Patent Application
20100139317
The present invention provides a method of cooling a hydrocarbon stream, and an apparatus therefor.
Conventional fuel gas is normally produced from the end gas/liquid separator or the boil-off gas in a liquefaction process and may typically amount to 10-20 mol % of the hydrocarbon feed gas. Fuel gas is comprised primarily of methane, such as >70 mol % methane, more commonly >90 mol %, with the balance being provided by nitrogen and C2+ hydrocarbons such as ethane and propane. The ethane content of the fuel gas does not normally exceed 5 mol %, and is more commonly <2 mol %.
Such fuel gas can be provided to a fuel gas header from which it can be supplied to any number of fuel gas consumers by fuel gas streams. Examples of fuel gas consumers include high quantity consumers such as gas turbines and boilers, as well as lower content consumers such as mixed refrigerant circuits.
In a first aspect, the present invention provides a method of cooling a hydrocarbon stream, comprising at least the steps of:
(a) providing a hydrocarbon feed stream;
(b) separating the hydrocarbon feed stream in at least one separator to provide a hydrocarbon stream and at least one methane-lean stream comprising a first ethane-rich header feed stream;
(c) heat exchanging the hydrocarbon stream with at least one refrigerant stream to provide at least one cooled hydrocarbon stream and at least one at least partially evapourated refrigerant stream;
(d) passing the first ethane-rich header feed stream to at least one fuel gas header; and
(e) removing fuel gas from the at least one fuel gas header as at least one fuel gas stream.
In a second aspect, the present invention provides an apparatus for cooling a hydrocarbon stream, the apparatus comprising at least:
at least one separator arranged to receive the hydrocarbon feed stream in a hydrocarbon feed stream line and to separate the hydrocarbon feed stream to provide a hydrocarbon stream in a hydrocarbon stream line and a first ethane-rich header feed stream in a first ethane-rich header feed stream line;
at least one heat exchanger arranged to receive the hydrocarbon stream in a hydrocarbon stream line and a refrigerant stream in a refrigerant stream line to heat exchange the hydrocarbon stream against the refrigerant stream to provide a cooled hydrocarbon stream in a cooled hydrocarbon stream line and an at least partly evaporated refrigerant stream in an at least partly evapourated refrigerant stream line; and
at least one fuel gas header connected to the first ethane-rich header feed stream line to receive the first ethane-rich header feed stream, said at least one fuel gas header being connected to at least one fuel gas stream line to provide at least one fuel gas stream.
Embodiments of the present invention will hereinafter be described by way of example only, and with reference to the accompanying non-limiting drawings in which:
For the purpose of this description, a single reference number will be assigned to a line as well as a stream carried in that line. Same reference numbers refer to similar components, streams or lines.
In the present specification, the term “one or more” is used interchangeably with the term “at least one”. Both are considered to have the same meaning.
The methods and apparatuses described herein may be used to cool a hydrocarbon stream to provide a cooled hydrocarbon stream, such as a Liquefied Natural Gas (LNG) stream. The hydrocarbon stream may comprise natural gas, or essentially consist of a natural gas stream.
The methods and apparatuses described herein employ one or more ethane-rich header feed streams, which may be used to supply one or more fuel gas headers. Herewith, an ethane-rich source of fuel gas may be provided for one or more fuel gas headers as the first ethane-rich header feed stream from the one or more separators. This may be a particularly advantageous proposition in, for instance, situations when the hydrocarbon feed stream comprises a significant amount of ethane, which may exceed the demands for ethane export.
The hydrocarbon feed stream may be any suitable gas stream to be cooled and liquefied, but is usually a natural gas stream obtained from natural gas or petroleum reservoirs. As an alternative the natural gas stream may also be obtained from another source, also including a synthetic source such as a Fischer-Tropsch process.
Usually a natural gas stream is comprised substantially of methane. Preferably the hydrocarbon feed stream comprises at least 50 mol % methane, more preferably at least 80 mol % methane.
The hydrocarbon feed stream may also contain non-hydrocarbons such as H2O, N2, CO2, Hg, H2S and other sulphur compounds, and the like. If desired, the hydrocarbon feed stream comprising the natural gas may be pre-treated before cooling and liquefying. This pre-treatment may comprise reduction and/or removal of undesired components such as CO2 and H2S or other steps such as early cooling, pre-pressurizing or the like. As these steps are well known to the person skilled in the art, their mechanisms are not further discussed here.
