Abstract:
A separator vessel ( 5 ) comprising; a separation chamber ( 10 ) arranged to separate liquid from an inflow production fluid ( 45 ); at least one gas scrubber ( 15 ) for removing entrained liquid from a separated gas inflow from said separation chamber ( 10 ); wherein said at least one gas scrubber ( 15 ) is positioned above and proximate to said separation chamber ( 10 ), said gas scrubber ( 15 ) and separation chamber ( 10 ) connectable through a vertically oriented at least one liquid outflow conduit ( 20 ) arranged to direct the removed entrained liquid from the gas scrubber ( 15 ) to the separation chamber ( 10 ) wherein the conduit ( 20 ) is arranged such that an outflow end ( 22 ) of said conduit ( 20 ) extends into the separation chamber ( 10 ) such that it is lower than a minimum threshold liquid depth ( 65 ) in said separation chamber ( 10 ).

Description:
FIELD OF INVENTION 
       [0001]    The invention relates to a system and method for the separation of gas and liquid, and particularly relates to applications for the oil and gas industry. In particular, the invention relates to a separator, and method of separation, in order to isolate gas, oil and water from a natural inflow prior to the refining process. 
       BACKGROUND 
       [0002]    A conventional means of separating gas, oil and water is using a three-phase separator. However, field experience indicates that many of these systems experience significant liquid carry-over which has resulted in problems and damage of downstream facilities like the gas compressions. To mitigate this, an additional polishing scrubber is generally provided downstream of the bulk gas/liquid or gas, oil and water separators. This adds to space, weight and instrumentation (due to additional level monitoring and control) which in turn results in increased cost. The reliability, availability and maintainability of the system are also reduced due to the additional equipment and associated instrumentation. 
         [0003]    For facilities where the inlet fluid is from a pipeline, slug flow in the pipeline results in significant sloshing, liquid entrainment and a drastic change in liquid level at the inlet separator. This turbulence at the inlet separator may result in a significant amount of liquid collecting around the gas outlet device at the separator. This, in turn, will result in both high liquid entrainment into the gas stream out of the separator and also potential blockage of the separator outlet device particularly if the liquid is waxy. 
         [0004]    The blockages occur as a result of cold spots at the gas outlet device; with the effect made worse by the normally small flow path associated with the internals. “Sloshing” of the liquid phase may also lead to liquid coming into contact with the gas outlet device. For separators on a Floating Production Storage and Unloading Unit (FPSO), this is more pronounced as the ship&#39;s motion leads to greater movement of the liquid phase. If the liquid entrained in the gas stream is waxy, there is no means of removing the wax that builds up at the device unless the separator is taken offline, and the outlet device disassembled. 
         [0005]    The need for high efficiency separation of the gas from the entrained liquids, for most applications, results in highly efficient gas outlet devices, or internals, being required at the separator. These internals may be mist mats, vane packs, cyclonic devices or other proprietary internals. However to accommodate the gas outlet device within the separator, the vapor space in the separator needs to be large enough to accommodate the device. This increases the size of the separator. 
         [0006]    In particular, waxy crude that forms gel or crystalline structure at lower temperatures normally leads to a number of operational problems especially the ability of the fluid to flow and clogging of the instruments and internals that is integral to the performance of the equipment. 
         [0007]    For facilities that handle waxy crude it is ubiquitous to inject Pour Point Depressant (PPD) to lower the pour point temperatures, and to maintain high production fluid temperatures in the equipments, pipes and instruments that handles the waxy crude. However it is unavoidable that some cold spots will develop within the system. These cold spots are located within the equipment or pipeline that experiences temperatures lower than the bulk fluid temperature. These cold spots are more prevalent in the gas phase where the specific heat of the gas is low. Low specific heat means that the gas gains or loses temperature faster. 
         [0008]    The separation chamber, which receives the production fluid, is typically a three phase separator that carries out course separation of the production fluid into its individual phases. The problem of wax is compounded within all such separation, as the gas phase internals are normally built into the inlet separator and consists of small flow paths and parts, and further, with the gas phase in direct contact with the oil phase. Also, it has been found that slugging, or surges, lead to more liquids carryover in the gas phase. 
         [0009]    For specific FPSO applications, the motion of the vessel may make the above problem worse. 
         [0010]    Furthermore, there is no means for early detection of the waxing problems, and no means to fix the problem online if the wax begins to form. 
         [0011]    And when wax begins to form, the problem is self propagating. Typically to mitigate liquid carry-over problems, a downstream gas scrubber is provided with liquid collected pumped back to the separator. This however increases the space and weight requirements and in addition increases the control, operational &amp; maintenance complexity of the system. 
         [0012]    A further problem involves slugging which is a challenging problem for many crude oil production receiving facilities particularly those receiving production from multi-phase subsea pipelines as they are susceptible to slugs. This is particularly the case for production facilities receiving crude and associated gas from remote wells via pipelines and risers. Slugs generated in the pipelines and risers not only require processing facilities to be increased in size to accommodate the slugs, but also results in production upsets associated with the high speed at which the slugs arrive and the transient pressure fluctuations due to the surge of gas following the arrival of the slug. Under these scenarios the production facilities like inlet heat exchangers, production separators and downstream gas compressors generally will not be able to cope with this transient slugging phenomenon resulting in production upsets and possibly shutdown. 
