METHODS FOR OPERATING HYDROCARBON REMOVAL SYSTEMS FROM NATURAL GAS STREAMS

Abstract

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, are provided. Other independent variations of the methods are disclosed herein.

Claims

1. 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; and (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.

2. The method of claim 1, wherein the split stream is depressurized to a lower pressure to produce a stripping gas and the stripping gas is fed directly into the column.

3. The method of claim 2, wherein the split stream is depressurized utilizing at least one Joule-Thomson (JT) valve.

4. The method of claim 1, wherein the split stream is depressurized to a lower pressure using a reboiler to produce a stripping gas and the stripping gas is fed directly into the column.

5. The method of claim 2, wherein the stripping gas is fed into the lower section of the column.

6. The method of claim 1, wherein the stripping gas regulates methane slippage to the bottom of the column.

7. The method of claim 1, further comprising feeding the reflux stream into the column.

8. The method of claim 1, wherein the heat exchangers utilize an external refrigerant comprising propane.

9. (canceled)

10. (canceled)

11. The method of claim 1, further comprising feeding the second overhead stream to the MCHX to be liquefied under cryogenic conditions to produce a liquefied stream.

12. The method of claim 1, wherein the cooling of at least a portion of the separated natural gas feed stream and a generation of a reflux by the split stream is integrated in one heat exchanger.

13. (canceled)

14. The method of claim 1, wherein the method further comprises a CO2 removal step and/or a H2S removal step.

15. 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).

16. The method of claim 15, wherein the separated natural gas feed stream is depressurized to a lower pressure prior to the cooling.

17. The method of claim 16, wherein the separated natural gas feed stream is depressurized utilizing at least one Joule-Thomson (JT) valve.

18. The method of claim 15, wherein the separated natural gas feed stream is depressurized to a lower pressure using a reboiler.

19. The method of claim 15, wherein the method further comprises feeding the reflux stream into the column.

20. The method of claim 15, wherein the cooling cycles comprise a warm mixed refrigerant cycle and a cold mixed refrigerant cycle.

21. The method of claim 20, wherein the method comprises cooling the second overhead stream in the warm mixed refrigerant cycle to about ?100? F. (about ?73? C.).

22. The method of claim 21, wherein the method comprises cooling the second overhead stream in the cold mixed refrigerant cycle after the warm mixed refrigerant cycle to produce a cryogenic fluid.

23. (canceled)

24. The method of claim 15, wherein the warm mixed refrigerant cycle comprises a warm mixed refrigerant and the warm mixed refrigerant comprises propane, iso-butane and ethane.

25. (canceled)

26. The method of claim 15, wherein the cold mixed refrigerant cycle comprises a cold mixed refrigerant and the cold mixed refrigerant comprises methane, ethane, propane, and nitrogen.

27.-29. (canceled)

Description

BRIEF DESCRIPTION OF THE FIGURES

[0017] FIG. 1 is a schematic representation for a system including a scrub column configured for lean feed gas in accordance with the prior art.

[0018] FIG. 2 is a schematic representation for a system including a scrub column configured for rich feed gas in accordance with the prior art.

[0019] FIG. 3 is a schematic representation for a system including a scrub column configured in accordance with one class of embodiments of invention.

[0020] FIG. 4 is a schematic representation for a system including a scrub column configured in accordance with another class of embodiments of invention.

DETAILED DESCRIPTION OF THE INVENTION

[0021] 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.

[0022] 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.

[0023] 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.

[0024] 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.

[0025] 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.

[0026] 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.

[0027] As used herein, the term expanded external refrigerant refers to an external refrigerant that has increased in volume due to a rise in pressure.

[0028] 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.

[0029] 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.

[0030] 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.

[0031] 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 (C.sub.1) as a significant component. The natural gas stream may also contain ethane (C.sub.2), 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.

[0032] 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.

[0033] 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 C.sub.5+ components from natural gas, typically reduces the burden to provide refrigeration and reboiler as well as greatly enhances C.sub.5+ separation efficiency when operated substantially as an absorber.

[0034] 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 H.sub.2S removal to under 4 ppmv, CO.sub.2 to 50 ppmv, total sulfur under 30 ppmv as S, water to 0.1 ppmv, and mercury (Hg) to levels of 0.01 ?g/Nm.sup.3.

[0035] 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.

[0036] 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.

[0037] 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.

[0038] 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 C.sub.2-C.sub.4 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 C.sub.5+ 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.

[0039] In some embodiments, the column is substantially operated in an absorption region, i.e., more C.sub.2-C.sub.4 components are obtained in the vapor product than in the bottoms line, and substantially all of the C.sub.5+ components are discharged to the bottoms line. Thus, the overhead vapor stream comprising primarily methane and C.sub.2-C.sub.4 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 C.sub.5+ and absorbs C.sub.5+ 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 C.sub.6+ components is is removed for subsequent liquefaction in an LNG plant.

[0040] A bottoms liquid rich in C.sub.5+ components with a minor amount of C.sub.2-C.sub.4 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.

[0041] In a class of embodiments, in general, the third feed/C.sub.3 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 C.sub.2+ 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.