Thus, the term “hydrocarbon feed stream” also includes a composition prior to any treatment, such treatment including cleaning, dehydration and/or scrubbing, as well as any composition having been partly, substantially or wholly treated for the reduction and/or removal of one or more compounds or substances, including but not limited to sulphur, sulphur compounds, carbon dioxide, water, Hg, and one or more C2+ hydrocarbons.
The hydrocarbon feed stream is one example of a source of an ethane-rich header feed stream which may be used to supply one or more fuel gas headers in a method and apparatus described herein.
Depending on the source, natural gas may contain varying amounts of hydrocarbons heavier than methane such as in particular ethane, propane and the butanes, and possibly lesser amounts of pentanes and aromatic hydrocarbons. The composition varies depending upon the type and location of the gas.
Conventionally, the hydrocarbons heavier than methane are removed as far as efficiently possible from the hydrocarbon feed stream prior to any significant cooling for several reasons, such as having different freezing or liquefaction temperatures that may cause them to block parts of a methane liquefaction plant. C2+ hydrocarbons can be separated from, or their content reduced in a hydrocarbon feed stream by a demethaniser, which will provide an overhead hydrocarbon stream which is methane-rich and a bottoms methane-lean stream comprising the C2+ hydrocarbons. The bottoms methane-lean stream may then be passed to a deethaniser to provide an overhead first ethane-rich stream, such as a first ethane-rich header feed stream and a bottoms ethane-lean stream comprising the C3+ hydrocarbons.
The separation of hydrocarbons heavier than methane from the hydrocarbon feed stream is another example of a source of an ethane-rich header feed stream which may be used to supply one or more fuel gas headers in a method and apparatus described herein. Preferably the first ethane-rich header feed stream is provided from a separator such as a deethaniser, which is an unconventional source of fuel gas.
The fuel gas header is a collection, storage and distribution system for fuel gas. It may be supplied with fuel gas streams from multiple sources. In the method and apparatus described herein, one or more fuel gas headers are provided with fuel gas from a first ethane-rich header feed stream derived from the separation of the hydrocarbon feed stream. It is preferred that the fuel gas in the total of the one or more fuel gas headers, i.e. the total volume provided by all the fuel gas headers in the method and apparatus, comprises greater than 30 mol % ethane, more preferably greater than 40 mol % ethane, even more preferably greater than 50 mol % ethane.
Preferably at least one of said fuel gas streams comprises >30 mol %, more preferably >40 mol %, still more preferably >50 mol % ethane. In such cases, if the fuel gas is required to power a gas turbine, Siemens gas turbines can be used because they are not limited by the quantity of ethane in the fuel gas stream. Conventional industrial gas turbines, such as General Electric Frame 7 gas turbines, are less tolerant to ethane content such that this to be limited to 20 to 25 mol % of the fuel gas stream. A separate fuel gas header may be provided to supply lower ethane content fuel to such gas turbines.
The gas turbines may be used to drive one or more compressors, such as refrigerant compressors, either by direct mechanical drive or by the electrical power generated if the turbine is connected to an electrical generator.
The one or more turbine flue gas streams may be heat exchanged against one or more water streams in a heat exchanger to provide one or more steam streams, such as high pressure steam streams, and one or more cooled turbine flue gas streams. The one or more steam streams, such as high pressure steam streams, may be passed to one or more steam headers, such as one or more high pressure steam headers.
In a further embodiment, the one or more turbine flue gas streams, originating either from gas turbines fuelled by a fuel gas header described herein supplied from the ethane-rich header feed stream or from another fuel gas header supplying lower ethane content fuel gas, may be passed to a combustion device, such as a duct firing device, where it is mixed with a fuel gas stream, and combusted to provide one or more heated flue gas streams. Such a duct firing operation may raise the temperature of the flue gas stream from 650° C. to 800° C. Preferably, the one or more fuel gas streams are provided by the one or more headers supplied from the ethane-rich header feed stream, although a fuel stream from a fuel gas header supplying lower ethane-content fuel gas may also be used. The one or more heated turbine flue gas streams may then be heat exchanged in a heat exchanger against one or more water streams to provide one or more steam streams, preferably high pressure steam streams, and one or more cooled turbine flue gas streams. The one or more steam streams, preferably high pressure steam streams may be supplied to a steam header, such as a high pressure steam header, and used throughout the plant, for instance to power steam turbines to generate mechanical or electrical power.
