cooling the first feed stream using a first heat exchanger, wherein the first heat exchanger is coupled to an assembly for separating contaminants; delivering an LNG stream from a storage tank of an LNG regasification system via a first LNG pipeline; heating the LNG stream using a first vaporizer of an LNG regasification system, wherein the first heat exchanger serves as the first vaporizer for the LNG system, obtaining a second feed stream from a cryogenic distillation column; cooling the second feed stream using a second heat exchanger; and heating a second LNG stream received from an LNG regasification storage tank via a second LNG pipeline using a second vaporizer of the LNG regasification system, in: The second heat exchanger is connected to the cryogenic distillation column, Cooling the first feed stream prior to cryogenic separation of contaminants, Cryogenically separating the contaminants prior to cooling the second feed stream, and The second heat exchanger acts as a second vaporizer, and A second line directs a second feed stream from the cryogenic distillation column to a second heat exchanger, separating the output from the first vaporizer, the output from the first heat exchanger, the output from the second vaporizer, and the output from the second heat exchanger into an output product stream and a reflux stream; and The reflux stream is directed to a reflux pump and then to a cryogenic distillation column.

5. The method according to claim 4, wherein the cryogenic separation of pollutants comprises: directing an input feed stream to a cryogenic distillation column; Allowing vapor to rise upward from the distillation section of a cryogenic distillation column; forming solids in a controlled freezing zone section of a cryogenic distillation column, the controlled freezing zone section being located above the distillation section, wherein the solids comprise contaminants in the input feed stream; directing vapor from the distillation section into the liquid retained by the melt tray assembly using at least one vapor stream riser; melting the solid using the liquid retained by the melt tray assembly; allowing a portion of the liquid retained by the melt tray assembly to exit the controlled freezing zone section; heating the portion of the liquid by indirect heat exchange with a heating fluid in a tower heat exchanger; and After the liquid has been heated in the tower heat exchanger, a portion of the liquid is returned to the melt tray assembly.

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