Patent Application
20240318909
The invention relates to methods for increasing ethane and non-freezing heavier hydrocarbons recovery in natural gas streams for the liquefaction of natural gas to form liquefied natural gas (LNG), and in particular, utilizing scrub columns to treat the natural gas feedstreams.
In conventional LNG plants, heat transfer for cooling a natural gas feed stream (or feed gas) sufficiently to form a liquid is conducted in heat exchangers. Natural gas can contain a wide range of compositions of undesirable species which are capable of forming solids during the cryogenic process of liquefying natural gas. Such species are referred to as “freezable species” and the solids formed of the freezable species are referred to as “freezable solids”.
Freezable species and other contaminants which are not removed prior to entering the cryogenic LNG cooling vessel precipitate and accumulate on the cold surfaces of the heat exchangers and other equipment, eventually rendering these items inoperable. When fouling has reached a sufficient level, the cooling vessel must be taken off-line for the fouling to be removed. In the process, the cooling vessel, baffles or pipework can be damaged which only encourages further fouling in the next production cycle. Moreover, solids condensing on metal surfaces form an insulating film reducing thermal efficiency of the heat exchanger.
Typically, a pre-treatment of the natural gas is required to remove the freezable species and other contaminants prior to the natural gas feed stream being directed to the cooling stages to cause liquefaction. In a typical natural gas, the CO2 composition can range between 0.5% to 30% and can be as high as 70%. In a conventional LNG facility, the level of CO2 present in the natural gas is typically reduced down to the level of 50 to 125 ppm prior to the natural gas feed stream being directed to liquefaction. Another of the freezable species, namely hydrogen sulphide (H2S), is normally removed down to a level of 3.5 mg/Nm3 prior to the natural gas feed stream being allowed to enter the liquefaction stage. One of the methods typically used to remove the freezable species and other contaminants from the natural gas feed stream is a chemical reaction using reversible absorption processes such as absorption with an amine solvent.
In addition, the manufacturing of LNG, feed gas is required to be conditioned to remove heavy hydrocarbons which would freeze under cryogenic condition such as aromatics and long chain alkanes. Heavy hydrocarbons (typically C5+) are typically partially removed along with water. Where further removal is required, a cryogenic distillation column is required, with cooling provided from the main refrigerant cycle. This can be an expensive and a complex process, especially if the removed components are required for refrigerant make-up in a Mixed Refrigerant (MR) cycle.
For MR based technology, such as propane precooled mixed refrigerant technology or dual mixed refrigerant technology, when MR components such as C2/C3/C4 are required to be is produced for making up MR loss in the refrigerant loop, the gas conditioning can involve deep Natural Gas Liquid (NGL) recovery which not only removes freezing heavies but also extracts C2 and Liquefied Petroleum Gas (LPG) to generate MR makeups via the downstream deethanizer, depropanizer and debutanizer. However, when MR components can be made up from other resources such as existing C2/C3/C4 streams in “brownfield” expansion projects (i.e., existing plants) or external importing where logistics are convenient or it is critical to simplify downstream processing, it is desired to minimize non-freezing C2+ slip to the scrub column bottom but ideally only targeting to remove freezing heavies. Also, when feed gas composition changes, e.g., from rich to lean and/or higher benzene to lower benzene, the required condenser temperature will require a change accordingly to generate sufficient reflux to meet the heavy (freezing) component specifications in the scrub column overhead stream.
For lean gas, a typical scrub system is composed of three levels of C3 refrigerant to pre-cool feed to −34° C., and then use MR cooling to generate reflux for the scrub column. Methane is the main component of natural gas, usually accounting for 70%-90% of the total volume produced. As used herein, “lean gas” refers to Natural Gas that contains a few or no liquefiable liquid hydrocarbons, wherein gas typically composes of 90% or higher methane. Reboiler is used at the bottom to generate stripping gas.
