• 专利附录
  • 专利说明
  • 权利要求
  • 类似技术
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    • 专利摘要:
    A crude natural gas stream treatment system comprising a first supersonic separator and a second supersonic separator, wherein the first supersonic separator comprises a crude gas inlet, a dry gas outlet and a first liquid outlet; wherein the second supersonic separator comprises a dry gas inlet, a treated gas outlet and a second liquid gas outlet, and wherein the dry gas outlet is in fluid communication with the dry gas inlet is disclosed.
    公开号:AU2013224145A1
    申请号:U2013224145
    申请日:2013-02-21
    公开日:2014-09-11
    发明作者:Erik Baggerud；Jostein KOLBU；Robert Perry
    申请人:FMC Kongsberg Subsea AS；
    IPC主号:C10L3-10
    专利说明:
    WO 2013/124339 PCT/EP2013/053420 1 GAS TREATMENT SYSTEM USING SUPERSONIC SEPARATORS The present invention relates to a gas treatment system for conditioning of a crude natural gas stream. Especially the present invention relates to a compact system for dew pointing and sweetening of crude natural gas. The system is applicable both for 5 topside and subsea gas treatment. Background The invention comprises a gas treatment system for removal of CO 2 to meet the specification on CO 2 content in downstream export pipelines to avoid corrosion, additionally the system provides for the removal of water. For fields with large 10 volumetric content of CO 2 the removal with re-injection of the CO 2 reduces the volumetric flow rate of export gas, hence potentially reducing the dimensions of export pipelines. The re-inject of CO 2 can further be an EOR (Enhanced Oil Recovery) measure. All these aspects have economical benefits that can be realized in an overall field development. The system may be implemented topside or subsea. 15 In pipeline system for export of gas from a gas field there are usually specific requirements to the maximum allowed CO 2 content in the gas stream. The main reason is that in a system where free liquid water is present CO 2 is a sour component and increases the corrosion rate of the pipeline materials. Further there may be restrictions to the content of CO 2 allowed in the gas at the receiving 20 facilities due to limited processing capacity for CO 2 removal prior to export to the market. For reservoirs where there is significant amounts of CO 2 there are basically two solutions, either make the export pipelines in stainless steel alloy or remove the CO 2 prior to export. The former solution is generally very expensive and will easily 25 make the field development too expensive, of course dependent on the length of the pipeline. Existing CO 2 removal technologies generally comprise physically large process systems typically membranes or absorption processes (e.g. amine solvent absorption). These processes have considerable complexity and utility requirements (power, heat and/or chemicals). Reducing the size and complexity of the CO 2 30 removal system can potentially be of great interest to the industry. The removal of water is necessary to avoid the formation of ice and hydrates, which can damage equipment like separators, valves, pumps and instrumentation. Prior art Conventional solutions for dehydration of crude natural gas and for removal of acid 35 carbon dioxide comprise the use of a combination of different absorption processes. One known process for dehydration of crude gas is absorption of water vapour in glycol such as TEG (triethylene glycol) to obtain dry natural gas. The glycol is WO 2013/124339 PCT/EP2013/053420 2 heated to remove the absorbed water and thereafter reused for absorption. Carbon dioxide can be removed by absorption in an amine solution; different types of amines are presently being used for this type of processing. Bringing the gas in sufficient contact with the absorbent solution requires considerable effort and has 5 previous been performed using contactor columns of considerable heights. The absorbent is regenerated in a stripper column requiring heating. Alternative prior art solutions for carbon dioxide removal from natural gas involve the use of selective membranes where carbon dioxide is forced to pass a membrane by a concentration and/or pressure gradient. 10 W02006/089948 discloses a method and system for cooling a natural gas stream and separating the cooled stream into various fractions, such as methane, ethane, butane and propane, utilizing a supersonic or transonic cyclonic expansion and separation device. WO 00/40834 elates to a method for removing condensables from a natural gas 15 stream, at a wellhead, downstream of the wellhead choke thereof. The natural gas stream is induced to flow at supersonic velocity through a conduit of a supersonic inertia separator and thereby causing the fluid to cool to a temperature that is below a temperature/pressure at which the condensables will begin to condense. Objectives of the invention 20 The present invention aims at providing a compact gas treatment system. The treatment system should limit the pressure loss and need for re-pressurisation. Further in a preferred embodiment the system should be applicable for subsea operation providing the possibility to keep the natural gas or at least the main part there of subsea during the whole treatment process. The system and process should 25 result in a gas stream of pipeline export quality with limited demands to the pipeline material, and with limited tendency to form gas hydrates. An objective of the invention is to provide a topside gas treatment system replacing physically large units of conventional technologies. It is also a goal to provide a system and a method that would facilitate for moving processing today performed at 30 a platform to the seabed and make topside facilities obsolete. Accordingly it is