         [0013]    Slugging results in the compression of the gas phase behind a slug. The transportation of a slug requires a larger pressure behind the slug to keep the slug moving through the pipeline and riser. This pressure increase depends on the size of the liquid slug. After the slug arrives at the outlet of the pipeline or production platform, the compressed gas creates a large gas surge, which again may result in major upsets in topside facilities, like the downstream gas compression trains. 
         [0014]    The production from the remote wells, usually comprising large slug volumes is transported to the heat exchanger via pipelines or risers. Without any effective separation upstream, the slug flow conditions at the heater results in large heating duties of the exchanger as both the gas stream and the liquid streams are heated. The excessive heating duties results in poor performance of the heat exchanger, thus waxy crude and emulsions are still of existence in the outlet stream. Furthermore, the system experiences large pressure drop as the heating duty is high. 
         [0015]    On the other hand, the existence of waxy crude and emulsions will cause blockages at the inlet and outlets of the separator. Although the separation of oil, gas and water can be performed, the exiting gas stream will comprise significant liquid entrainment that will cause damage to the condensing system, resulting in system shutdown. Hence, the reliability of the separator system is very low. In addition, these turbulences and the ineffective heating of the inlet fluids leading to the presence of water emulsion, inherent with multiphase fluids under slugging conditions will also result improper oil water separation in the separator. This will require the downstream system to be upsized due to excessive water carry-over in oil stream and excessive oil carry-over in the water stream. 
         [0016]    Furthermore, the presence of sand in the production fluid often results in sand build-up in the downstream separator which in turn possibly requires frequent shutdowns to remove sand from the separator or requires sand removal devices to be installed at the separator which are expensive 
       SUMMARY OF INVENTION 
       [0017]    In a first aspect, a separator vessel comprising; a separation chamber arranged to separate liquid from an inflow production fluid; at least one gas scrubber for removing entrained liquid from a separated gas inflow from said separation chamber; wherein said at least one gas scrubber is positioned above and proximate to said separation chamber, said gas scrubber and separation chamber connectable through a vertically oriented at least one liquid outflow conduit arranged to direct the removed entrained liquid from the gas scrubber to the separation chamber wherein the conduit is arranged such that an outflow end of said conduit extends into the separation chamber such that it is lower than a minimum threshold liquid depth  65  in said separation chamber. 
         [0018]    With the separator having a gas scrubber in close proximity, the ability to more efficiently recycle liquid, the invention is able to reduce space and save on capital infrastructure costs, providing advantage over the prior art. 
         [0019]    In one embodiment, by actually mounting the scrubber to the separation chamber, further space savings may be achieved. 
         [0020]    In a further embodiment, the conduit may be arranged such that an outflow end of said conduit extends into the separation chamber. Further, the outflow end will extend into the separation chamber such that it is lower than a minimum threshold water depth in said separation chamber. 
         [0021]    In one embodiment, the separator vessel may include a slug handling device for managing and/or removing slugs from the inflow production fluid. The slug handling device may include a separation device receiving the inflow production fluid through an inlet pipe. The separation device may be inclined to promote gravity flow, so as to separate a gas stream and liquid stream through gravity. The slug handling device will include a stilling well for receiving the separated liquid 
         [0022]    The said stilling well may have a sand trap so as to allow solids within said separated liquid to settle through gravity. The stilling well may also include an outlet above the sand trap so as to discharge said separated liquid to the separation chamber. 
         [0023]    The slug handling device may be a separator arranged to create a stratified flow regime and with total hold-up volume sized to accommodate the anticipated slug volume for said inflow production fluid so as to yield the separation of the gas stream and liquid stream. Alternatively, the slug handling device may include a pipe having an expanded diameter, such as having a diameter larger than the diameter of the inlet pipe. This expanded diameter may be sized so as to achieve the stratified flow regime and with total hold-up volume sized to accommodate the anticipated slug volume. 
         [0024]    In a further embodiment, the slug handling device may also include a gas bypass pipe for routing separated gas from the separation device to gas scrubber. 
         [0025]    The stilling well will have the outlet located above the sand trap, and further the pipe may be inclined upwards so as to prevent sand from exiting said stilling well. Further, the outlet may include a control valve for controlling the flow of liquid to the separator chamber. 
         [0026]    In one embodiment, the stilling well may include a sand removal assembly within the sand trap, said sand trap assembly including at least cyclonic device for agitating sand into suspension, and a valve controlled outlet for discharging liquid having the sand in suspension. In effect, having the sand in suspension allows the sand to be moved by flowing the liquid out of the sand trap, and thus using the liquid as a sand removal medium. Further, the sand removal assembly may also have an intermediate sand trap having a further valve controlled outlet arranged such that the liquid is discharged to the intermediate sand trap, prior to final discharge. Further still, the intermediate sand trap includes a further cyclonic device for agitating liquid in the intermediate sand trap prior to final discharge. 
     
