Patent Application
20120324941
The present invention relates to a process for producing a contaminant-depleted hydrocarbon gas stream with improved hydrocarbon recovery. The invention involves removal of acidic contaminants from a hydrocarbon gas stream, such as a natural gas stream, that contains hydrocarbons and acidic contaminants.
Natural gas streams may contain acidic contaminants. The most prominent contaminants are hydrogen sulphide and carbon dioxide (H2S and CO2). Transport and/or treatment of natural gas that contain these contaminants may add to the costs of the transport and/or treatment. The contaminants may also prove corrosive, hydrogen sulphide is toxic and on combustion produces sulphur dioxide, another pollutant. Moreover, carbon dioxide reduces the heating value of natural gas. It is therefore desirable to remove these contaminants from the natural gas streams in an early stage since.
Processes for producing contaminant-depleted gas by removal of contaminants from natural gas streams are known in the art.
For example, in WO 2006/087332, a method has been described for removing contaminating gaseous components, such as carbon dioxide and hydrogen sulphide, from a natural gas stream. In this method a contaminated natural gas stream is cooled in a first expander to obtain an expanded gas stream having a temperature and pressure at which the dewpointing conditions of the phases containing a preponderance of contaminating components, such a carbon dioxide and/or hydrogen sulphide are achieved. The expanded gas stream is then supplied to a first segmented centrifugal separator to establish the separation of a contaminants-enriched liquid phase and a gaseous phase with lowered contaminant content. The gaseous phase with lowered contaminant content is then passed via a recompressor, an interstage cooler, and a second expander into a second centrifugal separator.
A disadvantage of this method is that valuable hydrocarbons are lost via co-condensing and dissolution of hydrocarbons into the cold sour liquid waste stream. Thus, a valuable portion of the valuable hydrocarbons that were produced from a gas well will be lost with the waste stream Further, the use of a recompressor, interstage cooler and an expander between the two centrifugal separators affects the hydrocarbon efficiency of the separation process, which hydrocarbon efficiency is a measure of the fuel gas consumption and the hydrocarbon loss in the liquid phase contaminant streams during the process. The present invention presents a process improvement to recover the hydrocarbons from the liquid waste stream through a second expansion that has been implemented such that, surprisingly, overall, the amount of hydrocarbons lost with the liquid waste stream reduces by a fraction that compensates the required additional power and investments.
To this end, the invention provides a process for producing a contaminant-depleted gas stream from a contaminated hydrocarbon feed gas stream containing at least 10 vol. % of acidic contaminants, in particular H2S and CO2, the method comprising the steps of:
wherein step (d) prior to separating remaining hydrocarbons, further comprises the step of:
Optionally, the contaminated hydrocarbon feed gas stream is cooled prior to step (a).
The process enables an improved hydrocarbon recovery compared to known process for producing contaminant-depleted hydrocarbon gas. The hydrocarbon recovery is suitably in the range of from 1% to 90%.
By a hydrocarbon feed gas stream is understood any gas stream that contains significant amounts of hydrocarbons, especially methane. It includes a natural gas stream, an associated gas stream or a coal bed methane stream. The hydrocarbon fraction in such a gas stream is suitably from 10 to 85 vol % of the gas stream, preferably from 25 to 80 vol %. Especially the hydrocarbon fraction of the natural gas stream comprises at least 75 vol % of methane, preferably at least 90 vol %, of the total hydrocarbon fraction. The hydrocarbon fraction in the natural gas stream suitably contains from 0.1 to 20 vol %, suitably from 0.1 to 10 vol %, of C2-C6 or higher hydrocarbon compounds and/or comprises up till 20 vol %, suitably from 0.1 to 10 vol % of nitrogen.
Natural gas streams may become available at a temperature of from −5 to 150° C. and a pressure of from 20 to 700 bar. In the process of the present invention the natural gas stream comprises suitably hydrogen sulphide and/or carbon dioxide as acidic contaminants. It is observed that also minor amounts of other contaminants may be present, e.g. carbon oxysulphide, mercaptans, alkyl sulphides and aromatic sulphur-containing compounds. The major part of these components will also be removed in the process of the present invention. The acidic contaminants may occur naturally or partly or completely result from injection or re-injection into the subsurface reservoir.