As shown in
While for richer gas, a typical scrub system is composed of two levels of C3 refrigerant. It uses LLP (Low Pressure) C3 for reflux generation and reboiler is used to generate stripping gas. As used herein, “rich gas” refers to a gas containing heavier hydrocarbons than a lean gas, where the gas is typically composed of lower than 90% methane. When there is a necessity to switch between a lean gas configuration and a rich gas configuration, the design of selection often goes with the configuration in
In
Background references include U.S. Pat. Nos. 4,445,916, 5,325,673, and 6,401,486; U.S. Patent Application Nos. 2005/0072186; 2012/0060552; 2019/0376740; and WO 2006/123240 and WO 2014/022510.
Therefore, there is a need to optimize a scrub column configuration to maximize C2+ recovery to an LNG stream in a scrub column while meeting heavy (freezing) component requirements in the scrub column overhead stream, and ideally at the same time possessing the flexibility to handle different feed gas compositions. Such improvements would simplify and/or reduce the size of the downstream stabilization system, leading to cost savings and energy savings.
In a class of embodiments, the invention provides for a method for operating a hydrocarbon removal system, the method comprising the steps of: (a) separating at least a portion of a natural gas stream to produce a split stream and a separated natural gas stream; (b) cooling at least a portion of the separated natural gas feed stream in one or more heat exchangers to form a pre-cooled feed stream; (c) feeding the pre-cooled feed stream into a column, the column comprising an upper section, a mid-section, and a lower section; (d) separating a methane-rich overhead stream and a bottom stream from a C5+ hydrocarbon-rich mixture in the upper section of the column; (e) cooling the methane-rich overhead stream in a first heat exchanger to produce a first cooled methane-rich stream; (f) subsequently, (i) feeding the first cooled methane-rich stream to a reflux drum to produce a reflux stream; and/or (ii) feeding the first cooled methane-rich stream to a Main Cryogenic Heat Exchanger (MCHX) to produce a second cooled methane-rich stream, and feeding the second cooled methane-rich stream to the reflux drum to produce a second overhead stream that is essentially free of heavy hydrocarbons.
In another class of embodiments, the invention provides for a method for operating a hydrocarbon removal system, the method comprising the steps of: (a) separating at least a portion of a natural gas stream to produce a split stream and a separated natural gas stream; (b) cooling at least a portion of the separated natural gas feed stream in a single heat exchanger to form a pre-cooled feed stream; (c) feeding the pre-cooled feed stream into a column, the column comprising an upper section, a mid-section, and a lower section; (d) separating a methane-rich overhead stream and a bottom stream from a C5+ hydrocarbon-rich mixture in the upper section of the column; (e) cooling the methane-rich overhead stream in the single heat exchanger to produce a two-phase stream; (f) feeding the two-phase stream into a reflux drum to produce a second overhead stream and a reflux stream; and (g) feeding the second overhead stream into a Main Cryogenic Heat Exchanger (MCHX) of a liquefaction system comprising at least two cooling cycles to produce Liquefied Natural Gas (LNG).
Other embodiments and variations are disclosed herein.
Various specific aspects, embodiments, and versions will now be described, including definitions adopted herein. Those skilled in the art will appreciate that such aspects, embodiments, and versions are exemplary only, and that the invention can be practiced in other ways. Any reference to the “invention” may refer to one or more, but not necessarily all, of the embodiments defined by the claims. The use of headings is for purposes of convenience only and does not limit the scope of the present invention. For purposes of clarity and brevity, similar reference numbers in the several Figures represent similar items, steps, or structures and may not be described in detail in every Figure.
All numerical values within the detailed description and the claims herein are modified by “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.
As used herein, “cooling” broadly refers to lowering and/or dropping a temperature and/or internal energy of a substance by any suitable, desired, or required amount. Cooling may include a temperature drop of at least about 1° C., at least about 5° C., at least about 10° C., at least about 15° C., at least about 25° C., at least about 35° C., or least about 50° C., or at least about 75° C., or at least about 85° C., or at least about 95° C., or at least about 100° C. The cooling may use any suitable heat sink, such as steam generation, hot water heating, cooling water, air, refrigerant, other process streams (integration), and combinations thereof. One or more sources of cooling may be combined and/or cascaded to reach a desired outlet temperature. The cooling step may use a cooling unit with any suitable device and/or equipment. According to some embodiments, cooling may include indirect heat exchange, such as with one or more heat exchangers. In the alternative, the cooling may use evaporative (heat of vaporization) cooling and/or direct heat exchange, such as a liquid sprayed directly into a process stream.