The one or more fuel gas streams from the one or more fuel gas headers described herein may also be combusted in one or more boilers as boiler fuel gas stream, to provide heat and one or more boiler flue gas streams. Alternatively, a fuel gas stream from a fuel gas header supplying a lower ethane content fuel gas may also be used to fuel the boilers. Heat exchanging at least one of the one or more boiler flue gas streams against one or more water streams may provide at least one steam stream, such as a high pressure steam stream, and one or more cooled flue gas streams. The high pressure steam stream may be passed to a high pressure steam header. Conventional industrial boilers are not limited by the quantity of ethane in their fuel gas.
Alternatively, the one or more boiler flue gas streams, originating either from boilers fuelled by a fuel gas header described herein supplied from the ethane-rich header feed stream or from a fuel gas header supplying lower ethane content fuel gas, may be passed to a combustion device, such as a duct firing device, to increase the temperature of the flue gas to provide one or more heated boiler flue gas streams. The one or more heated boiler flue gas streams may then be heat exchanged in a heat exchanger against one or more water streams to provide one or more steam streams, preferably high pressure steam streams, and one or more cooled boiler flue gas streams. The one or more steam streams, preferably high pressure steam streams may be supplied to a steam header, such as a high pressure steam header, and used throughout the plant, for instance to power steam turbines to generate one or both of mechanical and electrical power.
To provide a partially liquefied hydrocarbon stream, the hydrocarbon stream should be cooled. Such initial cooling could be provided by a number of methods known in the art. One example is by passing the hydrocarbon stream against a refrigerant, such as a single refrigerant, e.g. propane, in a pre-cooling refrigerant circuit or a first fraction of a mixed refrigerant of a mixed refrigerant circuit, in one or more pre-cooling heat exchangers, to provide a partially liquefied hydrocarbon stream, preferably at a temperature below 0° C.
The single or mixed refrigerant circuit will comprise one or more refrigerant compressors to compress the refrigerant stream. The refrigerant compressors may be driven by one or more gas turbine drivers fuelled by fuel gas from the one or more fuel gas headers as disclosed herein or by other means, such as electrical driver motors.
Preferably, any such pre-cooling heat exchangers could comprise a pre-cooling stage, and one or more main heat exchangers used in liquefying any fraction of the hydrocarbon stream could comprise one or more main and/or sub-cooling cooling stages.
In this way, the method and apparatus disclosed herein may involve two or more cooling stages, each stage having one or more steps, parts etc. For example, each cooling stage may comprise one to five heat exchangers. The or a fraction of a hydrocarbon stream and/or the mixed refrigerant may not pass through all, and/or all the same, heat exchangers of a cooling stage.
In one embodiment, the hydrocarbon liquefying process comprises two or three cooling stages. A pre-cooling stage is preferably intended to reduce the temperature of a hydrocarbon feed stream to below 0° C., usually in the range −20° C. to −70° C.
A main cooling stage is preferably separate from the pre-cooling stage. That is, the main cooling stage comprises one or more separate heat exchangers.
A main cooling stage is preferably intended to reduce the temperature of a hydrocarbon stream, usually at least a fraction of a hydrocarbon stream cooled by a pre-cooling stage, to below −100° C.
Heat exchangers for use as the one or more pre-cooling or the one or more main heat exchangers are well known in the art. At least one of the main heat exchangers is preferably a spool-wound cryogenic heat exchanger known in the art. Optionally, a heat exchanger could comprise one or more cooling sections within its shell, and each cooling section could be considered as a cooling stage or as a separate ‘heat exchanger’ to the other cooling locations.
In yet another embodiment described herein, one or more fractions of a mixed refrigerant stream may be passed through one or more heat exchangers, preferably two or more of the pre-cooling and main heat exchangers described hereinabove, to provide one or more cooled mixed refrigerant streams.
