JP6289471B2 - Configuration and method for offshore NGL recovery - Google Patents

Description

  The present invention claims priority of a US provisional application having serial number 61/694949 filed on August 20, 2012, which is hereby incorporated by reference.

  The field of the invention is the removal and recovery of natural gas liquid (NGL) from feed gas to meet pipeline hydrocarbon dew point and heating value specifications, especially for offshore applications.

  In the prior art, many systems and methods for recovering C2, C3 and heavier components from natural gas are known, all or nearly all of which have high NGL recovery (ie, , More than 90%) and requires the use of turbo expanders and deep cooling, which is expensive and can only be economically justified if there is a large downstream market. However, this is not the case with offshore NGL recovery systems where the space is expensive and the economic value of the installation relies on a relatively small footprint and low operating and capital costs. Thus, in all or nearly all cases, the high capital investment and operating costs typically required for high recovery cannot be justified. On the other hand, pipeline operators are required to produce sales gas that satisfies the pipeline specifications related to hydrocarbon dew point and calorific value for safety in transportation. In most cases, over 95% recovery of C4 and heavier hydrocarbons from the feed gas is required, C3 recovery may be as low as 60%, and C2 recovery is incidental, 30% It may be low. In view of the changed requirements, the complexity of currently known NGL processing plants that allow over 90% C3 recovery cannot be justified from an economic perspective.

  Many NGL processing plants with high NGL recovery from feed gas are US Pat. No. 4,157,904 to Campbell et al., US Pat. No. 4,251,249 to Gulsby, US Pat. U.S. Pat. No. 4,617,039 to Buck, U.S. Pat. No. 4,690,702 to Paradowski et al., U.S. Pat. No. 5,275,005 to Campbell et al. 5) U.S. Pat. No. 5,799,507 to Wilkinson et al. And U.S. Pat. No. 5,890,378 to Rambo et al., U.S. Patent Application Publication No. 2002/0166336 to Wilkinson et al. No. (Patent Document 8), and Johnke et al. When including the cryogenic rectification process and the turbo expander process as described in Publication No. 2011/126710 (Patent Document 9). These and all external materials discussed herein are incorporated by reference in their entirety. If the definition or use of a term in an incorporated reference does not match or contradict the definition of that term provided herein, the definition of that term provided here applies and the definition of that term in the reference does not apply. Absent.

  All of these processes can achieve very high NGL recovery, but some difficulties still remain. In particular, the NGL recovery process uses a high expansion ratio turboexpander to produce a low level of cooling, which requires recompression of the residual gas. In addition, additional external cooling is often required when processing rich gas streams having relatively high levels of C5 + hydrocarbons. Typically, such process configurations are complex and difficult to operate. For example, Campbell et al. In US Pat. No. 6,182,469 (Patent Document 10) uses a hot residual gas and side reboiler to heat the supplied gas as depicted in FIG. 1 of the prior art. It describes that it is cooled by the exchanger. Next, the concentrated feed gas liquid is separated by a separator and sent to a demethanizer tower. Alternatively, an absorber is added upstream of the demethanizer tower, as depicted in prior art FIG. 2, as described by Sorensen in US Pat. No. 5,953,935. . In these configurations, the liquid from the feed separator and the bottom of the absorber is sent to the demethanizer tower. In order to further increase NGL recovery in these configurations, the absorber overhead is cooled and refluxed by cooling with demethanizer overhead steam.

  Further known configurations are reboiler duty as described in US Pat. No. 6,244,070 to Lee et al. And US Pat. No. 5,890,377 to Foglietta. Are integrated into the feed chill ring, and in these configurations, the liquid from the intermediate separator is sent to various locations in the downstream demethanizer tower for NGL recovery. These processes also include various means for providing cooling to the NGL process. An exemplary known configuration following such a scheme is depicted in FIGS. 3 and 4 of the prior art. Such complex configurations are suitable to achieve high C2 and C3 recovery up to over 95%, but they are cost prohibitive and not suitable for offshore applications.

  Thus, although various configurations and methods for recovering NGL from a feed gas are known, all or nearly all of them have one or more disadvantages when dew point and proper C3 recovery are required. Receive. Therefore, there is still a need to provide methods and configurations for improved NGL recovery.