As used herein, the term “environment” refers to ambient local conditions, e.g., temperatures and pressures, in the vicinity of a process, for example, in the range between 60 and 75° F. or 15 and 25° C.
As used herein, the term “essentially free” refers to a heavy hydrocarbon concentration that is sufficiently low in a stream that does not freeze under cryogenic conditions.
As used herein, the term “external refrigerant” refers to a liquid, mixture, or other substances capable of cooling a material located exterior to streams that are processed to generate products. External refrigerants typically form closed loop cooling streams, rejecting heat to environment.
As used herein, the term “expanded external refrigerant” refers to an external refrigerant that has increased in volume due to a rise in pressure.
The term “gas” is used interchangeably herein with “vapor,” and is defined as a substance or mixture of substances in the gaseous state as distinguished from the liquid or solid state. Likewise, the term “liquid” means a substance or mixture of substances in the liquid state as distinguished from the gas or solid state.
A “heat exchanger” broadly means any device capable of transferring heat energy or cold energy from one medium to another medium, such as between at least two distinct fluids. Heat exchangers include “direct heat exchangers” and “indirect heat exchangers.” Thus, a heat exchanger may be of any suitable design, such as a co-current or counter-current heat exchanger, an indirect heat exchanger (e.g. a spiral wound heat exchanger or a plate-fin heat exchanger such as a brazed aluminum plate fin type), direct contact heat exchanger, shell-and-tube heat exchanger, spiral, hairpin, core, core-and-kettle, printed-circuit, double-pipe or any other type of known heat exchanger. “Heat exchanger” may also refer to any column, tower, unit or other arrangement adapted to allow the passage of one or more streams there through, and to affect direct or indirect heat exchange between one or more lines of refrigerant, and one or more feed streams.
As used herein, the term “heavy hydrocarbons” refers to hydrocarbons having more than four carbon atoms. Principal examples include pentane, hexane and heptane. Other examples include benzene, aromatics, etc.
As used herein, the term “natural gas” refers to a multi-component gas obtained from a crude oil well (associated gas) or from a subterranean gas-bearing formation (non-associated gas). The composition and pressure of natural gas can vary significantly. A typical natural gas stream contains methane (C1) as a significant component. The natural gas stream may also contain ethane (C2), higher molecular weight hydrocarbons, and one or more acid gases. The natural gas may also contain minor amounts of contaminants such as water, nitrogen, iron sulfide, wax, and crude oil.
As used herein, the term “separation device” or “separator” refers to any vessel configured to receive a fluid having at least two constituent elements and configured to produce a gaseous stream out of a top portion and a liquid (or bottoms) stream out of the bottom of the vessel. The separation device/separator may include internal contact-enhancing structures (e.g. packing elements, strippers, weir plates, chimneys, etc.), may include one, two, or more sections (e.g. a stripping section and a reboiler section), and/or may include additional inlets and outlets. Exemplary separation devices/separators include bulk fractionators, stripping columns, phase separators, scrub columns, and others.
As used herein, the term “scrub column” or “column” refers to a separation device used for the removal of heavy hydrocarbons from a natural gas stream. A natural gas scrub column, designed to separate freezable C5+ components from natural gas, typically reduces the burden to provide refrigeration and reboiler as well as greatly enhances C5+ separation efficiency when operated substantially as an absorber.
The construction and operation of a cryogenic gas processing facility, such as a liquefied natural gas (LNG) plant, requires a significant capital expenditure. While each processing step of the LNG production plant is important, the gas treatment section of the plant plays a critical role in treating the gas to meet its final specifications for the natural gas liquefaction unit. Typically, the specifications to be met are H2S removal to under 4 ppmv, CO2 to 50 ppmv, total sulfur under 30 ppmv as S, water to 0.1 ppmv, and mercury (Hg) to levels of 0.01 μg/Nm3.
In general, the raw gas from the well typically is first processed in a slug catcher. A slug catcher collects the largest liquid slugs expected from the upstream operation and then allows them to slowly drain to the downstream processing equipment.
