Abstract:
A method for removal of a compound from a crude hydrocarbon gas stream to be obtained from a sub-sea well is disclosed. The method comprises bringing the crude hydrocarbon gas stream in contact with a treatment solution comprising an absorbent at least partly selective to the compound to be removed, thereby obtaining a rich treatment solution and a compound depleted gas stream, regenerating the treatment solution comprising the absorbent by desorbing the compound from the rich treatment solution, thereby obtaining a compound stream. The crude hydrocarbon gas stream is brought in contact with the treatment solution comprising the absorbent subsea, the compound depleted gas stream is obtained subsea, where as the regenerating of the rich treatment solution and obtaining the compound stream is performed topside Further a system for transporting a treatment fluid from a subsea treatment unit to a topside regeneration involving adding pressurized hot natural gas to the treatment fluid subsea as a lift gas and separating the natural gas from the treatment fluid topside before the treatment fluid enters the treatment unit is described.

Description:
The present invention relates to an offshore processing method and system, especially an offshore processing method where a treatment solution is employed for separation of a component from a main fluid stream, Further, the present invention relates to a method and a system where a fluid stream is transported from a subsea arranged installation to a topside installation without the use of a pump. 
     BACKGROUND OF THE INVENTION 
     Crude process fluid extracted from a well is initially separated into a crude natural gas stream and one or more liquid streams. The crude natural gas stream will usually contain acid compounds such as carbon dioxide and hydrogen sulphide as well as being saturated with water. The acid compounds can together with condensed water form liquid acid during handling and transport which may result in corrosion unless all equipment is made of high quality and high cost steel. Further, the presence of water in the natural gas can during temperature and pressure changes result in the formation of solid hydrates that may result in blockage of the passages through the equipment. 
     The exploitation of subsea wells has gone through considerable developments since the start of the offshore era. The location of the wells has changed both with respect to sea depth as well as distance to shore. This has resulted in new systems for handling the well streams. One such system includes a subsea installation near the wellhead combined with a topside platform, which can be a floating processing platform. Transportation of the well products can take place either through subsea pipelines or via tanker transport. Due to the limited space on a floating platform, generally the amount of process equipment needs to be adjusted to the available. space. One offshore processing method includes letting a major part of the hydrocarbon gas handling take place sub-sea but handling some regeneration processes and side streams topside. 
     The well fluid from a subsea well will normally naturally have sufficient pressure to proceed from the subsea well head and up to a topside arranged installation. 
     However, the subsea processing steps will often result in loss of pressure, as the different separation and treatment processes cannot be performed at such high pressures. After treatment the produced stream as well as the treatment solutions employed subsea will no longer have sufficient pressure for transportation to the topside installation. To facilitate transport of the fluids pumps are installed subsea. Power to the pumps is provided from the top side installation. At high sea depths the power demand would be considerable, which requires a considerable power plant on the top side installation and increased dimensions for the power cable and the length thereof. 
     PRIOR ART 
     Accordingly, it is well known to pass the crude natural gas through different separation processes to remove add compounds, water and or other compounds to obtain a natural gas stream ready for export. 
     Conventionally, when natural gas is recovered from a subsea well the well stream is either transported to a topside facility as is or an initial phase separation takes place subsea before the gas and/or oil is transported to a topside facility for further treatment prior to export. 
     Known processes for removal of acid compounds/CO 2  and water include separate absorption processes where the crude gas is brought in contact with a selective absorbent solution. After contact with the absorbent solution a gas stream depleted from the compound absorbed in the absorbent solution is obtained. To remove more compounds or groups of compounds the crude gas stream may be passed through a series of contactors employing similar or different absorbent solutions. 
     The different absorbent solutions including the selective absorbents usually have a significant cost and for environmental reasons require special treatment. For these and other reasons the absorbent solutions are normally regenerated for reuse in the absorption process. The regeneration is normally performed by heating and/or depressurization of the rich absorption solution in a desorber, resulting in desorption of the absorbed compound from the solution. The solution is separated from the desorbed gas and cooled before being reused. The desorption and regeneration process is demanding both with respect to energy, mainly for heating, and with respect to structural space. 
     For subsea wells the treatment processes are presently being performed topside, which requires that all the gas be brought up to the surface and that all the process equipment be installed topside, including absorbers, desorbers, tanks for the treatment solutions, etc. Due to the fact that the topside facility is handling all the produced natural gas, significant security requirements must be fulfilled. The hazard risks are initially significant when inflammable gas is handled and the security requirements must be in place to lower the risk. This increases the size and the complexity of the topside facility. 