an intension that the system and method are able to process gas to meet the specification of the export pipeline as well as removing CO 2 in the fluid subsea, which will reduce the need for treatment systems at the receiving facilities, pending on the end-use of the gas. 35 These and other objectives are achieved through [the use of] the system and method according to the present invention. The present invention provides a crude natural gas stream treatment system comprising a first supersonic separator and a second supersonic separator, wherein WO 2013/124339 PCT/EP2013/053420 3 the first supersonic separator comprises a crude gas inlet, a dry gas outlet and a first liquid outlet; wherein the second supersonic separator comprises a dry gas inlet, a treated gas outlet and a second liquid outlet, and wherein the dry gas outlet is in fluid communication with the dry gas inlet. 5 In one aspect of the invention the system further comprises a first additional separation system with at least a treated gas inlet, a sweet gas outlet, a CO 2 gas outlet, wherein the treated gas outlet is in fluid communication with the treated gas inlet. The first additional separation system is in one embodiment an absorption solution 10 cycle system and in another embodiment the first additional separation system is a membrane separation system. In another aspect of the present invention the system further comprises a first heat exchanger with a cooling medium inlet in fluid communication with the treated gas outlet and a cooling medium outlet in fluid communication with the treated gas 15 inlet, and an inlet for a medium to be cooled in fluid communication with the dry gas outlet and a cooled fluid outlet in fluid communication with the dry gas inlet. In yet another aspect the system further comprises a second additional treatment system with at least a fluid inlet, a CO 2 outlet and a hydrocarbon outlet, wherein the second liquid outlet is in fluid communication with the fluid inlet, and the 20 hydrocarbon outlet is in fluid communication with the treated gas outlet or the sweet gas outlet. In one embodiment the second additional separation system is an absorption solution cycle system in another embodiment the second additional separation system is a membrane separation system, in yet another embodiment the second 25 additional separation system is flash separation system. In another embodiment the second separator system may be a membrane separation system, with the membrane system adapted to separate out the wanted element. Further the second additional separation system may also be a third supersonic separator. In an aspect of the present invention the system further comprises a first heat 30 exchanger with a cooling medium inlet in fluid communication with the second liquid outlet and a cooling medium outlet in fluid communication with the fluid inlet, and an inlet for a medium to be cooled in fluid communication with the dry gas outlet and a cooled fluid outlet in fluid communication with the dry gas inlet. In another aspect the first liquid outlet is in fluid communication with a well stream 35 upstream an initial phase separator, where the initial phase separator comprises a crude gas outlet in fluid communication with the crude gas inlet.
    WO 2013/124339 PCT/EP2013/053420 4 In one aspect of the present invention the system is applicable for subsea installation. Further the present invention provides a crude natural gas treatment method, comprising passing crude natural gas through a first supersonic separator and a 5 second supersonic separator, wherein the first supersonic separator the crude natural gas is cooled and a first condensed liquid stream is separated of providing a dry gas stream, and wherein the second supersonic separator the dry gas is cooled and a second condensed liquid stream is separated of, thereby providing a treated gas stream. 10 In one aspect of the method the second liquid stream comprises mainly C0 2 , and C2 to C4 hydrocarbons. In another aspect the method further comprises feeding the treated gas to a first additional treatment system. In yet another aspect the first additional treatment system comprises bringing the 15 treated gas in contact with a CO 2 absorption solution, absorbing CO 2 in the solution, thereby obtaining a sweetened gas stream, and regaining the solution by desorption of the absorbed CO 2 or the first additional treatment system comprises bringing the treated gas in contact with a CO 2 selective membrane, letting CO 2 pass trough the membrane to obtain a sweetened gas stream. 20 In another aspect the method further comprises heating the treated gas upstream the first additional treatment system by heat exchange with the dry gas. An aspect of the invention is feeding the second liquid to a second additional treatment system. Optionally the method comprises heating the second liquid through heat exchange with the dry gas upstream the second supersonic separator, 25 thereby obtaining a second fluid. The second additional treatment system may comprise bringing the second fluid in contact with a CO 2 absorption solution, absorbing CO 2 in the solution, thereby obtaining a hydrocarbon gas stream, and regaining the absorption solution by desorption of the absorbed C0 2 , or it may comprise bringing the second fluids in 30 contact with a CO 2 selective membrane, letting CO 2 pass trough the membrane to obtain a hydrocarbon gas stream. Alternatively the second additional treatment system comprises flashing of hydrocarbons from the second liquid to obtain liquid
    CO
    2 or the second additional treatment system comprises passing second fluid trough a third supersonic separator, condensing and separating of liquid CO 2 and 35 obtaining hydrocarbon gas.