U.S. Pat. No. 4,157,904 US Pat. No. 4,251,249 US Pat. No. 4,617,039 US Pat. No. 4,690,702 US Pat. No. 5,275,005 US Pat. No. 5,799,507 US Pat. No. 5,890,378 US Patent Application Publication No. 2002/0166336 International Publication No. 2011-126710 US Pat. No. 6,182,469 US Pat. No. 5,953,935 US Pat. No. 6,244,070 US Pat. No. 5,890,377

  The subject of the present invention is the recovery of C4 and heavier hydrocarbons from the gas stream to meet the hydrocarbon dew point and calorific value specification of the pipeline gas produced from the gas stream and the proper recovery of C3 (90 %) And composition.

  In one preferred embodiment of the present inventive subject matter, the two columns are operated at different pressures, the first column (absorber) operates at a relatively high pressure of about 550 psig, and the second column (rectification). The tower) operates at about 450 psig. By operating the absorber at a relatively high pressure, the compression ratio of the residual gas is reduced, thereby minimizing the overall compression horsepower. In a rectification column operating at about 450 psig, separation of methane from ethane and heavier components can be achieved with less calorific value due to the preferred relative volatility between the components, The result is a smaller diameter tower.

  In another preferred embodiment of the invention, the vapor stream from the rectifier overhead is advantageously utilized for stripping at the absorber. In one embodiment of the process, the rectifier overhead stream is compressed and compression “free” heat is used to efficiently remove the methane component from the NGL from the absorber.

  Only the liquid portion of the expander discharge is used as reflux to the absorber, which requires that the expander discharge be sent to the middle or lower section of the absorber, as depicted in FIGS. It should be particularly recognized that this is completely different from the previously known configurations and methods. Expander emissions typically contain about 80% steam, and supplying this steam portion to the top of the absorber significantly reduces the amount of steam movement in the middle to lower portion of the absorber. Therefore, the size of the absorber is smaller. In previously known configurations and methods where the expander is discharged into the lower section of the absorber, the tower must be designed to handle all streams, not just the liquid stream presented here. For example, compared to a 10 foot diameter absorber size using the configuration and method presented here, which significantly reduces the equipment cost and weight associated with the need for space, which is of primary importance in offshore environments. The absorber size in currently known gas plants is then typically 12 feet in diameter for a 1,000 MMsccfd feed gas.

  In addition, the second rectification column operates at low pressure and low temperature and is not only more efficient with respect to separation, but also allows the use of residual gas compression heat to reboil the rectification column, thereby It should be appreciated that the need for steam and hot oil heating in known systems and methods is eliminated.

  The fractionator is operated at a pressure between 450 and 550 psig, overhead vapor is at least 50 psi, and more typically at least 100 psi, and most typically 155 psi higher than the absorber to an absorber pressure It is more generally preferred that it be compressed and that the compressor discharge steam have sufficient temperature and capacity to be used as stripping steam for the absorber.

  In addition, the method contemplated herein also includes expanding the vapor phase in a turboexpander and reducing the liquid phase pressure at the second expansion device before supplying the liquid phase to the supply exchanger. . Without limiting to the subject matter of the present invention, it is typically preferred that the feed gas cooling be performed without the use of external cooling. In yet another step, the bottom of the absorber is depressurized via a JT valve that provides additional cooling for the feed gas in the feed exchanger.

  In one preferred aspect of the present inventive subject matter, a processing plant for hydrocarbon dew point control of natural gas feed gas delivered from a feed gas source (eg, LNG import terminal, regasification facility, etc.) comprises a feed gas source A feed gas exchanger configured to cool the feed gas using the liquid phase of the feed gas fluidly coupled to and cooled and the bottom product of the absorber. The plant contemplated herein also includes a phase separator that is fluidly coupled to the feed gas exchanger and configured to separate the cooled feed gas into a liquid phase and a vapor phase. Most typically, the rectification column comprises a top section configured to produce a vapor phase that is compressed and used as strip gas in the absorber.

  Various objects, features, aspects and advantages of the present invention will become apparent from the following detailed description of preferred embodiments of the invention with the accompanying drawings.