The mixed refrigerant in a mixed refrigerant circuit may be formed from a mixture of two or more components selected from the group comprising: nitrogen, methane, ethane, ethylene, propane, propylene, butanes, pentanes, etc. The present invention may involve the use of one or more other refrigerants, in separate or overlapping refrigerant circuits or other cooling circuits.
In one embodiment of the present invention, the method of cooling, preferably liquefying a hydrocarbon stream comprises one refrigerant circuit comprising one mixed refrigerant.
A mixed refrigerant or a mixed refrigerant stream as referred to herein comprises at least 5 mol % of two different components. More preferably, the mixed refrigerant comprises two or more of the group comprising: nitrogen, methane, ethane, ethylene, propane, propylene, butanes and pentanes. A common composition for a mixed refrigerant can be:
The total composition comprises 100 mol %.
It is apparent that such a mixed refrigerant composition is suitable as a fuel gas stream. A bleed stream from an ethane-rich mixed refrigerant may be used as one ethane-rich header feed stream. For instance, an ethane-rich mixed refrigerant bleed stream may be drawn from one or more of the pre-cooling or one or more of the main-cooling heat exchangers and passed to one or more fuel gas headers.
In another embodiment, the cooled hydrocarbon stream may be a liquefied hydrocarbon stream. Preferably, the method is for liquefying natural gas to provide liquefied natural gas.
After liquefaction, the liquefied hydrocarbon stream may be further processed, if desired. As an example, the obtained LNG may be depressurized by means of a Joule-Thomson valve or by means of a cryogenic turbo-expander.
In another embodiment disclosed herein, the liquefied hydrocarbon stream is passed through an end gas/liquid separator such as an end-flash vessel to provide an end-flash gas stream overhead and a liquid bottom stream, the latter optionally for storage in a storage tank as the liquefied product, such as LNG. The end-flash gas may be compressed in an end-flash gas compressor to provide a compressed end-flash gas stream and cooled to provide a cooled end-flash gas stream, which may be passed to the one or more fuel gas headers.
The cooled end-flash gas is derived from the end gas/liquid separator. The composition of the cooled end-flash gas will thus be determined by the composition of the liquefied hydrocarbon. The liquefied hydrocarbon, such as LNG, will be at a required product specification, usually having an ethane content of less than 10 mol %. In this case, rather than providing an ethane-rich header feed stream, an ethane-depleted header feed stream would be provided.
Preferably, the cooled hydrocarbon stream provided by the method and apparatus described herein may be used to provide a liquefied hydrocarbon stream which may be stored in one or more storage tanks.
The boil-off gas stream from the one or more liquefied hydrocarbon storage tanks can provide a further source of fuel gas, for the fuel gas header. The boil-off gas is the gas vapourised from the liquefied storage tanks due to temperature fluctuations or imperfect insulation. The composition of the boil-off gas will thus be determined by the composition of the liquefied hydrocarbon. The liquefied hydrocarbon, such as LNG, will be at a required product specification, usually having an ethane content of less than 10 mol %. In this case, rather than providing an ethane-rich header feed stream, an ethane-depleted header feed stream could be provided.
In a further embodiment, where a fraction, preferably the coldest fraction, of the refrigerant stream passes through a suitable gas/liquid separator, at least a fraction of the gaseous overhead stream from this gas/liquid separator could be combined with the end-flash gas stream from the end gas/liquid separator or a stream derived therefrom, and optionally boil-off gas from the storage tank, to provide a combined stream for compression and supply to one or more fuel gas headers.
Furthermore, the fuel gas stream described herein may be used to provide duct firing for a flue gas stream. For instance, a flue gas stream, such as a turbine flue gas stream or a boiler flue gas stream may be passed to a combustion device where it is mixed with a fuel gas stream as described herein, and combusted to provide a heated flue gas stream.
Referring to the drawing,
A common form of such separation is termed ‘natural gas liquids’ (NGL) extraction, in which proportions of C2+ hydrocarbons are fractionated in the one or more separators 100, such as one or more fractionation columns, to provide a methane-enriched hydrocarbon stream as hydrocarbon stream 110 which is subsequently cooled, and one or more single or multi-component streams for the C2+ components, such as the first ethane-rich header feed stream 120 and optionally further methane-lean streams 130, such as NGL and LPG product streams.