[0042] In particular, with respect to FIG. 3, in a heavy hydrocarbon removal system 300, a feed gas stream 301 is split into a slip stream 303 which is depressurized to lower pressure via a pressure reducing device such as Joule-Thomson (JT) valve 305 and then fed to the bottom of the column 307 as stripping gas to regulate light hydrocarbon (such as C.sub.1) slippage to the bottom of the column 307. Alternatively, a reboiler (not shown) can be used to generate stripping gas for the same purpose. The remaining portion of the stream 301 is then chilled in one or more pre-chillers 311, 313, exchanging heat with an external refrigerant such as propane. The pre-chilled stream 314 is then routed to the column 307 wherein it separates into a bottom stream 309 that will be further fractionated in downstream fractionation column(s) as shown in FIG. 1B, and an overhead stream 315. Overhead stream 315 is then further partially condensed in a chiller 317, transferring heat to an external refrigerant such as propane. Depending on the composition of stream 315 and conditioning and/or impurity removal needs, sufficient condensation may be achieved by 317. As such, the stream exiting chiller 317 will bypass MCHX 321 entirely and directly feed the reflux drum 327. In the reflux drum 327, the chilled stream separates into stream 329 that meets the requirements for further liquefaction under cryogenic conditions occurring in MCHX 321, and a reflux stream 328 that will be returned column 307 via a reflux pump 308. For the case wherein sufficient condensation is not able to be achieved by using the chiller 317, part or all the stream leaving 317 will be routed to MCHX 321 via stream 319 to achieve deeper cooling insuring sufficient condensation to generate stream 325. Stream 325 is then routed to the reflux drum 327 to generate sufficient reflux and stream 329 that is essentially free of freezing hydrocarbons and is then routed to the MCHX 321 to be liquefied under cryogenic conditions to generate a liquefied stream 323 exiting the MCHX 321.

[0043] 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 C.sub.5+ recovery, energy costs, type of refrigeration system used in the LNG plant, and the like.

[0044] 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 FIG. 3, can be combined into a single heat exchanger. As shown in FIG. 4, part of a feed stream 401 is pre-cooled via heat exchanger 409 where it is cooled against a refrigerant stream 421 after depressurization via a pressure reducing element such as JT valve 419. After pre-cooling, the feed gas stream 401 is then separated into a bottom stream 405 and an overhead stream 407 in column 403. Similar to FIG. 3, part of the feed stream 401 can be split into a slip stream prior to being cooled by heat exchanger 409, feeding to the bottom of column 403 to serve as stripping gas (not shown). Alternatively, a reboiler can be used to achieve a similar stripping effect that regulates the amount of lighter hydrocarbons slip to column bottoms 405. The overhead stream 407 is then routed to heat exchanger 409 to be partially condensed into a two-phase stream 411, which then separates in reflux drum 413 into a reflux stream 415 and an overhead stream 423 that meets the requirement for further liquefaction under cryogenic conditions occurring in the MCHX 425 of a liquefaction system (denoted by a broken-line box in FIG. 4) to produce LNG.

[0045] Continuing with FIG. 4, the dual mixed refrigerant or MR system 400 for producing LNG includes a gas turbine 471 to power the compressor(s) 431 tasked with compressing the warm mixed refrigerant. System 400 also includes a gas turbine 505 tasked with compressing the cold MR.

[0046] 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 FIG. 4) which liquefies a natural gas feed stream to produce LNG using two refrigeration cycles in the MCHX 425: a warm mixed refrigerant (warm MR) cycle and a cold mixed refrigerant (cold MR) cycle. The feed gas 423 is chilled using a warm MR to about ?100? F., with the actual temperature being a process variable. The gas is then further cooled to the final cryogenic temperatures by a cold MR. The resulting cryogenic fluid 516 is then reduced in pressure, preferably by an LNG turbine 514, generating an LNG rundown stream 518. 518 is then routed to a storage area (not shown) and to further reduce pressure across valve 520, generating stream 521.

[0047] 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.

[0048] 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.

[0049] Given lean natural gas streams low in C.sub.2+ components, or relatively richer natural gas feed where there is already a supply of C.sub.2-C.sub.4 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 C.sub.5+ 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 C.sub.2-C.sub.5 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 C.sub.2-C.sub.5 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-US-00001 TABLE 1 Comparisons of Prior Art vs. (Inventive C.sub.3 MR based LNG plant) (FIG. 3) Energy Comparison (MW) Prior Art Embodiment Saving Rich Feed Compressor power 93.0 91.2 ?2% Lean Feed Compressor power 97.04 96.5 ?1%

[0050] 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 FIG. 3, the refrigerant compressor power will be 2% lower than the scenario wherein the same rich feed is processed via the prior art as illustrated in FIG. 2. Thus, FIG. 3 represents a more energy efficient process. As the LNG train capacity is often constrained by the available compression power, the 2% savings could also be used to produce more LNG. The same advantage may be found for a lean feed. Using the same heavy hydrocarbon removal scheme as illustrated in FIG. 3, the refrigerant compressor power will be 1% lower than the scenario where the same lean feed is processed via the prior art as illustrated in FIG. 1, thus, achieving higher energy efficiency for the same LNG throughput or alternatively, a higher LNG rate.

TABLE-US-00002 TABLE 2 Impact on Stabilizer - FIG. 1 (prior art) versus FIG. 3 (inventive) Stabilizer System Prior Art Embodiment Saving Rich Feed System Installation Cost 0.71 0.14 ?57% System Material Cost 0.29 0.04 ?25% Total Cost 1.00 0.19 ?81% Lean Feed System Installation Cost 0.68 0.35 ?33% System Material Cost 0.32 0.16 ?16% Total Cost 1.00 0.51 ?49%

[0051] Table 2 demonstrates the impact of employing a heavy hydrocarbon removal scheme as illustrated in FIG. 3 on the stabilizer section. As shown, for both rich feed and lean feed, the stabilizer section would be more cost effective in installation, material and total cost when compared to the prior art as illustrated in FIG. 1 (for lean feed) and FIG. 2 (for rich feed).