The amount of hydrogen sulphide in the hydrocarbon feed gas stream is suitably from 1 ppmv to 80 vol %, preferably above 5 vol % more preferably above 10 vol %, above 20 vol % oe even above 25 vol % and preferably below 50 vol %, based on the hydrocarbon feed gas stream. The amount of carbon dioxide in the hydrocarbon feed gas stream is suitably from 5 to 80 vol %, preferably above 10 vol % and below 30 vol %, based on the hydrocarbon feed gas stream. Basis for these amounts is the total volume of hydrocarbons, hydrogen sulphide and/or carbon dioxide and other components that together form the hydrocarbon feed gas stream. It is observed that the present process is particularly suitable for gas streams comprising large amounts of acidic contaminants, e.g. 10 vol % or more, suitably from 15 to 90 vol % of the hydrocarbon feed gas stream.
Natural gas streams produced from a subsurface formation typically contain water. In order to prevent the formation of gas hydrates in the present process, at least part of the water is suitably removed. Therefore, the natural gas stream that is used in the present process has preferably been dehydrated. This can be done by conventional processes. A suitable process is the one described in WO-A 2004/070297. Other dehydration processes include treatment with molecular sieves or drying processes with glycol. Suitably, water is removed until the amount of water in the natural gas stream comprises at most 50 ppmw, preferably at most 20 ppmw, more preferably at most 1 ppmw of water, based on the total natural gas stream.
Optionally, prior to step a the contaminated hydrocarbon feed gas stream is cooled in a heat exchanger to obtain a cooled contaminated hydrocarbon feed gas stream. Suitably, the gas stream is cooled to a temperature in the range of from 0 to 40° C., preferably from 3 to 25° C., depending on the composition of the hydrocarbon feed gas stream. The heat exchanger suitably makes use of a heat exchange medium. The heat exchange medium may be any available cold medium, in particular the sweet natural gas stream or the liquid solution of acidic contaminants.
In step (a) the optionally cooled contaminated hydrocarbon feed gas stream is suitably expanded from a pressure ranging from 70 to 200 bar to a pressure ranging from 5 to 30 bar. Such expansion typically will lead to a temperature decrease that is sufficient to start liquefaction of acidic contaminants. The temperature of the natural gas stream is preferably cooled by expansion from a range of −20 to 50° C. to a range from −30 to −80° C.
The expansion is done in such a way that no solid acidic contaminants are formed. This is suitably achieved by conducting the expansion step in a temperature region at least 3° C., preferably at least 5° C. above the temperature at which acidic contaminants begin to solidify. It will be understood that this temperature depends on the type of acidic contaminants and the composition of the mixture and on the pressure. The skilled person will be able to determine the conditions at which the expansion step needs to be conducted.
The expansion can be achieved by any method known to the skilled person, including methods based on the use of turbo-expanders, so-called Joule-Thomson valves and venturi tubes. It is preferred to at least partly cool the gas stream over a turbo-expander, releasing energy. One advantageous effect of using the turbo-expander is that the almost isentropic expansion in a turbo-expander results in optimal cooling per bar pressure drop and, thus, saves energy for compression of at least part of the contaminant-depleted gas stream. Since the stream of the contaminant-depleted gas is smaller than the feed gas stream now that acidic contaminants have been removed, the energy is suitably such that the contaminant-depleted gas may be compressed to an elevated pressure that makes it suitable for transport in a pipeline.
In step (b), at least part of the contaminants in the expanded contaminated hydrocarbon feed gas stream is allowed to liquefy to form a dispersion of a contaminants enriched liquid phase still comprising a small amount of hydrocarbons and a gaseous phase with lowered contaminant content. The gaseous phase with lowered contaminant content may still comprise a considerable amount of contaminants, suitable up to 30%, based on the total gaseous phase with lowered contaminant content.
A preferred way of achieving this is to adjust the residence time of the expanded gas stream between step (a) and step (c) such that at least part of the contaminants will liquefy by a combination of nucleation and coagulation. Thus, a dispersion of a contaminants-enriched liquid phase in a gaseous phase with lowered contaminant content is formed before separation takes place in the first separator. Preferably, the residence time between the expander and the first separator is in the range of from 0.5 to 5 seconds, in order to allow for sufficient nucleation of the contaminants-enriched phase followed by sufficient coagulation of droplets to form droplets with a diameter in the micrometer range. The formation of the dispersion suitably takes place in an insulated conduit connecting the expander with the first separator.
In step (c) at least part of the contaminants-enriched liquid phase comprising hydrocarbons is separated from the gaseous phase with lowered contaminant content in a first separator.
In step (d) remaining hydrocarbons are separated from the liquid stream in a second separator, thereby obtaining an overhead stream comprising remaining hydrocarbons and a bottom stream depleted in hydrocarbons.