A simplified example of the at least one separator 100 is presented in
The first separator 101 may be provided in the form of a demethanizer. The first light stream 104 may be in the form of a methane-rich stream, while the first heavy stream 105 may be in the form of a methane-lean stream. The second separator 102 may be provided in the form of a deethanizer. The second light stream 106 may be in the form of an ethane-rich stream while the second heavy stream 107 is preferably in the form of an ethane-lean stream.
Back to
The hydrocarbon stream 110 to be cooled may then be passed through one or more heat exchangers 200 in a refrigerant circuit 250. The one or more heat exchangers 200 can be in series, parallel, or both, in a manner known in the art.
For simplicity,
Cooling of the hydrocarbon stream 110 in the one or more heat exchangers 200 may be provided by one or more refrigerant streams 220 in the one or more refrigerant circuits 250. Each refrigerant circuit may comprise one or more refrigerant compressors 800, one or more coolers 1000, one or more expansion devices 1100 and one or more heat exchangers 200.
The hydrocarbon stream 110 is heat exchanged against the one or more refrigerant streams 220 to provide at least one cooled hydrocarbon stream 210 and one or more at least partially evapourated refrigerant streams 230. Preferably the cooled hydrocarbon stream 210 is a liquefied hydrocarbon stream, such as LNG.
At least a fraction of the one or more at least partially evapourated refrigerant streams 230 can be compressed in the one or more refrigerant compressors 800 to provide one or more compressed refrigerant streams 810. The one or more compressed refrigerant streams 810 may be cooled in one or more coolers 1000, such as air or water coolers, to provide one or more cooled refrigerant streams 1010. At least a fraction of the one or more refrigerant streams 1010 may be expanded in one or more refrigerant expansion devices 1100, such as an expander or Joule-Thomson valve, to provide the one or more refrigerant streams 220 used to cool the hydrocarbon stream 110.
The one or more heat exchangers 200 in one or more refrigerant circuits 250 may form one or more of a pre-cooling stage, a main cooling stage and a sub-cooling stage.
Preferably, any pre-cooling stage cools the hydrocarbon feed stream 10 to below 0° C., such as between −20° C. and −70° C., preferably either between −20° C. and −45° C., or between −40° C. and −70° C., to provide a partially liquefied hydrocarbon stream in a manner known in the art. Cooling may be carried out in one or more pre-cooling heat exchangers and may be provided by a single or mixed refrigerant in a manner known in the art.
The liquefied hydrocarbon stream from any pre-cooling stage may be passed to a main cooling stage comprising one or more main heat exchangers, preferably a main cryogenic heat exchanger. Such a main cryogenic heat exchanger may also perform the function of a sub-cooling stage.
Thus, it is preferred that: the one or more heat exchangers 200 may comprise one or more pre-cooling heat exchangers in a first cooling stage, and the one or more refrigerant streams 220 comprise a first fraction cooled refrigerant. It is also preferred that: the one or more heat exchangers 200 further comprise one or more main heat exchangers in a main cooling stage, the one or more refrigerant streams 220 further comprise one or more second fraction mixed refrigerant streams, and the one or more cooled hydrocarbon streams 210 comprise a liquefied hydrocarbon stream.
The one or more heat exchangers 200 provide one or more cooled, preferably liquefied, hydrocarbon streams 210.
As illustrated in
an expansion device 400 connected to the cooled hydrocarbon stream line carrying the cooled hydrocarbon stream 210, arranged to expand the cooled hydrocarbon stream 210 to provide an expanded cooled hydrocarbon stream 410 in an expanded cooled hydrocarbon stream line;
an end gas/liquid separator 500 connected to the expanded cooled hydrocarbon stream line to separate the expanded cooled hydrocarbon stream 410 into an end-flash gas stream 510 in an end-flash gas stream line and a liquid bottom stream 520 in a liquid bottom stream line;
an end-flash compressor 540 connected to the end-flash gas stream line to compress the end-flash gas stream 510 to provide a compressed end-flash gas stream 550 in a compressed end-flash gas stream line;
a third ethane-rich fuel gas feed line 530 receiving at least a portion of the compressed end-flash gas stream 550 and passing it to the at least one fuel gas header 300. The end-flash gas stream is typically an ethane-depleted stream as it is derived from the hydrocarbon stream 110 downstream of the one or more separators 100.