     The topside facility can be a floating platform or ship like construction or it can be a rig construction with one or more legs fixed to the ground subsea. 
     Disclosed solutions for subsea pumps comprise different techniques for handling the external pressure and the corrosive environment. For gas streams subsea compressors are provided to facilitate compact transport of the gas stream. Presently there exist compressors which work effectively under subsea conditions. 
     SUMMARY OF THE INVENTION 
     The objective of the present invention is to provide an alternative method and system for gas treatment which impose fewer requirements on the topside facility, without significantly increasing the complexity of the system. 
     The present invention provides a method for removal of a compound from a crude hydrocarbon gas stream obtained from a sub-sea well, wherein the method comprises bringing the crude hydrocarbon gas stream in contact with a treatment solution comprising an absorbent at least partly selective to the compound to be removed, thereby obtaining a rich treatment solution and a compound depleted gas stream, regenerating the treatment solution comprising the absorbent by desorbing the compound from the rich treatment solution, thereby obtaining a compound stream, wherein the crude hydrocarbon gas stream is brought in contact with the treatment solution comprising the absorbent subsea and the compound depleted gas stream is obtained subsea, whereas the regenerating of the rich treatment solution to obtain the compound stream is performed topside. 
     In another aspect the method comprises transporting the compound rich treatment solution from subsea to topside and transporting the treatment solution comprising the absorbent from topside to subsea. 
     In yet another aspect the method comprises heat exchanging the rich treatment solution with the treatment solution comprising the absorbent during transporting. 
     In a further aspect the method comprises inline mixing of the crude natural gas and the treatment solution comprising the absorbent. 
     In yet another aspect the method comprises bringing the crude natural gas and the treatment solution comprising the absorbent in contact in a counter current contactor column. 
     In a first aspect of the method according to the present invention the compound to be removed is CO 2  and optionally H 2 S. According to this first aspect the obtained compound stream will comprise mainly CO 2 , and this stream is further pressurized and reinjected subsea. According to this first aspect of the invention the treatment solution comprising the absorbent comprises a CO 2  absorbent. The absorbent can be freely selected among available CO 2  absorbents. In a further aspect of this first aspect of the invention the treatment solution is an aqueous amine solution. 
     In second aspect of the present invention the compound to be removed is H 2 O. According to this second aspect of the invention the treatment solution comprising the absorbent comprises a H 2 O absorbent. The absorbent can be freely selected among available H 2 O absorbents. In a further aspect of this second aspect of the present invention the treatment solution comprising the absorbent is a glycol solution. Further according to this second aspect of the invention the obtained compound stream mainly comprises H 2 O vapor, which can be released to atmosphere. 
     In a further aspect the method according to the present invention comprises firstly performing the method according to the first aspect and thereafter performing the method according to the second aspect on the CO 2  depleted gas obtained by performing the method according to the first aspect. 
     Further the present invention provides a crude natural gas treatment system for removal of a compound from a crude natural gas stream comprising an absorption unit with a natural gas inlet, a treatment solution inlet, a compound depleted gas outlet and a rich treatment solution outlet and comprising a desorption unit with a rich treatment solution inlet, a compound outlet and a depleted treatment solution outlet, where the rich treatment solution outlet is in fluid communication with the rich treatment solution inlet and the depleted treatment solution outlet is in fluid communication with the treatment solution inlet, wherein the absorption unit is arranged subsea and the desorption unit is arranged topside. 
     In one aspect of the system according to the present invention the system comprises a heat exchanger for heat exchanging the rich treatment solution with the depleted treatment solution. In one embodiment according to the aspect of the system the heat exchanger is a pipe-in-pipe riser. In an advantageous embodiment the pipe-in-pipe riser comprises an inner pipe in fluid communication with the depleted treatment solution outlet topside and the treatment solution inlet subsea, and an outer pipe in fluid communication with the rich treatment solution outlet subsea and the rich treatment solution inlet topside. 
     In another aspect of the system the absorption unit comprises an in-line mixing device and/or a contactor column. 
