Patent Application
20180087833
The present invention relates to a process for separating the components of a gas mixture containing methane, nitrogen and hydrocarbons heavier than methane.
The present invention therefore applies to the processes for removing nitrogen from natural gas with or without recovery of helium.
Natural gas is desirable for use as a fuel intended to be used for heating buildings, in order to provide heat for industrial processes for producing electricity, for use as a raw material for various synthesis processes for producing olefins, polymers and the like.
Natural gas is found in many fields that are at a distance from the users of natural gas. Natural gas typically consists of methane (C1), ethane (C2) and heavier compounds such as hydrocarbons having at least three carbon atoms, such as propane, butane, etc. (C3+).
Often, it may be advantageous to separate the C2 and C3+ compounds from the natural gas in order to sell them as separate coproducts.
Specifically, their commercial use is in general greater than the natural gas itself since they can be used directly for chemical processes (manufacturing ethylene from ethane for example), as motor fuels (C3/C4 is a conventional motor fuel referred to as GPL) or for many other applications.
Another component often present in natural gas is nitrogen. The presence of nitrogen in natural gas may lead to difficulties in complying with the specifications for natural gas (typically minimum lower calorific value to be met).
This is even truer when the hydrocarbons heavier than methane (C2 and C3+) are removed since these have a higher lower calorific value than methane, by removing them the lower calorific value is therefore reduced which must then potentially be increased by means of nitrogen separation. Consequently, a considerable effort has been devoted to the production of means for removing the nitrogen present in natural gas.
The natural gas deposits being exploited contain increasing quantities of nitrogen. This is notably because fields that are rich enough for no enrichment treatment to be needed before the gas is commercialized are becoming exhausted and increasingly rare.
These sources of natural gas often also contain helium. The latter can be put to commercial use by performing a pre-concentration before final treatment and liquefaction.
Unconventional resources such as shale gases also share the same problem set: in order to make them commercially viable, it may prove necessary to increase their calorific value by means of a treatment that consists in removing nitrogen from the gas.
The most widely used method for separating nitrogen and the hydrocarbons heavier than methane is “cryogenic separation”. A cryogenic nitrogen separation process, more specifically a process that uses a double column, is described in patent application U.S. Pat. No. 4,778,498. The units for removing nitrogen from natural gas in general treat gases which originate directly from wells at a high pressure. After removal of the nitrogen, the treated gas must be returned to the network, often at a pressure close to the pressure at which it entered it.
During the exploitation of natural gas deposits, many steps may be provided. One relatively conventional step after the drying and the removal of the impurities is the separation of the liquids associated with the natural gas (NGLs).
There may be many advantages of this step but often the advantage is to make commercial use of various “heavy” hydrocarbon products containing at least two carbon atoms (C2, C3, etc.) which are generally sold for considerably more than the natural gas product.
If the natural gas contains nitrogen, there is a risk of again having a natural gas with too low a calorific value due to the resulting low content of C2, C3, etc. It is therefore typical to then have to separate the nitrogen from this gas in order to render it marketable.
One conventional solution is to treat the two problems independently.
A first unit carries out the separation of the NGLs (subsequently referred to as NGL unit) whilst a second unit separates the nitrogen from the natural gas (subsequently referred to as NRU unit).
This solution has the advantage of operational flexibility. For example, if the NRU unit includes a refrigeration cycle, the associated machines have a limited reliability, and a failure of a cycle compressor will lead to the shutdown of the NRU but without leading to the shutdown of the NGL.
Unfortunately, this shutdown will not be able to be of long duration since it would then be necessary to flare the production (due to its excessively low calorific value). Moreover, this scheme is limited in terms of efficiency since all the gas is cooled then reheated in the NGL unit then cooled and reheated in the NRU.
Another solution would consist in wholly integrating the NGL and NRU units, the problem then becomes that the assembly as a whole will have to be shut down immediately in the event of failure of the refrigeration cycle of the NRU unit.
The inventors of the present invention have then developed a solution that makes it possible to resolve the problems raised above.