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         [0027]    It will be convenient to further describe the present invention with respect to the accompanying drawings that illustrate possible arrangements of the invention. Other arrangements of the invention are possible, and consequently the particularity of the accompanying drawings is not to be understood as superseding the generality of the preceding description of the invention. 
           [0028]      FIG. 1  is a schematic view of a separator vessel according to one embodiment of the present invention; 
           [0029]      FIG. 2  is an elevation view of a separator vessel according to a further embodiment of the present invention; 
           [0030]      FIG. 3  is an elevation view of a separator vessel according to a further embodiment of the present invention; 
           [0031]      FIG. 4  is a schematic view of a crude stabilization train according to a further embodiment of the present invention. 
           [0032]      FIGS. 5A and 5B  are schematic views of a slug handling system and separator vessel according to one embodiment of the present invention; 
           [0033]      FIG. 6  is a schematic view of a slug handling system and separator vessel according to a further embodiment of the present invention; 
           [0034]      FIG. 7  is a schematic view of a slug handling system and separator vessel according to one embodiment of the present invention; 
           [0035]      FIGS. 8A and 8B  are schematic views of a slug handling system and separator vessel according to one embodiment of the present invention, and; 
           [0036]      FIGS. 9A and 9B  are schematic views of a slug handling system and separator vessel according to a further embodiment of the present invention. 
       
    
    
     DETAILED DESCRIPTION 
       [0037]    The invention provides a separator developed for the oil and gas industry where a two phase (gas and liquid) or 3 phase (gas, oil and water) separator which, in various embodiments, may have the advantages of providing high liquid droplet removal efficiency, may be compact with minimal space and weight and may require less controls and instrumentations. The system may be suitable for both onshore and offshore applications where space is limited and may be suitable for waxy and fouling fluid services and for facilities where motion effects are high, e.g. FPSOs. 
         [0038]      FIG. 1  gives the schematic of the separator vessel  5  of this invention to enable bulk gas/liquid separation and efficient gas polishing. The separation system  5  comprises two sections, the bulk gas liquid separation section  10  and a gas polishing scrubber section  15  as an integrated unit  5 . 
         [0039]    The separator chamber  10  is similar to a three phase gas-liquid separator whereby production fluid  45  comprising a gas and liquid phase passes into the separation chamber  10  through an inlet device  75 . The separation chamber  10  includes separate chambers where the separated liquid forms a liquid pad in the base of the chamber which is divided by a barrier  70  into the water phase which is drained  50  for treatment and a crude oil phase which is drained  60  for processing. 
         [0040]    The difference between the present invention and the conventional system lies in the placement of a gas scrubber  15  mounted above the separation chamber  10  and connected through a connecting pipe  25  to flow gas from the gas phase in the separation chamber  10  through to the gas scrubber  15  whereby a further separation process occurs through gas polishing to remove remnant liquid from the gas which is drained through a vertically oriented liquid conduit, or downcomer pipe  20 , back into the separation chamber  10 . The gas then exits through an outlet device  80  to the gas outlet line  55  for further processing. 
         [0041]    The termination  22  of the downcomer pipe  20  is to be below the low liquid level  65  in the horizontal separator  10  to ensure that gas does not bypass the separator  10  via the downcomer pipe  20  under all operating conditions. To avoid accumulation of oil phase in the downcomer pipe, the pipe may be terminated above the high oil-water interface level of the horizontal separator  10 . The pressure drop of the gas from the horizontal separator section  10  to the vertical scrubber section  15 , including the scrubber inlet device  35  is to be less than the static liquid head in the downcomer pipe  20  from high liquid level in the horizontal separator to the bottom of the vertical scrubber. This will ensure that liquid from the liquid pad of the separator section does not rise up the downcomer pipe to the scrubber, due to siphon effect. 
         [0042]    Since the separator  10  and scrubber  15  share a common liquid pad within the separator, the scrubber need not have a liquid collection booth. This minimizes the size and height of the scrubber  15 . 
         [0043]    A differential pressure transmitter  40  between the scrubber section  15  and separator section  10  enables the system to monitor the level of liquid in the downcomer pipe and to trouble-shoot the system. 
         [0044]    The separator vessel  5  is arranged to have the horizontal vessel, or separation chamber  10 , piggy backed with a vertical gas scrubber  15 . The bulk gas/liquid separation will be in the horizontal part  10  of the vessel  5  while gas scrubbing/polishing is performed in the vertical part  15  of the vessel. Gas, with entrained liquid, will exit the horizontal separator section  10  via an outlet deflector plate  30 . In this embodiment, a speciality gas outlet device like a mist mat, vane pack, etc is not provided at the gas outlet section  30  of the horizontal separator section  10  for the following reasons:
       Removal of entrained liquids from the gas is performed at the vertical scrubber section  15  of the separation system  5 .   Providing the gas outlet polishing device here will expose it to contact with the bulk liquid phase in the horizontal section of the separation system. This is particularly the case when liquid slugs are present in the incoming production fluid with associated turbulences and liquid sloshing effects.   In the case when the liquid is waxy, there will be a risk of the liquid outlet device being blocked or flow restricted due to wax build-up at the device.   With the elimination of the gas outlet device, the diameter of the horizontal separator section may be reduced, this saving weight and space.   Pressure drop of the system may be minimized.       
 