     In a further aspect the system further comprises a second absorption unit with a second natural gas inlet, a second treatment solution inlet, a second compound depleted gas outlet and a second rich treatment solution outlet; and a second desorption unit with a second rich treatment solution inlet, a second compound outlet and a second depleted treatment solution outlet, where the second natural gas net is in fluid communication with the compound depleted gas outlet, the second rich treatment solution outlet is in fluid communication with the second rich treatment solution inlet, and the second depleted treatment solution outlet is in fluid communication with the second treatment solution inlet, and where the second absorption unit is arranged subsea and the second desorption unit is arranged topside. 
     In one aspect of the system according to the further aspect of the system according to the present invention the first compound is CO 2 , the absorption unit is a CO 2  absorber, the second compound is H 2 O and the second absorber is a dehydrator. 
     According to the present invention a major part of the hydrocarbon gas handling takes place sub-sea, but some regeneration processes and side streams are handled top side. 
     As there are in this solution fluids that are transported between topside and subsea facilities, dependent on the water depth and the process pressure subsea, one may make use of the differences in operating pressures subsea and topside to reduce or possibly eliminate the need for additional pressure increasing/decreasing devices such as pumps/chokes/lift gas systems, etc. in the system. The hydraulic head and transportation in itself will assist in the pressure increase and decrease of the fluids that are transported between subsea and topside. 
     A further object of the present invention is thus to provide an alternative way of providing pressure to a treatment fluid or other liquid stream employed subsea, where the streams need to be transported to topside for regeneration or further processing. 
     Another object is to provide a process which at the same time as it provides pressure for transport assists during transport in the separation of a rich treatment fluid. 
     Additionally it is goal to provide a system which supplies fuel to a topside fuel gas system. 
     The present invention provides a method for transporting a treatment fluid from a subsea treatment unit to a topside regeneration unit, wherein the method comprises adding pressurized natural gas to the treatment fluid subsea as a lift gas and separating the natural gas from the treatment fluid topside before the treatment fluid enters the treatment unit. The added pressurized natural gas will normally be hot at the prevailing conditions. The term “hot” as used here refers to at a temperature above the temperature of the treatment fluid, as the pressurized gas is heated during the compression. 
     In one aspect of the method according to the present invention the topside separation of the natural gas is performed by flashing of the natural gas from the treatment fluid. 
     In another aspect of the method according to the present invention, the subsea treatment unit is a CO 2  absorber unit and the treatment fluid is CO 2  rich absorption solution which is regenerated topside to CO 2  lean absorption solution. 
     In a further aspect of the method according to the present invention the subsea treatment unit is a H 2 O removal unit and the treatment fluid is H 2 O rich absorption solution which is regenerated topside to H 2 O lean absorption solution. 
     In yet another aspect of the method according to the present invention the separated natural gas is fed to a topside power generating system. 
     In an additional aspect of the method according to the present invention the natural gas used as lift gas is obtained by pressurization of crude natural gas treated by at least one treatment unit. 
     Further, the present invention provides a treatment fluid transporting system comprising a subsea treatment Ina with a treatment fluid outlet, a subsea arranged compressor with a natural gas inlet and a pressurized natural gas outlet, and a riser with a subsea riser inlet and a topside riser outlet, where the riser inlet is in fluid communication with the treatment fluid outlet and with the pressurized natural gas outlet. 
     In one aspect of the system according to the present invention the system further comprises a topside flash separation unit with an inlet in fluid communication with the riser outlet, a gas outlet and a treatment fluid outlet. 
     In a further aspect the system comprises a topside power generating system with a fuel inlet in fluid communication with the gas outlet from the flash separator and a treatment fluid regeneration unit in fluid communication with the treatment fluid outlet from the flash separator. 
     In yet another aspect of the system according to the present invention the treatment unit is a CO 2  absorption unit or a H 2 O absorption unit and the treatment fluid is the respective rich absorption fluid. 
     The term “topside” as used here refers to a position in proximity of the sea level. For floating topside installations, part of the equipment may be installed above or below the sea level but within or on the floating vessel or platform. For platforms with one or more legs connected to the seabed the term “topside” should be interpreted to refer to any position on the platform above sea level. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The present invention will be discussed in further detail with reference to the enclosed figures where: 
         FIG. 1  schematically illustrates a first embodiment of the present invention. 
         FIG. 2  illustrates the process scheme of a second embodiment of the present invention. 
         FIG. 3  illustrates a cross sectional view in the longitudinal direction of an embodiment of the riser/pipeline. 