    WO 2013/124339 PCT/EP2013/053420 5 One aspect of the present invention comprises feeding the first liquid to a well stream upstream a phase separator, where the crude natural gas stream is obtained from said phase separator. It is an aspect of the present invention that the method is performed subsea. 5 Brief description of the drawings The present invention will be described in further detail with reference to the enclosed drawings. The drawings are schematic diagrams illustrating the main principles of the invention. 10 Figure 1 shows the overall system from the subsea well to the gas receiving facilities. Figure 2 illustrates the main principles of a first embodiment of the present invention. Figure 3 illustrates in further details the first embodiment of the present invention. 15 Figure 4 illustrates a second embodiment of the present invention. Figure 5 illustrates a third embodiment of the present invention. Figure 6 illustrates a first possible embodiment of an additional treatment system. Figure 7 illustrates a second possible embodiment of an additional treatment system. 20 Figure 8 illustrates a third embodiment of an additional treatment system. Principal description of the invention The present invention relates to a gas treatment system. The term "gas treatment system" as applied here is used to refer to a system for processing the gas stream separated from a well stream to obtain a gas stream that can be exported. This 25 function of the gas treatment system is illustrated in figure 1. Here three subsea wells deliver a well stream comprising free liquid, the free liquid comprises water and condensate, to a gas/liquid separator. The well stream is a water saturated hydrocarbon stream and before entering the gas treatment system according to the invention this well stream is processed in a phase separator. The separator may be a 30 two phase or three phase separator, and the configuration thereof can be freely selected as long as the separator provides a generally liquid free gas stream. The generally liquid free gas stream is hereinafter referred to as crude natural gas stream. It is this generally liquid free gas stream that the gas treatment system WO 2013/124339 PCT/EP2013/053420 6 according to the present invention is prepared to process. Gas streams from potential downstream liquid treatment steps may be boosted and combined with the primary liquid free gas stream. The treatment system produces a dew pointed gas stream with a lowered CO 2 content that can be transported through an export gas 5 pipeline to receiving facilities. CO 2 rich stream separated from the gas stream can be transported to an injection well for re-injection possible to keep up the reservoir pressure. Liquid streams from the gas/liquid separator and the gas treatment system can be processed through other system not forming a part of the present invention. One embodiment of the present invention can remove the need for large and 10 complex processes and replace it by more compact supersonic separation technology. This can reduce the overall footprint, operational complexity and utility cost for the CO 2 removal system. Figure 2 illustrates a first embodiment of the present invention. A well stream 1 comprising gas and liquid enters a phase separator 2 to obtain a gas stream 3 and a 15 liquid stream 7. This gas stream 3 is fed to a first super sonic separator unit 4 resulting in cooling and separation of water and heavy hydrocarbons as liquid stream 9 which is returned to the well stream or as stream 9"' combined with stream 7 for potential further treatment. The term "heavy hydrocarbons" refers to hydrocarbons with a dew point which is higher or in the proximity of the water dew 20 point. The gas stream 11 leaving the first super sonic separator unit 4 will be dry, the dry gas stream, that is to say it will contain limited amounts of water or other compounds which during transport or storage of the gas at low temperature would result in the formation of a liquid phase. The dry gas stream 11 is fed into a second supersonic separator unit 6 designed to cool and separated CO 2 from the dry gas 25 stream. The liquid stream 17 leaving the separator will comprise liquefied CO 2 together with some