Schematic of one known configuration for NGL recovery, where the feed gas is cooled by a heat exchanger using cold residual gas and side reboiler, showing the prior art Schematic of other known configurations for NGL recovery, showing the prior art, where the absorber / rectifier column is located upstream of the demethanizer column Schematic of yet another known configuration for NGL recovery where reboiler and feed gas compression are integrated into feed cooling, showing prior art Schematic of a more known configuration for NGL recovery, where reboiler and compressed residual gas recycling is integrated with feed cooling, showing prior art Schematic of an exemplary configuration for NGL recovery according to the present inventive subject matter Table listing the calculated composition of the gas stream in the exemplary NGL recovery plant of FIG.

  The inventor has identified various NGL recovery, especially in offshore applications where rich feed gas is processed and C4 + recovery with moderate C2 and C3 recovery is required, with significantly reduced funding and operating costs. Discovered the configuration and method. In particular, the arrangements and methods contemplated here reduce the number of equipment services, reduce the need for residual gas pressure, and significantly reduce complexity and cost by eliminating external cooling and external heating.

  In a particularly preferred configuration and method, the feed gas (typically natural gas comprising C1, C2, C3, and C4 and heavier components) is cooled at a relatively high pressure and thereby partially Concentrate. The vapor phase and liquid phase are then separated and the liquid phase is expanded to a lower pressure to provide cooling to the feed gas. After depressurization, the liquid phase is sent to the lower section of the rectification column and the vapor phase is expanded via a turboexpander and sent to the top section of the first rectification column (absorber). Since the absorber is operated at a relatively high pressure (typically 550 to 650 psig), the need for residual gas recompression is greatly reduced.

An exemplary plant configuration is depicted in FIG. 5, where a wet feed having a typical composition as shown in the table of FIG. 6 at a pressure of about 1,000 psig and a temperature of about 100 ° F. Gas 1 is dried by molecular sieve dryer 51 to form stream 2. The gas stream 2 so dried is cooled to a temperature of about −65 ° F. in the exchanger 52 using the cooling capacity from the residual gas stream 9 and the liquid streams 6 , 11 to form stream 3. To do. The gas stream 3 so cooled is then separated in a layer separator 53 into a liquid portion stream 5 and a vapor portion stream 4.

  Liquid portion 5 is reduced in pressure to about 475 psig via JT valve 54 and cooled to about −106 ° F. to form stream 6, which enters the lower section of rectification column 59 as stream 7. Previously heated in exchanger 52 to about 70 ° F. Steam portion 4 is expanded to about 550 psig at about −109 ° F. via turbo expander 55 to form stream 8, which is fed to the top of absorber 70. As used herein, the term “about” relating to a number includes those 20% starting from 20% below the absolute value of the number and up to 20% above the absolute value of the number. Refers to a range. For example, the term “about −150 ° F.” refers to a range of −120 ° F. to −180 ° F., and the term “about 1500 psig” refers to a range of 1200 psig to 1800 psig. Further, unless stated otherwise to the contrary by context, all ranges stated herein are to be construed as including these endpoints, and unlimited ranges are commercially viable. Should be interpreted to include a value. Similarly, all lists of values should be considered as including intermediate values unless the context dictates otherwise. In some embodiments, the energy of gas expansion within the turboexpander 55 can be used to drive the compressor 56 and other devices to recover the expansion energy. In some embodiments, the energy of gas expansion in the turboexpander 55 can also be used to drive the compressor 57.

  It should be considered that the steam portion 4 has been expanded through a turbo expander 55 to partially concentrate the steam portion 4 to produce a two-phase stream 8 comprising a vapor phase and a liquid phase. . In some embodiments, at least 5% by volume of stream 8 is in the vapor phase. In some embodiments, at least 10% by volume of stream 8 is in the vapor phase. Further, in some embodiments, at least 20% by volume of stream 8 is in the vapor phase. In still some other embodiments, at least 30% by volume of stream 8 is in the vapor phase. Furthermore, in some embodiments, at least 40% by volume of stream 8 is in the vapor phase. Further, in some embodiments, at least 60% by volume of stream 8 is in the vapor phase. In still some other embodiments, at least 80% by volume of stream 8 is in the vapor phase. The remainder of the expanded stream is in the liquid phase and serves as the reflux stream. Thus, in some embodiments, at least 5% by volume of stream 8 is in the liquid phase. Further, in some embodiments, at least 20% by volume of stream 8 is in the liquid phase. In some other embodiments, at least 30% by volume of stream 8 is in the liquid phase. Further, in some embodiments, at least 40% by volume of stream 8 is in the liquid phase. Further, in some embodiments, at least 60% by volume of stream 8 is in the liquid phase. Further, in some embodiments, at least 80% by volume of stream 8 is in the liquid phase.