The subject of the present invention is a process for separating the components of a gas mixture to be treated comprising methane, nitrogen and at least one hydrocarbon having at least two carbon atoms, or a mixture of these hydrocarbons, comprising the following steps:
a) introducing a stream of said gas mixture to be treated at a flow rate greater than or equal to 2 000 000 Nm3/h into a methane removal unit comprising N methane removal columns;
b) partially condensing a gas mixture, comprising less than 1 mol % of hydrocarbons having at least two carbon atoms, extracted from the methane removal unit in order to obtain a liquid, at least one part of which is treated in order to be extracted as denitrogenated natural gas product, and a second gas;
c) introducing said second gas into a nitrogen removal unit comprising N nitrogen removal columns obtained from which are a gas and a liquid, at least one part of which is treated in order to be extracted as denitrogenated natural gas product;
characterized in that said denitrogenated natural gas thus produced comprises less than 5 mol % of nitrogen and in that N is greater than or equal to 3.
According to other embodiments, the process that is the subject of the present invention comprises at least the following features:
Process as defined above characterized in that it comprises the additional step:
d) treating said gas (36) from step c) in a second nitrogen removal unit (B) in order to produce a gaseous nitrogen stream comprising at most 2 mol % of methane and a gaseous methane stream comprising at most 5 mol % of nitrogen.
Process as defined above, characterized in that the second nitrogen removal unit (B) comprises at most N−1 nitrogen removal columns.
Process as defined above, characterized in that N is greater than or equal to 6.
Process as defined above, characterized in that the second nitrogen removal unit (B) comprises between N−5 nitrogen removal columns and N−1 nitrogen removal columns, preferably from N−4 to N−2 nitrogen removal columns.
Process as defined above, characterized in that the steps b) and c) are carried out at a temperature below −50° C. and the fluid is not reheated above −50° C. between step b) and step c).
The invention will be described in more detail by referring to the FIGURE that illustrates a process according to the invention.
A stream 1 of natural gas previously pretreated (separation of water, of CO2, of methanol, of very heavy hydrocarbons, that is to say having more than six or seven carbon atoms (such as C8+ hydrocarbons for example) comprising at least 30 mol % of methane, 0.1 mol % of hydrocarbons heavier than methane (that is to say comprising at least two carbon atoms) and 4 mol % of nitrogen is introduced into a system 2 enabling an at least partial condensation of said stream 1.
The pressure of this stream 1 is between 20 bara (bar absolute) and 100 bara (typically between 30 and 70 bara) and the temperature is close to ambient temperature, for example between 10° C. and 30° C.
The system 2 is for example a heat exchanger. The mixture 3 leaving this system 2 is in a two-phase (gas and liquid) state. This mixture 3 is introduced into a phase separator vessel 4.
The operating pressure is between 20 and 100 bara, typically between 30 and 70 bara. The temperature of this vessel is between −100° C. and 0° C., typically between −80° C. and −20° C.
The liquid phase 5 from the separator vessel 4 is expanded through a valve 6 then injected, at a pressure between 10 bara and 40 bara and a temperature for example between −110° C. and −30° C., into a methane removal column 7.
A methane removal column is understood to mean a distillation unit intended to produce at least two streams of different compositions from feed streams originating from the stream 1 of natural gas to be treated according to the process of the present invention.
The at least two streams are the following: one gaseous, depleted in hydrocarbons having at least two carbon atoms, that is to say comprising less than half of the “heavy” hydrocarbons contained in the feed gas (ethane, propane, butane, etc.) and the other, in liquid form, containing less than 5 mol % of the methane initially present in the stream 1 of natural gas to be treated.
A methane removal unit is understood to mean any system comprising at least one distillation column for enriching the overhead gas with methane and depleting the bottom liquid of methane.
At least one part of the gas phase (one part only typically) 8 from the separator vessel 4 is expanded by means of a turbine 9.
The stream from the turbine 9 is introduced into the column 7 at a higher stage 10 than the stage where the liquid 5 leaving the valve 6 is introduced.
A liquid stream 12 of heavier hydrocarbons than methane is recovered in the bottom part 16 of the column 7.
A reboiler 11 is placed at a level that makes it possible to reboil the bottom liquid from the column 7 in order to reheat a part of the liquid of said column for the purpose of adjusting the maximum limit of methane contained in the stream 12 of heavy hydrocarbons.