liquefied hydrocarbons, mainly C2, C3 and C4. Depending on the composition of the well stream and the separation efficiency the obtained sweetened gas stream 13 may be according to the needed specification and can proceed to the export pipeline without further treatment. However if the sweetened 30 gas stream 13 requires further processing to fulfil the specification for the gas export stream then the stream according to the present invention is fed to an optional first additional gas treatment system 8. In the optional first additional gas treatment system 8 additional CO 2 is removed from the gas. The CO 2 leaves the system 8 as stream 21. The fully sweetened gas 15 leaving the system 8 fulfils the 35 specification and can be compressed and transported to a remote location. The liquid stream 17 from the second supersonic separator may contain hydrocarbons of interest. In one embodiment of the present invention this stream is optionally processed further in a second additional treatment system 10 where the hydrocarbons are separated as stream 19 and returned to the sweetened gas stream 40 13 from the second supersonic separator 6 and if needed passed fed to the optional WO 2013/124339 PCT/EP2013/053420 7 first additional treatment unit 8. Alternatively if the stream 19 fulfils the specifications the stream is by passed the optional first additional treatment system and added as stream 59 directly to the fully sweetened gas stream 15. The stream 23 leaving the second additional treatment system comprises mainly CO 2 and can be 5 pressurised and re-injected through a re-injection well. Figure 2 also illustrates an alternative embodiment, if stream 17 contains a combination of hydrocarbons (C2 and upward) and CO 2 . The alternative consists of doing no further processing and boost the stream 14 to a topside unit as fuel gas for power generation. Figure 3 is a more detailed illustration of the first embodiment of the present 10 invention. Equal reference numbers are used for units equal to units discussed in connection with figure 2. Dependent on the conditions in the phase separator the pressure of the crude gas may require pressure control to get the proper inlet pressure to the gas treatment system. Pressure control is either increasing the pressure by compressor or reducing the pressure typically through a valve. In this 15 embodiment a heat exchanger H-I is included immediately upstream the first supersonic separator 4. The crude gas stream 3 is cooled by heat exchange with the separated liquid 9 being returned trough 9' upstream the phase separator 2 or through 9' combined with the liquid outlet 7 from the phase separator. The pipeline 9a is a heat exchanger by-pass for increased control of the temperature 20 within this part of the system. The condition (temperature, pressure) of the feed gas 3' to the first supersonic separator should be controlled to prevent super cooling and subsequent hydrate formation. The first supersonic separator 4 is fed with cooled gas 3'. The separator 4 uses 25 supersonic separation technology to reduce pressure and cool the gas such that water and higher hydrocarbons are condensed and separated as liquid. The pressure is partly regained in the discharge section of the unit. The separated liquid phase 31 is initially transported to a secondary separation tank 32 to remove any gas carried under. The separated gas is depending on the quality thereof return as stream 33 30 upstream the separator 4 or as stream 34 downstream the separator 4. Further the conditioned or dried gas 11' is cooled in the heat exchanger H-2 before entering the second supersonic separator 6 as stream 11 ". The sweetened gas 13' is providing the cooling and the pipeline 13a is a by-pass for temperature control. Conditioning of the gas upstream the second supersonic separation unit may involve 35 pressure control and temperature control H-2. The cooling is expected to be performed by heat exchanging the cold discharge gas 13', with the inlet stream 11' after dehydration in the first supersonic separator 4, all dependent on the conditions of the inlet gas 1 to the system. The dehydration step upstream the CO 2 removal unit is generally required to avoid hydrate formation inside the unit.