  The operating pressure of absorber 70 is in the range of about 550 to about 650 psig or higher, the temperature of the top section is about −100 ° F., and the bottom section is about −15 ° F. It should be noted that only the liquid portion from the expander discharge is used as reflux and the vapor portion forms part of the residual gas. The absorber is stripped in the hot compressor discharge stream 16 from the rectification column 59.

In some embodiments, the overhead gas stream 9 includes residual gas from the absorber 70 and at least some portion of the vapor portion of the stream 8. In some embodiments, the overhead gas stream 9 has a methane content of about 95 mol%. The overhead gas stream 9 from the absorber 70 is cold (about −100 ° F.) and the cooling capacity of the overhead gas stream 9 is used to cool the natural gas feed 2. The absorber bottom stream 10 is reduced in pressure to about 450 psig and cooled to -14 ° F. to form stream 11, whose cooling capacity is to cool the feed gas at exchanger 52 to form stream 21. used. The heated gas is instantaneously released to the top of the rectification column 59.

  After being used to cool the natural gas feed 2, the hot gas stream 17 from the heat exchanger 52 is compressed by the compressor 56 and becomes the compressed gas stream 18. In some embodiments, the gas stream 18 is further compressed by a compressor 57 to form a compressed gas stream 19 that is used to reboil the product from the rectification column 59 in the reboiler 62. Is done. Residual gas stream 15 so cooled is then fed to air cooler 58 before leaving the plant as residual gas stream 20 (eg, as pipeline gas). It should be appreciated that such a configuration does not require external heating or fuel gas heaters, while at the same time producing a product that meets specifications for offshore operation and eliminates harmful or undesirable emissions. .

  The rectification column 59 uses the reboiler 62 to maintain the methane content in the lower liquid stream 12 preferably as needed to meet the vapor pressure specification of only 2 mol% or NGL product. Due to the relatively low operating pressure in the rectification column, the reboiler uses the cold compression heat from the residual gas compressor discharge stream 19 to reboil the rectification column bottom product 13 and requires external heating. Can be eliminated. The rectification column 59 is configured to produce a rectification column overhead product 14 that is passed to the compressor 63. As described above, the compressed stream 16 is then passed to the bottom section of the absorber 70 and a portion of the bottom product exits as a C2 + NGL product stream 12.

  With respect to the feed gas, it is generally contemplated that suitable feed gases include C1, C2 and C3 +, and can further include N2 and CO2. As a result, the nature of the feed gas can vary greatly, and all feed gases in the plant contain a C1 component and a C3 component, and more typically are heavier than C1 to C5. As long as it contains quality components, and more typically C1-C6 and heavier components, it is considered a suitable feed gas. Thus, particularly suitable feed gases are natural gas (eg, after regasification from LNG, after removal of CO2 from that produced from the gas well), refined gas, and coal, crude oil, naphtha, oil shale, Includes syngas streams derived from tar sands and other hydrocarbon materials such as linnite. Suitable gases may also contain heavier hydrocarbons such as propane, butane, pentane, etc., and relatively small amounts of hydrogen, nitrogen, carbon dioxide and other gases. Depending on the particular feed gas, the feed gas pressure can vary. However, it is generally preferred that the feed gas has a pressure between about 700 psig and about 1400 psig, more typically between about 900 psig and about 1200 psig.