At least 50 mol % (typically, at least 85 mol %) of the heavy hydrocarbons present in the gas mixture 1 to be treated are recovered in this stream 12. Preferably at least 90% are recovered.
Preferably, the liquid stream 12 of hydrocarbons does not contain more than 1 mol % of methane.
A heat exchanger 13 may be installed in order to reheat the bottom part of the column 7 (bottom part=below the introduction of the liquid originating from the vessel 4). This exchanger is fed by the gaseous feed stream 1. This reheating improves the equilibrium between search for maximum efficiency and purity of the stream leaving the methane removal column 7.
At the top 14 of the column 7 (top=highest outlet of the column), a methane-enriched gas stream 15, typically containing less than 0.5 mol % of hydrocarbons having more than two carbon atoms (containing at most half of the amount of heavy hydrocarbons—having more than 2 carbon atoms—present in the feed gas) is extracted. The temperature of the gas stream 15 is below −80° C.
Consequently, the cold may be recovered by condensing a methane-enriched gas under pressure. This condensation is carried out owing to a heat exchanger 17 fed both with a part of the gas stream 8 from the separator vessel 4 and with the methane-enriched gas stream 15 from the top 14 of the methane removal column 7.
This is only one example of implementation of the process that is the subject of the invention. But according to a particular embodiment of the invention, a third stream to be condensed could be introduced into this exchanger.
According to yet another embodiment of the invention, only one of the two streams described would be to be condensed.
A methane-enriched gas is understood to mean a gas mixture containing methane, nitrogen and typically less than 0.5% of hydrocarbons having more than two carbon atoms (containing at most half of the amount of heavy hydrocarbons—having more than 2 carbon atoms—present in the feed gas).
The stream(s) 18 (18a and 18b) which has been cooled in the exchanger 17 is expanded by means for example of at least one valve 19 (19a, 19b), then is introduced into an upper part (upper part=above the feed 10 leaving the turbine 9) of the column 7.
The stream 20 which has been reheated in the exchanger 17 contains at most half of the amount of heavy hydrocarbons—having more than 2 carbon atoms—present in the feed gas.
The gas stream 20 reheated in the exchanger 17, to a temperature between −40° C. and −70° C., preferably of the order of −60° C., is then partially condensed by means, for example, of a heat exchanger 21.
At the outlet of this exchanger 21, a two-phase (gas-liquid) stream 22 emerges (comprising from 20 to 80 mol % of gas).
Alternatively, it is possible to dispense with the preceding step, that is to say with the passage of the stream 15, extracted from the top of the methane removal column 7, into the heat exchanger 17.
It is therefore possible to maintain the temperature of the stream 15 below −80° C. (or even below −100° C.) and to introduce said stream 15 directly into the heat exchanger 21 in order to obtain the stream 22.
The stream 22 is then sent to a nitrogen removal system A according to the invention described below.
In the nitrogen removal system A, the two-phase stream 22 is, after a possible expansion in a valve or a turbine 23, introduced into a phase separator vessel 25.
The liquid phase 29 resulting from the phase separator vessel 25 is, after a possible expansion in a valve (not represented in the figure), reheated through heat exchangers 27 then 21 and finally 2 in order to rejoin the outlet stream 30 of methane-rich gas produced at the outlet of the process.
The outlet stream 30 contains less than 5 mol % of nitrogen.
The gas phase 26 resulting from the separator vessel 25 is partially condensed in a heat exchanger 27 then expanded on leaving said exchanger 27 by means of a turbine or a valve before being introduced into a distillation column 31.
The distillation column 31 is a nitrogen “stripping” column, the purpose of which is to separate the nitrogen from the methane-enriched outlet liquid, also referred to as nitrogen removal column.
The methane-enriched liquid comprises less than 5 mol % of nitrogen. It is a question here of a distillation column connected to a reboiler 32 but not having an associated condenser system.
At the bottom of column 31, at a temperature below −100° C., preferably below −110° C., a very methane-rich stream 33 in liquid form is extracted. This stream 33 contains less than 5 mol % of nitrogen, preferentially less than 4%. The liquid stream 33 is then mixed with the liquid phase 29 resulting from the phase separator vessel 25 and follows the same path to the outlet stream 30.