In step (d1), which takes place prior to the separation in step (d), the pressure of the liquid stream is increased to typically above 8 bar, preferably above 10 bar and typically below 50 bar, preferably below 20 bar.
Optionally, step (d) prior to separating remaining hydrocarbons, further comprises one or more of the steps of:
These optional steps result in a better separation of remaining hydrocarbons.
The first and/or the second separator may be any separator suitable for separating the fractions. However, it has been found that two types of separators offer advantages.
One preferred type of separator that can used as a first and/or the second separator is a centrifugal separator comprising a bundle of parallel channels that are arranged within a spinning tube parallel to an axis of rotation of the spinning tube.
Another preferred type of separator that can be used as first and/or second separator is a gas/liquid separator vessel, comprising a gas/liquid inlet at an intermediate level, a liquid outlet arranged below the gas/liquid inlet and a gas outlet arranged above the gas/liquid inlet.
It is preferred to use a separator which comprises two trays between which open-ended swirl tubes extend, each from an opening in one tray to some distance below a coaxial opening in the other tray, each swirl tube having been provided with swirl means to impart a rotary movement to gas entering the swirl tube. Such a separator has been described in EP-A 48 508. This separator basically comprises a number of swirl tubes, which are arranged between two trays in a separation vessel. In accordance with the teachings of EP-B 195 464 it is suitable to provide the separator according to EP-A 48 508 with a coalescer, e.g. a demister mat. Such mats are relatively tenuous (have a large permeability) and have a relatively large internal surface area. Thereon, small droplets of liquid will coalesce and drop down from the coalescer, whereby the removal efficiency is enhanced. If desired, it is also feasible to expose the contaminant-depleted hydrocarbon gas to a demister mat after leaving the swirl tubes. Accordingly, the separator suitably comprises further a coalescer, upstream and/or downstream of the swirl-tubes.
In a preferred embodiment of the present process the separator comprises a housing with a gas inlet for the cooled natural gas stream at one end of the housing, a separating body, a gas outlet for contaminant-depleted gas at the opposite end of the housing and a contaminants outlet downstream of the separating body, wherein the separating body comprises a plurality of channels over a part of the length of the axis of the housing, which ducts have been arranged around a central axis of rotation. Suitable separators have been described in e.g. EP-B 286160, WO-A 2007/097621, U.S. Pat. No. 5,667,543 and WO-A 2006/087332. In a preferred embodiment the separator has been provided with a tangential gas inlet. That has the advantage that the gas is brought into a swirling motion, thereby obtaining a preliminary separation of droplets of liquefied acidic contaminants and gas. In such a situation the separator is preferably provided with an additional liquid outlet upstream of the separating body. It is also possible to provide a central gas inlet with swirl-imparting means. The known separators can be manufactured in a variety of ways. In one specific embodiment of the separator the channels consist of corrugated material wrapped around a shaft or a pipe. The material can consist of paper, cardboard, foil, metal, plastic or ceramic.
Alternatively, the separator has been composed of a plurality of perforated discs wherein the perforations of the discs form the channels. The channels may be given a varying hydraulic diameter and/or be arranged in a non-parallel way with regard to the central axis of rotation. Although certain embodiments of such separators make it easy to arrange for channels that are non-parallel to the central axis of rotation, it is preferred to have parallel channels. The manufacture of parallel channels is easier and the separation under the process conditions is not substantially affected.
In a most preferred embodiment, a separator is used comprising:
The separator may have a small or large number of channels. The prior art separators have a number of channels suitably ranging from 100 to 1,000,000, preferably from 500 to 500,000. The diameter of the cross-section of the channels can be varied in accordance with the amount of gas and amounts and nature, e.g., droplet size distribution, of contaminants and the desired contaminants removal efficiency. Suitably, the diameter is from 0.05 to 50 mm, preferably from 0.1 to 20 mm, and more preferably from 0.1 to 5 mm. By diameter is understood twice the radius in case of circular cross-sections or the largest diagonal in case of any other shape.
The size of the separator and in particular of the channels may vary in accordance with the amount of gas to be treated. In EP-B 286 160 it is indicated that separators with a peripheral diameter of 1 m and an axial length of 1.5 m are feasible. The separator in the present invention may suitably have a radial length ranging from 0.1 to 5 m, preferably from 0.2 to 2 m. The axial length ranges conveniently from 0.1 to 10 m, preferably, from 0.2 to 5 m.
For the process according to the invention the separator suitably rotates at a velocity of from 100 to 3000 rpm at the temperature and pressure conditions described above.
In step (e), the overhead stream comprising remaining hydrocarbons is led to a point prior to step d).