         FIG. 4  schematically illustrates an embodiment of the present invention with an alternative way of providing pressure to a treatment fluid or other liquid stream employed subsea where said stream needs to be transported to topside. 
         FIG. 5  schematically illustrates a further embodiment of the present invention with an alternative way of providing pressure to a treatment fluid or other liquid stream employed subsea where said stream needs to be transported to topside. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     The figures illustrate different embodiments of the present invention. The same reference numbers are used to refer to equal elements within the different embodiments. It should be understood that features of the different embodiments may be combined to provide additional embodiments of the present invention. 
       FIG. 1  illustrates how, according to the present invention, a crude gas stream  11  comprising a compound to be removed is fed to a contactor system  14 ,  16  arranged subsea. In the illustrated embodiment the contactor system is a two stage process with an Initial direct contactor (mixer device)  14  and a traditional contactor column  16 . However, the present invention is not limited to this embodiment; any contactor system applicable for subsea arrangement may be employed. In the direct contactor  14  the gas stream is brought in contact with a treatment solution stream fed through pipe  23 . The obtained gas treatment solution mixture proceeds as stream  17  into the contactor column  16 . Lean treatment solution is provided to the column from pipe  21 . In the illustrated embodiment the treatment solution for the direct contactor is obtained from the column  16  at a level above the gas inlet; however, the present invention is not limited to this solution, as lean treatment solution could also be fed to the direct contactor as well as the column. The treatment solution comprises one or more species that at least with some selectivity absorb the compound to be removed from the crude gas stream. A species and solvent/diluent applicable for forming an effective treatment solution can be selected by the user depending on the compound to be removed and the prevailing conditions within the system. During contact with the treatment solution the compound to be removed is absorbed in the solution. The crude gas accordingly at least partly depleted from the compound to be removed leaves the system over the top of the column trough pipeline  31 . The main crude gas stream accordingly stays subsea during the treatment process. The rich treatment solution leaves the contactor  16  through the bottom outlet pipeline  25 . in the illustrated embodiment a pump  18  is provided to force the rich treatment solution to proceed up through the riser or pipeline  27 . The is only an illustration of one possible way of securing transport of the rich treatment solution up through the pipeline  27 ; other methods of providing the needed pressure and flow can equally be employed. On a topside facility  90  a regeneration system  20  is installed. The system receives the rich solution from pipeline  27 , desorbs and separates the absorbed compound therefrom, and obtains a depleted treatment solution which is sent back to the subsea contactor system through pipeline/riser  21 . The desorbed compound leaves the regeneration unit  20  as stream  29 . 
     In one aspect of the present invention the compound to be removed is an acid gas, such as CO 2  and/or H 2 S and the treatment solution comprises an amine based CO 2  absorbent. In another embodiment the compound to be removed from the gas is water, and the treatment solution is water absorbent such as tri ethylene glycol or another glycol based water absorbing compound. 
       FIG. 2  illustrates a further embodiment of the present invention. Illustrated here is also the initial treatment of a well fluid  1 . Firstly the well fluid  1  enters a phase separator  2 , where the gas stream  3  is separated from the liquid. In the illustrated embodiment a water stream  19  is passed to a produced water treatment system  4 , and the oil stream  13  is past to an oil treatment system  6 . The gas  3  is initially cooled by cooler  8  to obtain cooled gas  5 . The cooling results in condensation of higher hydrocarbons which are separated in separator  10 . The liquid stream  7  is via pump  12  and pipe  9  mixed with the main oil stream from the separator  2 . The gas  11  leaving over the top of the separator  10  is subject to a system and treatment as discussed in connection with  FIG. 1 . The obtained treated gas  31  enters a second system according to the present invention comprising a direct contactor  34 , where it is brought in contact with a treatment solution stream  43 . The obtained mixture is fed to a contactor column  36 . The rich treatment solution leaves via the bottom as stream  45 , via pump  38  and is transported via pipeline  47  to a top side installation  90  and a regeneration unit  40 . Here the compound absorbed in the rich treatment solution is released resulting in a compound stream  49  and a lean treatment solution  41  being returned to the subsea contactor  36 . 
     The treated gas stream  51  leaving over the top of contactor column  36  can be compressed in compressor  52  and the temperature of the compressed gas  53  controlled by heat exchanger  54 , thereby providing a treated gas stream  55  adjusted for subsea pipeline transport. 