  For the most appropriate applications, the configurations and methods contemplated here are that of using at least 95% of C4 and heavier hydrocarbons, C3 components using a single rectification column without the use of external cooling. Recover 60% to 80% and 20% to 50% of the C2 component. Thus, it should be noted that feed gas cooling and / or steam product cooling is performed without external cooling (at least 90% of what is required for cooling is generated from expansion of the process stream). It is. Also, a single column configuration can also be used with two separation columns stacked one above the other, and the functions corresponding to the absorber and rectification column are also suitable for use herein. It should be recognized that It is contemplated that the dryer, separator, rectifying column, heat exchanger, JT valve, residual gas compressor, and turboexpander used in the construction and method of the present invention are conventional devices well known to those skilled in the art.

  Among the advantages of the configurations contemplated herein, it should be particularly appreciated that the layer separator produces C5 + enriched liquid and C5 + deficient vapor from the feed gas. Thus, the C5 enrichment so produced is advantageously rectified in the bottom section of the rectification column to meet product liquid specifications. In addition, by using a feed cooler and a feed phase separator, and also by cooling the steam from the feed coolant and separating the cooling steam at the separator (thus forming C5 + enriched liquid and C5 + depleted steam). Most, but not all of the heavier components are removed from the feed gas. As a result, the composition of the material flowing through the cold section is substantially stabilized because the processing of heavy components in the feed gas in the upper section of the rectification column can be eliminated. Thus, the thermal duty, turbo expander, and rectification column operate at the most efficient point. Thus, the configurations and processes contemplated herein allow for handling of the enriched feed gas composition, thereby eliminating the complexity of modern technology cooling units. From another point of view, the process contemplated here maintains constant operating conditions for the NGL recovery plant by removing the C5 + component in the feed gas.

  According to previously performed calculations (data not shown), the configuration contemplated here is at least 60%, and more typically 78% propane recovery, and at least 85%, and more typical. Achieves 95% butane recovery (see FIG. 6). Further considerations, configurations and methods suitable for use herein are described in US Pat. Nos. 6,601,406, 6,837,7070, 7,051,552, 7051,552 and 7,377,127, all of which are hereby incorporated by reference. It is contemplated that a natural gas processing plant does not need to include all of the above features to achieve efficiency in NGL recovery. Thus, a natural gas processing plant may include only a subset of the above features. In some of these embodiments, the natural gas processing plant may include additional features not disclosed herein.

For example, the natural gas processing plant of some embodiments can include a turbo expander and an absorber. The turboexpander is configured to reduce the pressure of the vapor stream to generate a two-phase stream having a liquid phase and a vapor phase. The absorber is configured to receive the two-phase stream at a location that allows the use of the liquid layer as reflux. The absorber is further configured to produce an absorber overhead product and an absorber bottom product. Preferably, but not necessarily, the steam stream entering the turboexpander includes a natural gas feed that is cooled in a heat exchanger. In some of these embodiments, the absorber overhead product is returned to the heat exchanger where the cooling capacity of the absorber overhead product is used to cool the natural gas stream.

  Preferably, but not necessarily, after being used to cool the natural gas feed, the absorber overhead product is compressed and used to reboil the contents in the rectification column. In addition, the steam stream entering the turboexpander includes a natural gas feed that is cooled by a heat exchanger. In some of these embodiments, the absorber bottom product is recycled back to the heat exchanger where the cooling content of the absorber bottom product is used to cool the natural gas stream.

  It should be apparent to those skilled in the art that many and many other modifications than those already described are possible without departing from the inventive concepts described herein. Accordingly, the subject matter of the invention should not be limited except in the spirit of the appended claims. Moreover, in interpreting both the specification and the claims, all terms should be interpreted in the broadest possible manner consistent with the context. In particular, the terms “comprises” and “comprising” refer non-exclusively to an element, component, or step, and the referenced element, component, or step exists. Should be construed to refer to what can be used, can be used, and can be combined with other elements, components or steps not explicitly referenced. When the description and claims refer to at least one selected from the group consisting of A, B, C... And N, in this text it is not A and N or B and N etc. Should be construed as requiring only one element from the group.