An optional end-flash gas ambient heat exchanger 560, such as a cooler, may be connected to the compressed end-flash gas stream line to exchange heat between the end-flash gas stream and ambient to provide a heat exchanged, optionally cooled, end-flash gas stream 570 in a heat exchanged end-flash gas stream line, prior to passing it to the third ethane-rich fuel gas feed line 530.
The method of cooling the hydrocarbon stream may further comprise the steps of:
(g) passing the cooled hydrocarbon stream 210 through an expansion device 400 to provide an expanded cooled hydrocarbon stream 410;
(h) separating the expanded cooled hydrocarbon stream 410 in an end gas/liquid separator 500 into an end-flash gas stream 510 and a liquid bottom stream 520;
(i) compressing the end-flash gas stream 510 in an end-flash compressor 540 to provide a compressed end-flash gas stream 550;
(j) optionally heat exchanging, such as cooling, the compressed end-flash gas stream 550 against ambient to provide a heat exchanged, preferably cooled, end-flash gas stream 570;
(k) passing at least a part of the compressed and/or cooled end-flash gas stream 570 to the fuel gas header as an ethane-depleted header feed stream 530.
After passing through the one or more heat exchangers 200, the cooled hydrocarbon stream 210 may then be passed through an expansion device 400 such as a Joule-Thomson valve, to provide an expanded cooled hydrocarbon stream 410. The expanded cooled hydrocarbon stream 410 may then be passed to an end gas/liquid separator 500, which may be an end-flash vessel. The end gas/liquid separator 500 separates the expanded cooled hydrocarbon stream 410 into an end-flash gas stream 510 overhead and a liquid bottom stream 520. The liquid bottom stream 520 may be passed into a storage tank 600, such as an LNG storage tank.
End-flash gas stream 510 may be compressed in an end-flash compressor 540, driven by an end-flash driver D1, to provide a compressed end-flash gas stream 550. The compressed end-flash gas stream 550 may then be cooled in an end-flash cooler 560, such as an air or water cooler, to provide a cooled end-flash gas stream 570. At least a part of the end-flash gas stream 570 may be passed to at least one of the one or more fuel gas headers 300, as ethane-depleted header feed stream 530.
The method of cooling the hydrocarbon stream may further comprise the steps of:
(l) passing the liquid bottom stream 520 into a storage tank 600;
(m) removing boil-off gas from the storage tank 600 as a boil-off gas stream 610;
(n) compressing the boil-off gas stream 610 in a boil-off gas compressor 620 to provide a compressed boil-off gas stream 630;
(o) optionally heat exchanging the compressed boil-off gas stream 630 against ambient, for instance cooling the compressed boil-off gas stream 630 in a boil-off gas cooler 640 to provide a cooled boil-off gas stream 650; and
(p) passing at least a part of the cooled boil-off gas stream 650 to the fuel gas header 300 as ethane-depleted header feed stream 530.
Step (o) is advantageous when the boil-off gas stream 610 compressed in step (n) is provided at or about the operating pressure of the one or more fuel gas headers 300, for instance at a pressure in the range of 20 to 40 bara. However, step (o) may be optional.
In an alternative embodiment not shown in
The liquid bottom stream 520 from the end gas/liquid separator 500, which may be LNG, can produce vapour during storage in storage tank 600 if the temperature rises about its dew point. Such vapour is called boil-off gas. Any boil-off gas can be removed from the storage tank 600 through boil-off gas stream 610. Boil-off gas stream 610 may be compressed in a boil-off gas compressor 620, driven by a boil-off gas driver D2, to provide a compressed boil-off gas stream 630. The compressed boil-off gas stream 630 may be cooled in a boil-off gas cooler 640, such as an air or water cooler, to provide a cooled boil-off gas stream 650. At least a part of the cooled boil-off gas stream 650 may be passed to at least one of the one or more fuel gas headers 300, as ethane-depleted header feed stream 530.
Alternatively, the compressed boil-off gas stream 630 may be passed to an intermediate stage of the end-flash compressor 540 to provide the compressed end-flash gas stream 550 as a compressed combination of the end-flash gas stream and compressed boil-off gas stream 630.