    WO 2013/124339 PCT/EP2013/053420 8 The cooled gas 11" is treated utilizing supersonic separation technology to reduce pressure and cool the gas such that CO 2 is condensed and separated as liquid from the gas. The pressure is partly regained in the discharge section of the unit. The initially obtained liquid stream 35 enters a secondary separation unit 36 wherein any 5 carry under gas is separated of and returned either as stream 37 upstream the separator 6 or as stream 39 downstream the separator 6 generating the sweetened gas stream 13' a combination of the main sweetened gas stream 13 and the return stream 39. The liquid reject stream 17 from the gas treatment system 6 may be processed 10 further in an optional additional processing step 10 to recover hydrocarbons condensed with the CO 2 . These hydrocarbons are mainly C2 (ethane) and upwards. Methane generally goes with the main gas stream 13. Benefits of utilizing supersonic technology compared with other technologies are generally the compactness of the units, no moving parts, no or limited utilities, 15 simple control and limited energy requirement. The technology may also give higher discharge pressure for stream 15 and/or 23 than conventional CO 2 removal technology. Thereby the power consumption in boosting steps 50 and/or 40 can be reduced. The CO 2 rich streams 21 and 23 from the first and second optional additional 20 treatment systems 8 and 10 should be re-injected in the reservoir or in a disposal well. This requires boosting by unit 40 by pumping or compression dependent on the state of the fluid, i.e. liquid or gas. The boosting unit 40 provides a pressurized
    CO
    2 rich stream. Any separated liquid 41 and 45 from the additional systems 10 and 8 can be 25 introduced to the main liquid stream 7 or further downstream 7'in potential processing units if treatment of the liquid stream is performed. The handling of the liquid stream 7' can be performed through well known methods. The main fully sweetened and conditioned gas stream 15 may be compressed by compressor 50 before leaving the gas treatment system as stream 51. 30 Figure 4 illustrates an embodiment comprising the same units as the system disclosed on figure 3 but where the quality of the hydrocarbon gas from the second additional treatment system 10 is according to the required specification and therefore this gas is returned through pipeline 59 downstream the first additional treatment system 8. 35 Figure 5 illustrated another embodiment of the present invention. Equal units are given the same reference numbers. The first conditioning part of the system is unchanged when comparing with figure 3. Beside that a pump P-I is installed to pump the liquid 9 downstream the phase separator. After the conditioning, WO 2013/124339 PCT/EP2013/053420 9 downstream the heat exchanger H-2 a third heat exchanger H-3 is installed to further cool the main gas stream 11" before it enters the second supersonic separator 6 as stream 11 a. The liquid stream 17 is utilised to provide cooling before the stream enters the second additional treatment system 10 as stream 17'. The 5 pipeline 17a is provided for controlling and provides the possibility to by-pass the heat exchanger H-3. Further illustrated on figure 5 is the possibility to utilize the hydrocarbon stream 19 from the second additional treatment system as fuel for power generation for this are other systems. For this purpose the pipeline 53 is provide for removing the hydrocarbons from the gas treatment system. 10 Additionally figure 5 illustrates that the first and the second additional treatment systems 8 and 10 might rely on the supply of supplement treatment solution. These would be supplied through pipes 63 and 61, respectively. Further the present invention provides hybrid solutions combining supersonic separation technology with membrane technology can reduce the required 15 membrane area, reduce utility requirements and also handle challenges with respect to selectivity of CO 2 versus methane. The selectivity of CO 2 versus methane can be improved by embodiments of the current invention. Also provided by the present invention are hybrid solutions combining supersonic separation technology with absorption cycle process units. The combination can 20 reduce the size of the absorption system, reduce utilities need, absorption fluid content and make-up stream. The optional first and second additional treatment systems 8 and 10 illustrated in the figures can accordingly be based either on membrane technology or on the utilization of an absorption solution or a combination thereof. 25 The systems 8 and 10 can be selected from the systems illustrated on figure 6 and 7 respectively. Figure 6 illustrates an absorption system based on a liquid CO 2 absorbent solution. The use of different amine based absorbents as well as other absorbents is well known in the art. The configuration of such a system is also well known and the present invention can generally apply any equivalent liquid 30 absorption system. The stream 17/17'/ 25 comprising CO 2 and hydrocarbons is obtained from the second supersonic separator 6. If the unit illustrated in figure 6 is the first additional treatment system 8 then the gas stream to be treated is stream 25 as indicated in figures 2 to 5. If the unit illustrated in figure 6 is the second additional treatment system 10 then the gas stream to be treated is stream 17 as 35 indicated in figures 2 to 4 or stream 17' as indicated in figure 5. Similarly the output streams from the treatment system