The feed gas will then be processed in an acid gas removal unit. The acid gas removal unit primarily removes the acidic components such as hydrogen sulfide and carbon dioxide from the feed gas stream. The next step in the process is a molecular sieve unit which removes water (gas dehydration) and mercaptans, typically, followed by mercury removal.
Subsequently, the feed gas from this pre-treatment processing is introduced to a scrub column. The cryogenic distillation tower known as the scrub column or column is a crucial operation within an LNG processing train. The column's functions are to control the concentration of heavier hydrocarbons (C3+) in the vapor overheads product and maximize the recovery of hydrocarbon liquids in the bottoms product.
The feed point to the scrub column is selected in conjunction with temperature and composition similarity of the feed gas and a given location in the column. For example, the feed gas may be fed through a line under pressure to the column preferably as a vapor or at a high mass ratio of vapor to liquid C2-C4 components, e.g., more than 90 to 10. The feed gas is preferably at a relatively low feed point with respect to the column, i.e., there are more stages in the enriching section above the feed point than in the lower stripping section below the feed point, to effect removal of freezable C5+ components. The temperature of the feed gas line may be ambient temperature, for example, about 17° C. The pressure in the feed gas line generally ranges between about 3.5 MPa (500 psia) to about 14 MPa (2000 psia), and more preferably between about 3.5 MPa to about 7 MPa (1000 psia). It is known that the operating pressure in the column must be lower than the critical pressure of the gas mixture (the critical pressure of methane is 4.64 MPa (673 psia)) to enable phase separation based on boiling point differences of gas components to take place.
In some embodiments, the column is substantially operated in an absorption region, i.e., more C2-C4 components are obtained in the vapor product than in the bottoms line, and substantially all of the C5+ components are discharged to the bottoms line. Thus, the overhead vapor stream comprising primarily methane and C2-C4 components is taken from the column through a line in the overhead section. A portion of the overhead vapor is condensed by refrigeration cooler or partial condenser and collected in a separator. The condensed overhead stream is returned to the column to provide a reflux. The reflux liquid is thus essentially free of C5+ and absorbs C5+ components from the vapor stream rising in the column. If desired, one or more intercondensers can be operated, typically up to three intercondensers spaced between the feed point and the reflux line. The overhead partial condenser preferably operates at a temperature less than ambient to about −40° C. Suitable refrigerants include, for example, propane and Freon™ refrigerant. An overhead vapor product comprising less than about 1 ppm C6+ components is is removed for subsequent liquefaction in an LNG plant.
A bottoms liquid rich in C5+ components with a minor amount of C2-C4 components is removed at the bottom section of the column. A portion of the liquid is vaporized by the reboiler and returned to the column. A bottoms stream comprising a natural gas liquids (NGL) product is withdrawn for distribution.
In a class of embodiments, in general, the third feed/C3 chiller is located at the column overhead. The bypass line is used to fully bypass MCHX (Main Cryogenic Heat Exchanger) for richer gas operation and partially used for Condenser Temperature adjustment for leaner gas operation, so that the same configuration can process both lean and rich gas without over-chill feed stream, driving excess C2+ to the bottom of the column. Reboiler of the column can be replaced with stripping gas from part of warm feed as shown. As result, the downstream fractionation column can either use the same base configuration but with a reduced size or greatly simplified design depending on project considerations, plant fuel balance, etc. In addition to this flexibility, the advantages in energy and cost saving brought by this class of embodiments is discussed in more detail in Table 1 below.
In particular, with respect to
Furthermore, the concept may be applied to other MR based technology such as EMR (Enhanced Mixed Refrigerant) or other type of DMR (Dual Mixed Refrigerant) processes. In another class of embodiments, in general, the feed pre-cooling and reflux generation by a slip stream of WMR (Warm Mixed Refrigerant) is integrated in one HX (Heat Exchanger) such as plate-fine type exchange unit. In these embodiments, part of WMR is used to exchange heat with overhead stream from column to generate reflux. The reflux can be used alone or proportionally supplemented with condensate present in the feed gas. The exact proportion of reflux to condensate in the column feed is determined by several considerations including composition of the feed gas, LNG specification, desired LPG and/or C5+ recovery, energy costs, type of refrigeration system used in the LNG plant, and the like.