         [0050]    An expanded connecting pipe  25 , sized to minimize pressure drop routes gas (with entrained liquid) to the vertical gas scrubber section. 
         [0051]    The vertical gas scrubber section  15  is sized for the process conditions and gas flow and liquid carry-over from the horizontal separator section  10 . The scrubber  15  is provided with typical internals designed to enhance gas liquid separation. An inlet distributor  35  is provided at the scrubber to reduce the inlet velocity and to give a good gas distribution in the vessel. A gas outlet demisting device  80  is also provided and may be a mist mat, vane pack, cyclonic or other proprietary internals depending on the specific application requirements. 
         [0052]    A heat exchanging device may also be incorporated into the gas scrubber. Such a heat exchanger (not shown) may be arranged to dissipate heat from the inflow of gas. Alternatively, a heat exchanger within the body of the gas scrubber may be used so as to dissipate heat from gas within the scrubber. Conventional heat exchangers may be used for this purpose. The scrubber section may thus also function to cool the gas stream (separated gas inflow) and for final liquid droplet removal from the gas stream. This may avoid the need to provide an additional cooler downstream of the scrubber section prior to routing to the downstream processing facilities. 
         [0053]    In the case when the production liquid is waxy or fouling, a wax or fouling matter removal system  26 , comprising a nozzle mounted to the inlet or connecting pipe  25 , may be provided to enable hot water flushing of the inlet device  35  (due to wax blockage) as required. Potential blockage or flow restriction at the inlet device  35  is monitored by the differential pressure transmitter  40 . High differential pressure may signify fouling at the inlet device  35  of the gas scrubber due to wax deposition, etc. In addition, the wax removal system  26  may also be provided at the gas outlet device liquid draining compartment to remove blockages/restrictions as required. Whilst hot water may be used for the removal of wax, in fact any one or a combination of water, steam, diesel or any other solvent may also be used. 
         [0054]    The advantages with combining the two sections  10 ,  15  may include:
       Both sections may share a common liquid control system thus minimizing control and operational complexity of the system.   Size of scrubber is independent of liquid carry over rate as the liquid handling request is maintained within the separator section.   For waxy fluids, both sections may share a common heating system to avoid wax formation in the liquid pad of either section.       
 