     In one embodiment of the present invention CO 2  is removed in the first contactor  16  and water is removed from the gas in the second contactor  36 , whereby the obtained gas is sweetened and dewpointed to allow for pipe line transport. The CO 2    29  released from the treatment solution  27  within the unit  20  is then in this embodiment transferred to a CO 2  injection system  60  where it is compressed or otherwise prepared for injection via line  61 . The gas stream  31  is a sweet gas stream. Water present in the gas is absorbed in the treatment solution  47 . The removed compound in stream  49  is water and this stream can be released to the atmosphere. The gas stream  51  is sweet and dry and as such is conditioned for transport. 
       FIG. 3  illustrates a pipeline configuration forming an aspect of the present invention, Here the pipelines  121  and  127  correspond to the pipe lines  21  and  27  in  FIG. 1 , but arranged as a pipe-in-pipe riser. In the illustrated embodiment the inner pipe  127  of the two concentric pipes transports the lean treatment solution, whereas the outer pipe  121  of the two concentric pipes transports the rich treatment solution. The topside regeneration of the treatment solution normally involves supplying heat to the solution to release the absorbed compound. The pipe-in-pipe arrangement allows for heat transfer from the warm lean treatment solution to the rich treatment solution and thereby provides a more energy efficient process as well as reduces the number of connections between the subsea installation and the topside facility. 
       FIG. 4  illustrates an embodiment of the present invention with an alternative way of providing pressure to a treatment fluid or other liquid stream employed subsea where said stream needs to be transported to topside. A subsea stream  11  is fed to a treatment column  36 , where the stream  11  is brought in contact with a treatment fluid  41 . In one embodiment the stream  11  may be a natural gas stream and the treatment fluid an absorbent for absorbing a compound to be removed from the natural gas stream. The bottom stream  45  leaving the column will be a rich treatment solution. The natural gas with a reduced content of the compound to be removed leaves over the top as stream  51 . The gas is fed to a subsea compressor  52  to obtain compressed, depleted natural gas  53 . A part  55  of the compressed, depleted natural gas proceeds to shore, storage or further processing. Another part  59  of the compressed gas is injected into the rich treatment solution  45 , thereby providing sufficient pressure for the rich treatment solution to be transported through riser  47  to a topside installation  90 . 
     The top side installation  90  comprises a treatment solution regeneration system  40 , wherein the treatment solution is regeneration through separation of the absorbed compound and removal of the natural gas introduced into the solution. The natural gas  93  is preferably supplied as fuel gas to an onboard power supply system  86  which might require recompression of the gas phase. The depleted treatment fluid is returned through pipeline  41  to the subsea system. Stream  49  is the removed compound or a part thereof. 
     To further explain the present invention the following example is provided. If the compound to be removed from the natural gas  11  is for instance water, the treatment fluid could be a glycol such as triethylene glycol. During transport of the rich glycol  45  including water together with the pressurized natural gas  59  through the riser  47 , it is expected that part of the water will be transferred back to the gas phase. This water will be separated off together with the natural gas forming fuel gas  93 . However, it is well known to combust fuel gas containing water, and this might even be beneficial for the control of the combustion temperature. When a significant amount of the compound to be removed, in this example water, is separated during transport and separated off through initial phase separation, the size of the further system to regenerate the treatment solution can be reduced. Other examples of treatment fluids and similar systems include absorbents of acidic compounds such as amine solutions for removing CO 2  and for H 2 S. 