Claims (13)

A method for processing a natural gas stream, comprising:
Cooling the natural gas stream and separating the cooled natural gas stream into a vapor portion and a liquid portion;
Reducing the pressure of the vapor portion using a turbo expander, thereby generating a two-phase stream having a liquid phase and a vapor phase;
Feeding the two-phase stream to the absorber such that the liquid phase is reflux in the absorber producing an absorber overhead product and an absorber bottom product;
Reducing the pressure of the bottom product of the absorber, and supplying the bottom product of the absorber after the pressure reduction to a rectifying column that generates a rectifying column bottom product and a rectifying column overhead product;
Compressing the rectifier overhead product and using the compressed rectifier overhead product as a strip gas in the absorber;
Compressing the absorber overhead product to form a compressed absorber overhead product;
Using the heat capacity of the compressed absorber overhead product to reboil the rectification column.   The method of claim 1, further comprising using a cooling capacity of the absorber overhead product for the step of cooling the natural gas stream.   3. The method of claim 1 or claim 2, further comprising using a cooling capacity of the liquid portion and the absorber bottom product after pressure reduction for the step of cooling the natural gas stream. A natural gas processing plant,
A heat exchanger configured to cool the natural gas stream and a phase separator configured to receive the cooled natural gas stream and separate it into a vapor portion and a liquid portion;
A turboexpander coupled to the absorber and to the phase separator and configured to reduce the pressure of the vapor portion, thereby generating a two-phase stream having a liquid phase and a vapor phase;
The absorber is configured to receive the two-phase stream at a location that allows use of the liquid phase as reflux, and the absorber is configured to generate an absorber overhead product and an absorber bottom product. Said turbo expander,
A pressure reduction device fluidly coupled to the absorber and configured to reduce the pressure of the absorber bottom product;
A rectifying column configured to receive the absorber bottom product after pressure reduction and further configured to generate a rectifying column bottom product and a rectifying column overhead product, and having a reboiler;
A compressor fluidly coupled between the rectification column and the absorber, which receives and compresses the rectification tower overhead product and strips the compressed rectification tower overhead product in the absorber Said compressor configured to provide as:
A residual gas compressor configured to compress the absorber overhead product to form a compressed absorber overhead product;
A natural gas processing plant, wherein the reboiler of the rectification column is configured to use the heat capacity of the compressed absorber overhead product to reboil the rectification column.   The plant of claim 4, wherein the heat exchanger is configured to allow use of a cooling capacity of the absorber overhead product to cool the natural gas stream.   The heat exchanger is further configured to allow use of a cooling capacity of the liquid portion and the bottom product of the absorber after pressure reduction to cool the natural gas stream. Item 6. The plant according to Item 5. A method of operating an absorber in a natural gas processing plant comprising:
Supplying a biphasic stream having a liquid phase and a vapor phase to the top of the absorber such that the liquid phase operates as reflux, the biphasic stream being generated by expansion of the vapor portion of the natural gas stream Steps,
Feeding the bottom product of the absorber to a rectification column;
Using the heat capacity from the compressed absorber overhead product in the reboiler of the rectification column.   The method of claim 7, wherein the expansion of the vapor portion of the natural gas stream is performed using a turboexpander.   8. The method of claim 7, wherein the natural gas stream is a rich natural gas stream having at least 3% C3 + and the natural gas stream has a pressure of at least 1000 psig. A natural gas processing plant,
A turboexpander configured to reduce the pressure of a vapor stream to generate a two-phase stream having a liquid phase and a vapor phase, wherein the two-phase stream is generated by expansion of a vapor portion of a natural gas stream Said turbo expander,
An absorber coupled to the turboexpander and configured to receive the two-phase stream at a location that allows use of the liquid phase as reflux, producing an absorber overhead product and an absorber bottom product. The absorber further configured as:
A rectifying column coupled to the absorber, the rectifying column receiving the absorber bottom product,
A natural gas processing plant, wherein the absorber overhead product is compressed to form a compressed overhead product, and the compressed overhead product is used to reboil the rectification column. A heat exchanger configured to use the absorber overhead product to cool the natural gas stream to form a cooled natural gas stream; and receiving the cooled natural gas stream and the steam portion natural gas processing plant of claim 10 and a configured phase separator to separate the liquid portion and. The natural gas processing plant of claim 10 , wherein the natural gas stream is a rich natural gas stream having at least 3% C3 +, and the natural gas stream has a pressure of at least 1000 psig. The natural gas processing plant according to claim 10 , wherein the rectification tower overhead product from the rectification tower is compressed and the compressed rectification tower overhead product is supplied to the absorber as a strip gas.

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