         [0058]    Various embodiments of the present invention comprise the following components: 
         [0059]      FIG. 2  shows an actual vessel  85  constructed in accordance with the present invention. Here a separation chamber  90  has mounted thereto a gas scrubber  95  with a downcomer pipe  100  extending into the separation chamber. The position of the exit  102  of the pipe  100  is positioned near the base of the separation chamber  90  so as to be below a minimum threshold level of the liquid pad within the separation chamber. The separation chamber  90  includes an inflow  120  for receiving a gas liquid supply with a connecting pipe  110  for directing the separated gas from the separation chamber  90  to the gas scrubber  95 . The gas first passes through a deflection plate  115  before entering the connecting pipe  110  and than passes through an inlet device  105  before entering the gas scrubber  95 . The gas is then scrubbed to remove the remaining liquid and routing the gas through an outlet device  150  and subsequently through an outlet  145 . The remaining liquid is transported back into the separator vessel  90  through a conduit  100 . The separation chamber  90  further includes outlet  125  and liquid outlets for water  130  and crude oil  135  from respective chambers separated by a barrier  140 . 
         [0060]    It would be appreciated that the scrubber  95  may be mounted directly to the separation chamber  90  as shown in  FIG. 2 . Alternatively, a framework supporting the gas scrubber  95  may support the gas scrubber in a position above the separation chamber but not actually mounted thereto. 
         [0061]    The separation vessel  85  functions in the following manner:
   1. Full well stream fluid is first routed through an inlet heater, the heater ensures that the fluid is above WAT and sufficient to break the emulsion.   2. The separator vessels comprise two distinct sections:—
       a. Horizontal section  90  that bulk separation occurs and water is separated from the crude.   b. Vertical section  95  that houses the gas separation device that performs final polishing of the gas stream.   
       3. The inlet device  105  for the gas stream is located on the vertical scrubber section  95  that is isolated from the bulk liquid section.   4. The gas outlet from the separation chamber comprises a deflector plate  115  that inhibits the carryover of the bulk fluid into the gas phase and minimizes pressure drop.   5. The gas will flow through a pipe section  110  sloped back into the separation chamber  90 .   6. The gas separation internals are located at the vertical section  95 .   7. There will be a downcomer pipe  100  that will allow for any liquid separated in the vertical section to re-enter the main vessel that is terminated below the liquid level in the horizontal separator.   8. The gas separation device can be installed with differential pressure instruments to monitor the condition of the internals.   9. A source for hot water can be connected to the internals that can allow for on-line cleaning of the gas internals.   10. As the main gas polishing occurs in the vertical scrubber section of the vessel, gas section on the horizontal vessel can be reduced.   11. Since there will be no isolation valves between the horizontal and vertical vessel there will be no additional Pressure Safety Valves (PSV) required.   
 
         [0075]    One alternative configuration to the above option is to have a horizontal gas separation section so that the separator vessel will have a lower overall height as shown in  FIG. 3 . 
         [0076]    Here the separation chamber  90  is configured in the same way that of the embodiment of  FIG. 2 . However, the position of the gas scrubber  160  is in a horizontal alignment. An inlet device  165  is still used as is an outlet device  170  and dehydrated gas outlet  180  and downcomer pipe  100  for draining liquid into the separation chamber  90 . 
         [0077]    A typical crude stabilization train comprises 2 to 3 stages of separation and the flash gas from the 3-phase separators are re-compressed. Conventionally, this is achieved through multi stages of 3-phase separator operating at progressively lower pressure to meet the vapor pressure specification of the product crude where the outlet gas stream passes through gas scrubbers just upstream of the compressor suction for final polishing and to provide surge volume. 
         [0078]      FIG. 4  shows a crude stabilization train  185  according to the present invention. In such a system, the outlet gas from the integrated scrubber may be fed directly into the flash gas compressor  240 ,  285 . Thus not only do the 3 phase separators  210 ,  250 ,  290  reduce in size, the gas scrubbers  212 ,  265 ,  300  also reduce in size. Overall the system may provide a very compact stabilization train. 
         [0079]    The crude stabilization train  185  shown in  FIG. 4  comprises a system whereby a gas/liquid fluid  205  flows into a first separator stage  190  via a heater  207 . The result is the separated gas outlet  230  by a first gas scrubber  212  from the system  185 , and the flow of crude for dehydration and storage removal  285 . Water is also removed  215 ,  255  from the system  185 . The system itself comprises a three-stage process with each stage representing a separation vessel according to the present invention that are operated of progressively lower pressures to meet the vapor pressure specification of the final crude product,  285 . The first stage  190  receives the fluid  205  and sending  225  gas back to its gas scrubber  212  which removes the remnant liquid and directs the separated gas for processing  230  whilst directing the liquid back to the separation chamber  210  of the first stage  190  and water is drained through outlet  215 . 
         [0080]    The crude is sent  220  to the second stage  195  via an inter-stage heater  245  where it is received by a second separator chamber  250 . Gas sent  270  to the second gas scrubber  265  is scrubbed and delivered  280  to a flash gas compressor  240  which cools  235  the gas before delivering back to the first scrubber  212 . Water is drained  255  and the subsequent crude sent to the third stage  200  to be received by the third separation chamber  290  which removes  305  the final gas to the third gas scrubber  300  and delivers  285  the crude for processing. 
         [0081]    The gas removed from the third stage  200  is sent to a second flash gas compressor  285  which cools  275  the gas before delivering it to the second gas scrubber  265 . 
         [0082]    Thus, a three-stage process of continually separating and scrubbing the gas is substantially reduced in its footprint and with the proximity of the three-stages with the corresponding gas scrubbers substantial savings in capital infrastructure and instrumentation may also be achieved. 
         [0083]    Table 1 below shows the comparison of the size of the separators/scrubbers for the 2 options based on a typical production facility. 
         [0000]    
       