In a further alternative embodiment not shown in
Ethane-depleted header feed stream 530 may be used to adjust the composition of the one or more fuel gas headers 300. By increasing the proportion of the ethane depleted header feed stream 530 added to the one or more fuel gas headers 300, the ethane content may be reduced.
Alternatively or additionally, the ethane-depleted header feed stream 530 may be sent to another fuel gas header having a lower ethane content, which may be used to supply those pieces of equipment which are not tolerant to higher ethane contents, such as conventional gas turbines.
Users of the fuel gas streams 310, 320, 340 may be one or more gas turbines. For instance, first, second and third gas turbines, 700a, 700b and 700c may be fuelled by first, second and third fuel gas streams 310, 320 and 340, which are turbine fuel gas streams. First, second and third gas turbines are supplied with first, second and third oxidant streams 360a, 360b and 360c respectively, which can comprise oxygen, such as first, second and third air streams. The first, second and third oxidant streams 360a, 360b and 360c are passed to the first, second and third turbine compressors 365a, 365b and 365c respectively, where they are compressed to provide first, second and third compressed oxidant streams 370a, 370b and 370c respectively. First, second and third turbine compressors 365a, 365b and 365c may be mechanically connected to first, second and third turbine expanders 390a, 390b, 390c respectively, for instance by first, second and third connecting shafts 375a, 375b, 375c respectively.
The first, second and third compressed oxidant streams 370a, 370b and 370c are passed to first, second and third combustion chambers 380a, 380b, 380c respectively, where they may be mixed with the first, second and third turbine fuel gas streams 310, 320, 340 and ignited. The combustion reaction produces first, second and third combustion product streams 385a, 385b and 385c from first, second and third combustion chambers 380a, 380b and 380c respectively, and these streams are passed to first, second and third turbine expanders 390a, 390b and 390c, where their expansion is used to provide useful work to drive first, second and third shafts 395a, 395b and 395c respectively and first, second and third turbine flue gas streams 710a, 710b and 710c are produced.
The one or more gas turbines 700a, 700b, 700c may be used to provide one or both of mechanical and electrical power. As shown in
The first and second turbine fuel gas streams 310 and 320 are drawn from fuel gas header 300. When these fuel gas streams comprise higher ethane contents, such as >30 mol %, then first and second gas turbines 700a, 700b may be Siemens gas turbines. Third turbine fuel gas stream 340 is drawn from another source, such as a fuel gas header other than fuel gas header 300. If third turbine fuel gas stream 340 comprises lower ethane contents, such as <25 mol %, preferably <20 mol %, more preferably <15 mol %, even more preferably <10 mol % ethane, then it may be used to fuel a conventional industrial gas turbine, such as a GE Frame 7 gas turbine.
In a further embodiment (not shown in
In another embodiment, a fuel gas stream described herein may be used to supply fuel to one or more boilers in the form of a boiler fuel gas stream.
Furthermore, the fuel gas stream described herein may be used to provide duct firing for a flue gas stream. For instance, a flue gas stream, such as a turbine flue gas stream or a boiler flue gas stream may be passed to a combustion device, where it is mixed with a fuel gas stream, such as the fuel gas stream described herein, and combusted to provide a heated flue gas stream. Such a duct firing operation may raise the temperature of the flue gas stream from 650° C. to 800° C. The heated flue gas stream may then be passed to a heat exchanger where it is cooled against a water stream, to provide a cooled flue gas stream and a heated water stream, more preferably a steam stream, even more preferably a high pressure steam stream.
The heat from the heated turbine flue gas stream 910 may be extracted in a turbine heat exchanger 940, for instance by heat exchange against a second water stream 920, to provide a heated second water stream 930, which is preferably a steam stream, even more preferably a high pressure steam stream, and a cooled turbine flue gas stream 950. The heated second water stream 930 may then be passed to an appropriate header, such as a steam header when a steam stream is produced.
The person skilled in the art will understand that the present invention can be carried out in many various ways without departing from the scope of the appended claims.
The present application claims the benefit of U.S. Provisional Applications Nos. 61/120,086 filed 5 Dec. 2008 and 61/138,725 filed 18 Dec. 2008.
| Number | Date | Country | |
|---|---|---|---|
| 61120086 | Dec 2008 | US | |
| 61138725 | Dec 2008 | US |