refer to streams indicated in the previous figures. In the system in figure 6 the stream to be treated is optionally firstly compressed in the compressor C-2. The need for the compressor depends on the pressure loss through the earlier stages of the treatment. If the liquid stream 17 from WO 2013/124339 PCT/EP2013/053420 10 the second supersonic separator is fed to the system the fluid should preferably be converted to gas phase generally by heating before or when entering the treatment system. The gas stream to be treated enters a contactor 60 where it is brought in contact with a lean absorption solution 69'. CO 2 is absorbed in the solution which 5 leaves the system as rich solution 65. Any liquid hydrocarbons are separated of from the stream 65 in the separator 64 and leave the system as stream 41/45 to be processed together with the other hydrocarbon containing liquid streams. The rich absorption solution proceeds as stream 67 to desorption column where it is heated to released the CO 2 and regain lean absorption solution 69. CO 2 depleted gas leaves 10 through the top of the contactor 60 as stream 19/15/59. The gas stream is processed further as discussed in connection with the previous figures. The stream 71 leaving over the top from the desorber comprises CO 2 , and any absorption solution that is carried over is condensed in the condenser 68 and returned as stream 73. The obtained CO 2 stream 23/21 leaves the system to be processed further as discussed 15 above in relation to the other figures. A heater 66 or similar arrangements provides the heat for the desorption process. If needed fresh absorption solution is supplied to the lean solution 69 by the stream 61/63 comprising make-up solvent. Benefits gained from a hybrid solution where the supersonic unit 6 removes the bulk of CO 2 and the first additional treatment system 8 is an absorption cycle 20 according to figure 6 compared with a pure absorption cycle process system as described in figure 6 are: - Reduced volume of solvent required - Reduced size of contactor and regeneration columns - Reduced size of additional equipment such as pumps, heat exchangers, coolers 25 etc. - Reduced duty of reboiler in desorption/regeneration column - Reduced volume flow of solvent make-up stream These benefits should reduce the overall size and utility requirement for the system. For a subsea application of the system, this may be the benefit enabling CO 2 30 separation subsea. Alternative for the absorption cycle process the solvent regeneration column may be located on a topside installation. Figure 7 illustrates another alternative for the first or second additional treatment system. The gas stream to be treated 17/17'/25 is optionally compressed by compressor C-3 and optionally pre-treated in a pre-treatment unit 80 before being 35 fed as stream 81 to a first membrane unit 82. The pre-treatment could comprise the removal of any substances with a harmful effect on the membrane or the function thereof. Within the first membrane unit 82 primarily CO 2 passes the membrane and WO 2013/124339 PCT/EP2013/053420 11 the remaining gas 19/15 will comprise a limited amount of CO 2 . The use and configuration of membrane separators is well known in the art. The sweetened gas 19/15 is processed further as discussed in connection with the figures 2 to 5. Depending on the efficiency and selectivity of the membrane in the first membrane 5 unit 82 the CO 2 rich gas 89 may be compressed in compressor C-4 and either passed directly to the further processing as stream 23/21, or alternatively the gas 89 may be fed to a second membrane unit 84 to obtain a CO 2 rich stream 87 which leaves the system as stream 23/21 and a hydrocarbon gas stream 85 which is returned to the stream 81 upstream the first membrane unit 82. The stream 23/21 is handled as 10 discussed in relation to the figures 2 to 5. The shown membrane process shows optional compression and pre-treatment of the gas prior to the first membrane unit. Also optionally a compressor and potentially cooling can be applied on the CO 2 rich permeate 89. The CO 2 stream may be discharged directly or run through a secondary membrane unit to purify the CO 2 15 stream even more. Combinations of membrane units in parallel and/or series or cascade can be configured, all dependent on the requirements to achieve. Additional pre-treatment between membrane units and compression and cooling can be applied. In this case no liquid hydrocarbon stream is discharged and no solvent is needed, hence streams 41/45 in figures 3 to 5 and 61/63 in figure 5 are obsolete. 20 Benefits gained from a hybrid solution where the supersonic separator 6 removes the bulk of CO 2 and a first additional treatment system 8 according to figure 7 compared with a pure membrane process system are: - Reduced volume flow through the membrane unit giving potentially reduced membrane area required and number of stages required 25 - Overall pressure drop may be reduced giving potential for less compression power required. The purpose of the optional second additional treatment system 10 of the CO 2 rich reject stream 17/17' is to recover more of the hydrocarbon gas and enrich the stream with respect to C0 2 , if required. 