         
               
             
               
               
               
               
             
           
               
                 TABLE #1 
               
             
             
               
                   
               
               
                 Size Comparison 
               
             
          
           
               
                   
                 Vessel Size 
                 Conventional 
                 Embodiments 
               
               
                   
                   
               
               
                   
                 1 st  Stage Separator 
                 4.2 m × 12 m 
                 3.7 m × 9.7 m 
               
               
                   
                 2 nd  Stage Separator 
                 3.0 m × 10.1 m 
                 3.0 m × 9.3 m 
               
               
                   
                 3 rd  Stage Separator 
                 3.0 m × 9.5 m 
                 3.0 m × 8.9 m 
               
               
                   
                 1 st  Stage Scrubber 
                 2.7 m × 3.7 m 
                 1.9 m × 2.5 m 
               
               
                   
                 2 nd  Stage Scrubber 
                 1.2 m × 3.9 m 
                 1.0 m × 2.5 m 
               
               
                   
                 3 rd  Stage Scrubber 
                 1.4 m × 3.5 m 
                 1.0 m × 2.5 m 
               
               
                   
                   
               
             
          
         
       
     
         [0084]    It indicates that with the separators of the present invention, there is significant size and weight benefits to the system resulting in a compact crude stabilization train. As the scrubbers are located above the respective separators, further significant space and weight saving is realized. In addition, significant instrumentation, controls and shutdown functions are removed with the separator system resulting in reduced control, operational and maintenance complexity of the system. It also results in higher system availability. 
         [0085]    The concept of installing a scrubber provides a convenient and efficient way of increasing the gas handling capacity of the separator either for a “brownfield” modification or refurbishment of used equipment. Many operating facilities presently experience significant problems due to liquid carry-over from the bulk gas liquid separators to the gas compression trains resulting in mechanical damage to compressor impellers, etc. The proposed configuration of the separator vessel may provide a cost effective option of installing a gas scrubber on top of an existing separator to polish the gas stream exiting the separator without the need of significant space and adding weight to the existing facilities. In addition it may also avoid the need for additional controls and shutdowns. 
         [0086]      FIGS. 5A and 5B  show schematic views of the separator configuration  315  according to one embodiment of the present invention. This embodiment provides slug handling, bulk gas/liquid separation and efficient gas polishing. The separation system  315  comprises 3 sections, the slug handling section  320 , the bulk gas liquid separation section  325  and a gas polishing scrubber section  330  as an integrated unit. 
         [0087]    The Slug Handling section  320  comprises a separation pipe inclined to the horizontal, such as a horizontal expanded pipe  340  or other such separator/vessel, capable of gas and liquid separation of fluid (such as FWS fluid), that has a Gas Bypass Line  342  at its upper section and is in operational connection with a pipe known as a Stilling Well  350  at its lower section. The Slug Handling device  340  may be a conventional separator or a pipe piece with or without internals that is positioned horizontally with a slight tilt to enable the liquid to flow effortlessly into the Stilling Well  350 . Only coarse gas/liquid separation may be performed in the slug handling device  340  as final separation is undertaken at the gas polishing scrubber section  330  and the bulk gas/liquid separation section  325 . As such, the slug handling device may be sized as a minimum to ensure flow in this section is in the stratified flow regime and to accommodate the anticipated slug volume arriving. 
         [0088]    In operation, fluid such as FWS fluid is first routed to the slug handling device  340  for gas and liquid separation after which the liquids, including liquid slugs, are diverted into the Stilling Well  350  and the gas is routed to the Gas Bypass Line  342 . The Gas Bypass Line  342  routes the gas stream to the Gas Scrubber  405  ensuring that the pressure in the Slug Handling device  320  is almost equal to that at the Gas Scrubber  405  and Separator  380 . This configuration ensures that the discharge of the liquid from the Stilling Well  350  to the Separator  380  via the heat exchanger  365  and/or restriction orifice (not shown in diagram) is only dependent on the differential static head  386  of the liquid level in the Stilling Well  350  and at the Separator  380 . The height of the Stilling Well  350  is predetermined to provide sufficient liquid head  386 , between the normal liquid level  346  and the liquid level  375  in the separation chamber  380 , to overcome pressure drop of the liquid travelling from the stilling well  350  to the separation chamber  380 . Under normal steady state design flow conditions, the system hydraulics is configured to maintain liquid level  346  near to base of the slug handling device  340  and within the stilling well  350 . 
         [0089]    The horizontal position of the slug handling device  340 , its geometry (long and thin) and its overall volume ensures that the arrival of liquid slugs does not increase liquid head  345  significantly while the slugs are accommodated in the slug handling device, thus minimizing the incremental liquid head  345 . As the liquid flow is dependent on the available liquid head, the position and geometry ensure a steady flow through the heater  365  into the separator even with the arrival of large liquid slugs. Consequently, this ensures good temperature control and performance of the heater and minimizes turbulence in the downstream separator, enabling good  3  phase separation. In addition the system also ensures that pressure surges following slug arrival does not cause surges in liquid flow from the stilling well to the separator chamber as pressure in the slug handling system  320  and the gas scrubber  330  are equalized. 
         [0090]    This separator configuration  315  thus effectively manages slugs and associated pressure surges using a pressure balanced system with effective use of liquid hydraulic head, as detailed above, to ensure stable flow even under slugging conditions. This is achieved without additional instrumentation and controls thus providing for a highly reliable system with overall liquid level controls maintained at the bulk  3  phase separator  325 . 
         [0091]    Since sand is occasionally present in the incoming fluid, a sand trap  355  is installed at the bottom of the Stilling Well  340  where additional valves  360  will be added to periodically remove the sand. Separation of sand in liquid medium can occur via two main mechanisms:
       (i) Change in momentum   (ii) Gravity Settling       
 