Several ways of executing the invention, and in particular step (e), are possible.
Without wishing to restrict the invention to specific embodiments, preferred ways of executing the invention, and in particular step (e), will be illustrated using
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 same or similar elements.
In
In
In
From the first separator 8, a contaminant-depleted hydrocarbons stream are led via conduit 17 to the second heat exchanger 4, where it is heat exchanged against the cooled feed gas stream. The resulting heat exchanged contaminant-depleted hydrocarbons stream is led via conduit 18 to a compressor 19, where it is compressed. Compressed contaminant-depleted gas is led from the compressor via conduit 20.
In
In
The invention will be illustrated using the following, non-limiting, examples.
A dry contaminated natural gas stream of 74660 kmole/hr with the feed composition given in Table 1 at a pressure of 88 bar and a temperature of 26° C. is pre-cooled over a heat exchanger to 8° C. and, subsequently, expanded over a turbo-expander to a pressure of 10 bar. The expansion causes the temperature to drop to −54° C. and a fraction of the stream to condense. The two-phase stream is phase separated over a separator to produce the comprising vapour and liquid streams with the compositions given in Table 1. The vapour stream is heat-exchanged with the above mentioned feed gas stream and, subsequently, is compressed to a pressure of 25 bar using a compressor that is driven on the shaft of the above mentioned turbo-expander. Subsequently, the vapour is compressed in a few stages to 90 bar export pressure. The liquid stream produced in the phase separator, which is considered the waste stream, e.g. to be re-injected into a subsurface reservoir, is pumped to a pressure of 80 bar before cross-exchange with the above mentioned feed gas stream. From Table 1, it can be deducted that 675 kmoles/hr of valuable hydrocarbons are lost to the liquid waste stream.
A dry contaminated natural gas stream of 74660 kmole/hr with the composition given in Table 2 at a feed pressure of 88 bar and a temperature of 26° C. is pre-cooled over a heat exchanger to 7° C. and, subsequently, expanded over a turbo-expander to a pressure of 10 bar. The expansion causes the temperature to drop to −55° C. and a fraction of the stream to condense. The expanded stream is combined with a vapour stream (4400 kmoles/hr) from the downstream hydrocarbon recovery stage described below. The individual phases in the combined two-phase stream, then, have the composition given in Table 2. Subsequently, the combined stream is phase separated over a first separator to produce the comprising vapour and liquid streams. The vapour stream cross-exchanges heat with the above mentioned feed gas stream and, subsequently, is compressed to a pressure of 25 bar by a compressor that is driven on the shaft of the above mentioned turbo-expander. Subsequently, the vapour is compressed in a few stages to 90 bar export pressure. The liquid stream produced in the phase separator is pumped to a pressure of 25 bar before cross-exchange with the above mentioned feed gas stream, where it heats up to −20° C. This warm liquid stream is expanded to a pressure of 10 bar, which causes a fraction (16 mole %) of the liquid to evaporate. The two-phase stream (27570 kmoles/hr) is, subsequently, phase separated in a second separator. The produced liquid and gas compositions are given in Table 3. The vapour stream from the separator is combined with the feed into the first phase separator. The liquid stream is pumped to a pressure of 80 bar and exported as waste, e.g., for re-injection in a subsurface reservoir. From Table 3, it can be deducted that only 183 kmoles/hr of valuable hydrocarbons are lost to the liquid waste stream.
A dry contaminated natural gas stream of 29960 kmole/hr with the feed composition given in Table 4 at a pressure of 88 bar and a temperature of 26° C. is pre-cooled over a heat exchanger to 8° C. and, subsequently, expanded over a turbo-expander to a pressure of 10 bar. The expansion causes the temperature to drop to −54° C. and a fraction of the stream to condense. The two-phase stream, then, is phase separated over a separator to produce the comprising vapour and liquid streams with the compositions given in Table 4. The vapour stream cross-exchanges heat with the above mentioned feed gas stream and, subsequently, is compressed to a pressure of 25 bar by a compressor that is driven on the shaft of the above mentioned turbo-expander. Subsequently, the vapour is compressed in a few stages to 90 bar export pressure. The liquid stream produced in the phase separator, which is considered the waste stream, e.g. to be re-injected into a subsurface reservoir, is pumped to a pressure of 80 bar before cross-exchange with the above mentioned feed gas stream. From Table 4, it can be deducted that 449 kmoles/hr of valuable hydrocarbons are lost to the liquid waste stream.