30 One solution can be to perform flashing of the liquid to flashing off light hydrocarbons (mainly methane) and without flashing off too much CO 2 . This will further reduce the pressure, but maintain the CO 2 in the liquid phase. This process is illustrated in figure 8. The CO 2 rich stream 17/17' from the second supersonic separator is fed to a flashing unit 90 at low temperature resulting in a hydrocarbon 35 gas stream 19 to be processed further as discussed in connection with the figures 2 to 5 and a liquid CO 2 stream 23 to be handled as discussed in connection with WO 2013/124339 PCT/EP2013/053420 12 figures 2 to 5. However the boosting unit 40 could be a pump as CO 2 is in a liquid state. Another embodiment is to employ an absorption cycle process as shown in figure 6 as system 10. 5 Compared with a pure absorption solvent process, if the supersonic unit 6 can give the gas specification of the main gas stream without the need for the first additional treatment system 8, the benefits of this hybrid solution combining the supersonic separation 6 with the absorption solvent process as system 10 may be: - Reduced volume of solvent required 10 - Reduced size of contactor and regeneration columns - Reduced size of additional equipment such as pumps, heat exchangers, coolers etc. - Reduced duty of reboiler in regeneration column - Reduced volume flow of solvent make-up stream 15 These benefits should reduce the overall size and utility requirement for the system. For a subsea application of the system, this may be the benefit enabling CO 2 separation subsea. A third embodiment is to implement membrane separation process as shown in figure 7 as system 10. 20 Compared with a pure membrane process, if the supersonic unit 6 can give the gas specification of the main gas stream without the need for the first additional system 8, the benefits of this hybrid solution combining the supersonic separation 6 with the membrane process of figure 7 will be: - Highly reduced volume flow through the membrane unit (membranes not in 25 the main feed stream) giving highly reduced membrane area required - Reduced size and complexity of the system - Potential for better membrane design focusing on selectivity between C2 hydrocarbon and CO 2 since C1 is generally associated with the main gas flow 13. This can further reduce the size of the membrane unit. 30 - Reduce pressure drop through the membrane unit and potentially reduce the overall pressure drop, thereby reducing compression power required In another solution for purifying stream 17' in figure 5 could be to run the vaporized liquid through an additional supersonic separation unit. In this WO 2013/124339 PCT/EP2013/053420 13 embodiment the second additional treatment system 10 is another supersonic treatment unit. Overall system and component design will be dependent on the conditions and composition of the inlet stream 1 and the requirements to the discharge gas streams 5 43 and 51, and potentially the liquid stream 7'. The process may be implemented in a topside or subsea environment. The export gas leaving the system stream 51 will be low on CO 2 and also dehydrated to quite a low dew point, hence it should be fit for long distance transport. 10 Process simulations modelling the supersonic separation unit in Hysys indicate that thermodynamically CO 2 will be condensed as liquid within the unit and low concentrations can be achieved in the gas, however dependent on the gas composition and the process conditions. Further it is considered that the current invention can be applied on-shore, off-shore 15 topside and subsea.
    权利要求:
    Claims (27)
    [1] 1. Crude natural gas stream treatment system comprising a first supersonic separator and a second supersonic separator, wherein the first supersonic separator comprises a crude gas inlet, a dry gas outlet and a first liquid 5 outlet; wherein the second supersonic separator comprises a dry gas inlet, a treated gas outlet and a second liquid outlet, and wherein the dry gas outlet is in fluid communication with the dry gas inlet.
    [2] 2. System according to claim 1, characterized in that the system further comprises a first additional separation system with at least a treated gas inlet, 10 a sweet gas outlet, a CO 2 gas outlet, wherein the treated gas outlet is in fluid communication with the treated gas inlet.
    [3] 3. System according to claim 2, characterized in that the first additional separation system is an absorption solution cycle system.
    [4] 4. System according to claim 2, characterized in that the first additional 15 separation system is a membrane separation system.
    [5] 5. System according to claim 2, 3 or 4, characterized in that it further comprises a first heat exchanger with a cooling medium inlet in fluid communication with the treated gas outlet and a cooling medium outlet in fluid communication with the treated gas inlet, and an inlet for a medium to be 20 cooled in fluid communication with the dry gas outlet and a cooled fluid outlet in fluid communication with the dry gas inlet.
    [6] 6. System according to anyone of the claims 1 to 5, characterized in that the system further comprises a second additional treatment system with at least a fluid inlet, a CO 2 outlet and a hydrocarbon outlet, wherein the second liquid 25 outlet is in fluid communication with the fluid inlet, and the hydrocarbon outlet is in fluid communication with the treated gas outlet or the sweet gas outlet.
    [7] 7. System according to claim 6, characterized in that the second additional separation system is an absorption solution cycle system. 30
    [8] 8. System according to claim 6, characterized in that the second additional separation system is a membrane separation system.
    [9] 9. System according to claim 6, characterized in that the second additional separation system is flash separation system.