         [0094]    As shown in  FIGS. 5A and 5B , the Stilling Well  350  according to this embodiment, both mechanisms are employed, where the large diameter and its upward orientation of the outlet pipe from the stilling well allows the solid particles  317  to settle and with the abrupt change in direction of flow  316  create a momentum shift that would further aide separation. 
         [0095]    Phases with different densities will have different momentum. If a two phase stream changes direction sharply, greater momentum will not allow the particles of the heavier phase to turn as rapidly as the lighter fluid, so separation occurs. 
         [0096]    The diameter of the stilling well is sized to aid both gravity settling of sand and to provide adequate surge volume for liquid hold-up to ensure that instantaneous flow fluctuations are dampened. 
         [0097]    The configuration of the Slug Handling Device  340  may simplify the controls associated with conventional slug catchers as it eliminates the need for liquid level and pressure control valve and shutdown valves, thus improves the reliability of the system. This also reduces the size of the slug handling device  340  compared to a conventional slug catcher as the slug handling device  340  needs to only cater for the maximum anticipated slug volume with liquid hold-up for final degassing being accommodated in the downstream 3 phase separator  325 . 
         [0098]    An inlet Heater  365  may be required upstream of the 3-phase separator  325  to provide heat to break the emulsion, thus enabling improved separation of oil and water. In a system according to the present invention, the flow rate may be limited by the available static head to overcome the pressure drop across the Inlet Heater and associated piping and fittings. This arrangement has the benefit of heating only the liquid stream and avoids heating of the gas stream which is bypassed via the Gas Bypass Line  342  of the Slug Handling Device  340 . The system effectively utilizes the static head  386  available in the Stilling Well  350  to control flow through the Inlet Heater  365  and thus eliminates permanent pressure drop. This will result in reduced downstream compression power requirements. In addition, the configuration allows for a steady flow to the heater even under fluctuating incoming flow and pressure conditions typically associated to heavily slugging incoming fluid flow conditions. 
         [0099]    The liquid is then conveyed to the Separator  380  in which the horizontal vessel is piggy backed with a vertical scrubber  405  according to a further embodiment of the present invention. The bulk gas/liquid separation will be in the horizontal part  380  of the vessel while gas scrubbing/polishing is performed in the vertical part  405  of the vessel. Gas, with entrained liquid, will exit the horizontal separator section via an outlet deflector plate. A specialty gas outlet device such as a mist mat, vane pack, etc is not provided at the gas outlet section of the horizontal separator section as for the reasons stated previously. 
         [0100]    An expanded pipe, sized to minimize pressure drop routes gas (with entrained liquid) to the vertical gas scrubber section. The Gas Bypass Line  342  from the Slug Handling System  320  will connect with the expanded pipe from the separator before being passed through the gas scrubber. 
         [0101]    The vertical gas scrubber section  330  is sized for the process conditions and gas flow and liquid carry-over from the horizontal separator section and the slug handling device. The scrubber  405  may be provided with typical internals designed to enhance gas liquid separation. An inlet distributor  415  is provided at the scrubber to reduce the inlet velocity and to give a good gas distribution in the vessel. A gas outlet demisting device  410  is also provided and may be a mist mat, vane pack, cyclonic or other proprietary internals depending on the specific application requirements. 
         [0102]    Liquid separated at the vertical gas scrubbing section  405  is routed via a downcomer pipe  385  to the liquid pad of the horizon separator. The termination of the downcomer pipe  385  is to be below the low liquid level  390  in the horizontal separator  380  to ensure that gas does not bypass the separator via the downcomer pipe  385  under operating conditions. To avoid accumulation of oil phase in the downcomer pipe, the pipe is terminated above the high oil water interface level of the horizontal separator,  325 . The pressure drop of the gas from the horizontal separator section  380  to the vertical scrubber section  405 , including the scrubber inlet device  415  is to be less than the static liquid head in the downcomer pipe  385  from high liquid level in the horizontal separator  380  to the bottom of the vertical scrubber  405 . This will ensure that liquid from the liquid pad of the separator section does not rise up the downcomer pipe  385  to the scrubber  380 , due to siphon effect. 
         [0103]    A differential pressure transmitter may be provided to monitor the performance of the system. In the case when the production liquid cause fouling and/or is waxy, a nozzle may be provided at the inlet pipe to the vertical scrubber  405  to enable hot water flushing of the inlet device (due to wax blockages and/or fouling) as required. Potential blockage or flow restriction at the inlet device is monitored by the differential pressure transmitter. In addition, hot water or solvent flushing facility may also be provided at the gas outlet device liquid draining compartment to remove blockages/restrictions as required. 
         [0104]    The benefits of system according to the present invention may include over the conventional system may include:
       1. A slug handling device that is capable of handling large slug volume and sand.   2. A heater to break the emulsion before the liquid enters the separator. The configuration of the system enables only liquid phase to be heated (thus minimizing heating duty) with flow through heater maintained steady thus ensuring accurate temperature control of the liquid phase.   3. A separate section i.e. the gas scrubber section is located above the horizontal bulk gas/liquid separator and will house the gas polishing internals. This will avoid potential contact of the gas outlet device with the bulk liquid due to turbulences, sloshing, etc.   4. The gas polishing section (or the gas secondary separation section) is provided with a downcomer pipe that terminates below the low liquid level of the main horizontal bulk gas/liquid separation section. This avoids the need to provide a separate liquid hold-up section for the vertical gas scrubber and avoids the need for dedicated level control and associated safeguarding instrumentation for the gas scrubber.   5. The gas polishing section is provided with an inlet distribution device to reduce the inlet momentum of the fluid and to enhance separation of the gas from liquid.   6. Online hot water flushing for cleaning   7. Smaller slug catcher as liquid hold-up and degassing is undertaken in the downstream 3 phase separator.   8. Smaller 3 phase separator as it need not make space for the gas outlet internals and gas handling capacity is reduced with gas bypassed at the slug handling device.   9. Smaller Scrubber as it need not have to cater for any liquid hold-up and surge volume       
 