In class of embodiments, the pre-chilling of a feed stream 301 via pre-chillers 311 and 313 and the partial condensation of an overhead stream 315 via chiller 317 in
Continuing with
Following the heavy hydrocarbon removal step as discussed-above, stream 423 may be directed to the liquefaction system (denoted by a broken-line box in
The warm MR is primarily composed of ethane with lesser amounts of propane and iso-butane. The warm MR enters the MCHX 425 at 455 and then splits into multiple portions. Each portion provides cooling to the chilled pretreated gas stream, exits the MCHX 425, is reduced in pressure by valves 457, 466, 473, re-enters the MCHX 425 to provide further cooling to the chilled pretreated gas stream, and exits the heat exchanger to be directed to knock-out vessels 441, 463, 469, respectively. The output of knock-out vessels 469 and 463 are directed to the first two stages of a first compressor 431 to a pressure that is equal to or slightly higher than the operating pressure of knock-out vessel 441. The combined output of the first two stages of the first compressor is cooled in an ambient cooler 435 and directed to the knockout vessel 441. The output of the knock-out vessel 441 is directed to a third stage 445 of the first compressor, which is depicted schematically as being separate from compressor 431 and connected by a common shaft thereto. The output of the third stage 445 is cooled in an ambient cooler 449 and sent to a surge drum 453 that feeds the MCHX 425 with stream 455 and heat exchanger 409, thereby completing the Warm Mixed Refrigerant (WMR) cycle.
The composition of the cold MR is primarily methane with lesser amounts of ethane, nitrogen, and propane. The function of the cold MR, which enters the MCHX 425 at 495 and is evaporated at a single pressure level and is used to cool the pretreated gas stream 423 to cryogenic temperatures as well as to subcool itself. Cold MR exiting the MCHX 425 is collected in a knock-out drum 509 and expanded in a cryogenic expander 513, after which it re-enters the MCHX 425. The cold MR exiting the MCHX 425 the second time enters a knock-out vessel 479 and is then compressed in two stages in a second compressor 483 to a pressure sufficient to completely condense it against the WMR in the heat exchanger. The cold mixed refrigerant from the second compressor is cooled in ambient coolers 487, 493 before being directed to the inlet 495 of the MCHX 425, thereby completing the cold mixed refrigerant cycle.
Given lean natural gas streams low in C2+ components, or relatively richer natural gas feed where there is already a supply of C2-C4 components for refrigeration, the focus of pretreatment can shift from supplying ethane, propane and butane makeup gas to conventional LNG refrigeration systems to the removal of freezable C5+ components. Embodiments of the present invention has several advantages over conventional treatment schemes. In a conventional process, the chilled feed produces liquids which are stripped to remove light components from the bottoms product and heavy components are absorbed near the top of the column by the reflux. The feed temperature is optimally controlled and cooled in the column where the cooling is preferably provided by the overhead condenser. Consequently, more non-freezable C2-C5 components stay in the gaseous phase entering column while heavier freezable component preferentially condense out to greatly enhance freezable components' removal efficiency and recovery of non-freezable C2-C5 to overhead gas for LNG production. Significantly less ethane is condensed in comparison to the prior art, thus, reducing the need for refrigeration and reboiler. The overhead condenser can ordinarily be satisfied using readily available refrigerants from liquefaction refrigerant cycle(s).
Table 1 compares the refrigerant compressor power required to produce a nominal 3MTA LNG in identical hot climate conditions. For rich feed which employs a heavy hydrocarbon removal scheme, as illustrated in
Table 2 demonstrates the impact of employing a heavy hydrocarbon removal scheme as illustrated in
This application claims the priority benefit of U.S. Provisional Patent Application No. 63/203,289, filed Jul. 16, 2021, entitled systems and methods for systems and methods for systems and methods for METHODS FOR OPERATING HYDROCARBON REMOVAL SYSTEMS FROM NATURAL GAS STREAMS, the entirety of which is incorporated by reference herein.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2022/072897 | 6/13/2022 | WO |
| Number | Date | Country | |
|---|---|---|---|
| 63203289 | Jul 2021 | US |