    [10] 10. System according to claim 6, characterized in that the second additional 35 separation system is a third supersonic separator. WO 2013/124339 PCT/EP2013/053420 15
    [11] 11. System according to any one of the claims 6 to 10, characterized in that it further comprises a first heat exchanger with a cooling medium inlet in fluid communication with the second liquid outlet and a cooling medium outlet in fluid communication with the fluid inlet, and an inlet for a medium to be 5 cooled in fluid communication with the dry gas outlet and a cooled fluid outlet in fluid communication with the dry gas inlet.
    [12] 12. System according to anyone of the previous claims, characterized in that the first liquid outlet is in fluid communication with a well stream upstream an initial phase separator, where the initial phase separator comprises a crude 10 gas outlet in fluid communication with the crude gas inlet.
    [13] 13. System according to anyone of the previous claims, characterized in that the system is applicable for subsea installation.
    [14] 14. Crude natural gas treatment method, comprising passing crude natural gas through a first supersonic separator and a second supersonic separator, 15 wherein the first supersonic separator the crude natural gas is cooled and a first condensed liquid stream is separated off providing a dry gas stream, and wherein the second supersonic separator the dry gas is cooled and a second condensed liquid stream is separated off, thereby providing a treated gas stream. 20
    [15] 15. Method according to claim 14, characterized in that the second liquid stream comprises mainly C0 2 , and C2 to C4 hydrocarbons.
    [16] 16. Method according to claim 14 or 15, characterized in that method further comprises feeding the treated gas to a first additional treatment system.
    [17] 17. Method according to claim 16, characterized that the first additional 25 treatment system comprises bringing the treated gas in contact with a CO 2 absorption solution, absorbing CO 2 in the solution, thereby obtaining a sweetened gas stream, and regaining the solution by desorption of the absorbed CO 2 .
    [18] 18. Method according to claim 16, characterized that the first additional 30 treatment system comprises bringing the treated gas in contact with a CO 2 selective membrane, letting CO 2 pass trough the membrane to obtain a sweetened gas stream.
    [19] 19. Method according to claim 17 or 18, characterized in that the method further comprises heating the treated gas upstream the first additional treatment 35 system by heat exchange with the dry gas. WO 2013/124339 PCT/EP2013/053420 16
    [20] 20. Method according to any one of the claims 14 to 19, characterized in that method further comprises feeding the second liquid to a second additional treatment system.
    [21] 21. Method according to claim 20, characterized in that the method comprises 5 heating the second liquid through heat exchange with the dry gas upstream the second supersonic separator, thereby obtaining a second fluid.
    [22] 22. Method according to claim 21, characterized that the second additional treatment system comprises bringing the second fluid in contact with a CO 2 absorption solution, absorbing CO 2 in the solution, thereby obtaining a 10 hydrocarbon gas stream, and regaining the absorption solution by desorption of the absorbed CO 2 .
    [23] 23. Method according to claim 21, characterized that the second additional treatment system comprises bringing the second fluids in contact with a CO 2 selective membrane, letting CO 2 pass trough the membrane to obtain a 15 hydrocarbon gas stream.
    [24] 24. Method according to claim 20, characterized in that the second additional treatment system comprises flashing of hydrocarbons from the second liquid to obtain liquid CO 2 .
    [25] 25. Method according to claim 21, characterized in that the second additional 20 treatment system comprises passing second fluid trough a third supersonic separator, condensing and separating of liquid CO 2 and obtaining hydrocarbon gas.
    [26] 26. Method according to any one of the claims 14 to 25, characterized in that the method comprises feeding the first liquid to a well stream upstream a phase 25 separator, where the crude natural gas stream is obtained from said phase separator.
    [27] 27. Method according to any one of the claims 14 to 26, characterized in that the method is performed subsea.
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    同族专利:
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    EA201491546A1|2014-11-28|
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    法律状态:
    2017-06-01| FGA| Letters patent sealed or granted (standard patent)|
    2018-09-13| MK14| Patent ceased section 143(a) (annual fees not paid) or expired|
    优先权:
    申请号 | 申请日 | 专利标题
    NO20120194||2012-02-23||
    NO20120194A|NO20120194A1|2012-02-23|2012-02-23|Gas Treatment System|
    PCT/EP2013/053420|WO2013124339A1|2012-02-23|2013-02-21|Gas treatment system using supersonic separators|
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