       FIG. 5  illustrates a further embodiment of the present invention with an alternative way of providing pressure to a treatment fluid or other liquid stream employed subsea where said stream needs to be transported to topside. A well fluid  1  enters a phase separator  2 , where a gas stream  3  is separated from the liquid. In the illustrated embodiment a water stream  19  is passed to a produced water treatment system  4 , and the oil stream  13  is passed to an oil treatment system  6 . The gas  3  is initially cooled by cooler  8  to obtain cooled gas  5 . The cooling results in condensation of higher hydrocarbons which are separated in separator  10 . The liquid stream  7  is via pump  12  and pipe  9  mixed with the main oil stream from the separator  2 . The gas  11  leaving over the top of the separator  10  is subject to a gas treatment system. The crude gas stream  11  comprising a compound to be removed such as CO 2  and/or other acid gasses is fed to a contactor system  14 ,  16  arranged subsea. In the illustrated embodiment the contactor system is a two stage process with an initial direct contactor  14  and a traditional contactor column  16 . However, the present invention is not limited to this embodiment; any contactor system applicable for subsea arrangement may be employed. In the direct contactor  14  the gas stream is brought in contact with a treatment solution stream fed through pipe  23 . The obtained gas treatment solution mixture proceeds as stream  17  into the contactor column  16 . Lean treatment solution is provided to the column from pipe  21 . In the illustrated embodiment the treatment solution for the direct contactor  14  is obtained from the column  16  at a level above the gas inlet; however, the present invention is not limited to this solution, as lean treatment solution could also be fed to the direct contactor as well as the column. The treatment solution comprises one or more species that at least with some selectivity absorb the compound to be removed from the crude gas stream. A species and solvent/diluent applicable for forming an effective treatment solution can be selected by the user depending on the compound to be removed and the prevailing conditions within the system. During contact with the treatment solution the compound to be removed is absorbed in the solution. The crude gas accordingly at least partly depleted from the compound to be removed leaves over the top of the column through pipeline  31 . The main crude gas stream accordingly stays subsea during the treatment process. The rich treatment solution leaves the contactor  16  through the bottom outlet pipeline  25 . A pressurized natural gas stream  65  is added to the rich treatment solution to provide the necessary pressure to transport the rich treatment solution to the topside installation through riser  27 . 
     On a topside facility  90  a regeneration system  20  is installed. The system receives the rich solution from pipeline  27 , separates the added natural gas  91 , and desorbs and separates the absorbed compound therefrom and obtains a depleted treatment solution which is sent back to the subsea contactor system through pipeline/riser  21 . As discussed in connection with  FIG. 4 , a part of the absorbed compound may be released to the gas phase during transport through the riser  27 . This released gas will follow the added natural gas via pipeline  91  and be added as fuel gas to the fuel gas system  86 . The desorbed compound leaves the regeneration unit  20  as stream  29 . If the compound is CO 2  the stream  29  may be treated and compressed in unit  60  and from there transported via pipeline  61  to a subsea injection well (not shown). 
     The obtained treated gas  31  enters a second system for removal of a second compound, such as water. The system comprises a direct contactor  34 , where the gas is brought in contact with a treatment solution stream  43 . The obtained mixture is fed to a contactor column  36 . The rich treatment solution leaves via the bottom as stream  45  and is transported via pipeline  47  to a top side installation  90  and a regeneration unit  40 . Pressurized hot natural gas  59  is added to the rich treatment solution subsea to facilitate the transport up through the riser  47 . The topside system is as discussed in connection with  FIG. 4 . Topside, the added gas  93  and possibly some of the absorbed compound is obtained as fuel gas  93 . The rest of the compound absorbed in the rich treatment solution is released, resulting in a compound stream  49  and a lean treatment solution  41  being returned to the subsea contactor  36 . If the compound is water the stream  49  is steam that can be released to the atmosphere. 
     The treated gas stream  51  leaving over the top of contactor column  36  can be compressed in compressor  52  and the temperature of the compressed gas  53  controlled by heat exchanger  54 , thereby providing a treated gas stream  55  adjusted for subsea pipeline transport. 
     Further illustrated on  FIG. 5  is the handling of the oil stream  13 , which is fed to an initial oil treatment system  6  arranged subsea. Here the crude oil is dehydrated, for instance by use of electrostatic coalescers or other dehydration techniques. Separated water is passed as stream  15  to the produced water treatment system  4 . The dehydrated oil  81  is via pump  80  transferred to the topside installation  90  as stream  85  together with a part  57  of the treated and compressed gas  53 . A topside stabilization system  84  comprises one or more stabilization steps where gas is flashed off from the crude oil. The first step is preferably performed at a pressure equal to the pressure required by the fuel gas system  86  so that the fuel gas  89  is not required to be compressed before feeding it to the fuel gas system  86 . The fuel gas is a combination of the added gas  57  and the gas present in the crude oil prior to stabilization. Additional stabilization steps may be included within unit  84  to allow for removal of additional gas to secure a quality applicable for tanker transport. The amount of added gas  57  can be regulated based on the amount of fuel needed by the power generators and the fuel  91  and  93  being provided to the fuel gas system after having worked as a lift gas for the treatment solutions. 
     According to the present invention, as by way of example is illustrated in  FIGS. 4 and 5 , the amount of pumps required for transferring the treatment solutions from the subsea treatment units to the topside regeneration facilities has been limited and the pressurized natural gas added as lift gas serves as fuel for topside power generation.