A dry contaminated natural gas stream of 29960 kmole/hr with the composition given in Table 5 at a feed pressure of 122 bar and a temperature of 30° C. is pre-cooled over a heat exchanger to 11° C. and, subsequently, expanded over a turbo-expander to a pressure of 14 bar. The expansion causes the temperature to drop to −54° C. and a fraction of the stream to condense. The expanded stream is combined with a vapour stream (1133 kmoles/hr) from the downstream hydrocarbon recovery stage described below. The individual phases in the combined two-phase stream, then, have the composition given in Table 5. Subsequently, the combined stream is phase separated over a first separator to produce the comprising vapour and liquid streams. The vapour stream cross-exchanges heat with the above mentioned feed gas stream and, subsequently, is compressed to a pressure of 34 bar by a compressor that is driven on the shaft of the above mentioned turbo-expander, after which the gas is fed into a next stage step in the total separation train, e.g. a solvent process.
The liquid stream produced in the phase separator is pumped to a pressure of 60 bar before cross-exchange with the above mentioned feed gas stream, where it heats up to −9° C. This warm liquid stream is expanded to a pressure of 14 bar, which causes a fraction (13 mole %) of the liquid to evaporate. The two-phase stream (8769 kmoles/hr) is, subsequently, phase separated in a second separator. The produced liquid and gas compositions are given in Table 6. The vapour stream from the separator is combined with the feed into the first phase separator. The liquid stream is pumped to a pressure of 215 bar and exported as waste, e.g. for re-injection in a subsurface reservoir. From Table 6, it can be deducted that only 160 kmoles/hr of valuable hydrocarbons are lost to the liquid waste stream.
A water dry contaminated natural gas stream of 29970 kmole/hr with the feed composition given in Table 7 at a pressure of 147 bar and a temperature of 30° C. is expanded over a turbo-expander to a pressure of 15 bar. The expansion causes the temperature to drop to −46° C. and a fraction of the stream to condense. The two-phase stream, then, is phase separated over a separator to produce the comprising vapour and liquid streams with the compositions given in Table 7. The vapour stream is compressed to a pressure of 47 bar by a compressor that is driven on the shaft of the above mentioned turbo-expander. Subsequently, the vapour is compressed to 90 bar export pressure.
The liquid stream produced in the phase separator, which is considered the waste stream, e.g. to be re-injected into a subsurface reservoir, is pumped to a pressure of 215 bar. From Table 7, it can be deducted that 1681 kmoles/hr of valuable hydrocarbons are lost to the liquid waste stream.
A water dry contaminated natural gas stream of 29970 kmole/hr with the composition given in Table 8 at a feed pressure of 147 bar and a temperature of 30° C. is expanded over a turbo-expander to a pressure of 15 bar. The expansion causes the temperature to drop to −46° C. and a fraction of the stream to condense. The expanded stream is combined with a vapour stream (3126 kmoles/hr) from the downstream hydrocarbon recovery stage described below. The individual phases in the combined two-phase stream, then, have the composition given in Table 8. Subsequently, the combined stream is phase separated over a first separator to produce the comprising vapour and liquid streams. The vapour stream cross-exchanges heat with the overhead stream from a second separator in the downstream hydrocarbon recovery stage described below and, subsequently, is compressed to a pressure of 77 bar by a compressor that is driven on the shaft of the above mentioned turbo-expander, after which the gas is fed into a next stage step in the total separation train, e.g. a solvent process.
The liquid stream produced in the first phase separator is pumped to a pressure of 18 bar before cross-exchange with the overhead stream from a downstream fractionation column described below, where it heats up to around 1° C. This stream is fed into a trayed fraction fraction column with reboiler which produces a stream (619 kmol/hr) rich in heavy hydrocarbons at a temperature of 185° C. The composition of this stream is given in Table 9. The overhead stream of the fractionation column with a temperature of around 5° C. is heat exchanged with the feed stream to the fractionation column, which leads to condensation of the heavier components to form a dispersion. This dispersion (11090 kmoles/hr) is, subsequently, phase separated in a second separator. The produced liquid composition is given in Table 9. The liquid stream is pumped to a pressure of 215 bar and exported as waste, e.g. for re-injection in a subsurface reservoir. From Table 9, it can be deducted that only 456 kmoles/hr of valuable hydrocarbons are lost to the liquid waste stream. The overhead vapour stream from the second separator is heat exchanged with the overhead vapour stream from the first separator and combined with the feed into the first separator.
| Number | Date | Country | Kind |
|---|---|---|---|
| 10155228.9 | Mar 2010 | EP | regional |
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/EP2011/052878 | 2/28/2011 | WO | 00 | 8/30/2012 |