A part 32 of the mixed stream containing in part the liquid phase 29 and the liquid 33 and reheated through the heat exchanger 27 is recycled to the bottom part 34 of the nitrogen removal column 31.
At the top 35 of column 31, a nitrogen-rich gas stream 36, at a temperature below −110° C., is produced. Said nitrogen-rich stream 36 comprises at least 20 mol % of nitrogen.
The nitrogen-rich stream 36 is reheated through successive exchangers 27, 21 then 2. These may be one and the same exchanger according to one particular embodiment of the invention. And according to another particular embodiment of the invention, more than three exchangers may be used.
This results in a stream 37, at a temperature close to ambient temperature (above −10° C. typically and below 50° C.), sent to an additional nitrogen removal system B.
The objective of the nitrogen removal system B is to produce a gas stream even richer in nitrogen than the stream 37.
This system B may for example include at least one separator vessel and a nitrogen removal column. If the specification of the nitrogen at the outlet of the system B is strict (<100 ppm typically), it may prove necessary to add a cycle compressor, for example a nitrogen compressor, to the system B in order to provide the reflux needed to obtain the nitrogen purity at the top of the nitrogen removal column of the system B.
The process that is the subject of the present invention makes it possible to:
not be obliged to flare the gas in a failure mode of the refrigeration cycle of the nitrogen removal system (failure of the cycle compressor);
improve the efficiency of the process.
Specifically, if a failure takes place in the nitrogen removal system B, it will be possible all the same to continue the implementation of the process and produce a large part, typically at least 80%, of the desired products (denitrogenated methane) owing to the nitrogen removal system A.
This is because the solution proposed is to partially integrate the nitrogen removal system with the system for extracting the products resulting from the “NGL part”. This partial integration consists in integrating at least a first separator vessel after the methane removal column of the “NGL process”. Recovered from this first separator vessel, in liquid form, will be at least one part of the natural gas product. This product will be at least partially denitrogenated, making it possible in certain cases to attain the specification in terms of calorific value of the product. In addition to this first vessel, a first nitrogen removal column may be integrated into the “NGL part”, this makes it possible to increase the propart of product at the specification that is directly produced using the nitrogen removal system.
The expression “NGL part” is understood to mean all the steps of the process according to the invention prior to step c).
A last very cold part then remains (where the temperature levels reached are below −140° C.), preferably below −160° C., in which a refrigeration cycle may be used if necessary.
A failure of the refrigeration cycle would then lead to the shutdown of the nitrogen removal but will be able to maintain part of the production of denitrogenated natural gas and also the production of the products derived from the “NGL part”.
In addition, the use of the process according to the invention makes it possible, in addition to improving the reliability of the plant, to optimize the total investment cost by optimizing the number of elements constituting the various units for implementing said process relative to the incoming flow rate in each unit.
Specifically, it will not be necessary to add as many nitrogen removal systems B as nitrogen removal systems A.
For very large flow rates one or more trains are necessary for the NGL part, the use of at least one train less on the NRU part than on the NGL part (for example: seven trains for the NGL part and three trains for the NRU part) then makes it possible, in addition to improving the reliability of the plant, to optimize the total investment cost by optimizing the number of trains relative to the flow rate entering into each unit.
A train is a treatment unit comprising in general a single piece of equipment for each function of the process (one turbine 9, one separator vessel 4, etc.).
On the other hand it is possible to specifically double one or more pieces of equipment within one and the same train. When the flow rate is too high, it is necessary to use several identical trains, namely several treatment units operating in parallel and with the same pieces of equipment.
It will be understood that many additional changes in the details, materials, steps and arrangement of parts, which have been herein described in order to explain the nature of the invention, may be made by those skilled in the art within the principle and scope of the invention as expressed in the appended claims. Thus, the present invention is not intended to be limited to the specific embodiments in the examples given above.
| Number | Date | Country | Kind |
|---|---|---|---|
| 1552781 | Apr 2015 | FR | national |
This application is a 371 of International PCT Application PCT/FR2015/052632, filed Oct. 1, 2015, which claims priority to French Patent Application No. 1552781, filed Apr. 1, 2015, the entire contents of which are incorporated herein by reference.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/FR2015/052632 | 10/1/2015 | WO | 00 |