         [0114]    The liquid level of the fluid in the stilling well  350  is dependent on the pressure drop of the liquid through the heat exchanger. Hence, the heat exchanger is sized for minimal pressure drop to minimize the height of the slug handling device,  340  relative to the bulk separator,  325 . Note that the line between the stilling well  350  and the bulk separator,  325  may include any other flow restricting device, like a restriction orifice, if a heat exchanger is not required for the service. 
         [0115]    The liquid level in the stilling well increases, as a result the liquid flow to the Heater and Separator will increase. To provide additional protection against high liquid level in the Separator, a further embodiment as shown in  FIG. 6  may be adopted. In this system  420 , a control valve  430  is installed upstream to the separator  380 . During normal operation, the control valve  430  may be left open to maintain the liquid level and minimize the pressure drop of the system. When large liquid surge is expected (e.g. during a pigging operation), the liquid surge entering the separator is attenuated on high liquid level at the Separator  380  by adjusting the control valve  430 . 
         [0116]    In some cases, a restriction orifice may be used instead of the valve to restrict the large surge from entering the separator to ensure that overall pressure drop under normal maximum flow conditions maintains liquid level in the stilling well near the top of the stilling well. This ensures that when slug arrives, the slug volume is accommodated within the slug handling device, thus minimizing static head rise  345  on slug arrival. This ensures steady flow of liquid to the bulk separator via the heater even under slugging conditions. 
         [0117]    Another variation is to provide a control valve  427  with minimum pressure drop when in open position at the Gas Bypass Line  342 . This embodiment is illustrated in  FIG. 7 . For this system  422 , the control valve  427  is normally kept in a wide open position. As the pressure drop across the Heater  365  increases, such as due to fouling, the liquid level in the Stilling Well  350  increases also. The liquid level in the Stilling Well  350  is measured using a differential pressure transmitter  500  between the Stilling Well base and Slug Handling Device  340 . On high liquid level detection at the Stilling Well  350 , the control valve  427  at the Gas Bypass Line  342  will throttle close to provide the pressure drive necessary to evacuate the liquid from the Slug Handling Device  320  to the Separator  325 . In addition, if the liquid level in the Separator  325  reaches high level, an override Separator high level control signal may be provided to throttle open the control valve to prevent high level in the Separator. Although the liquid that flows through the gas bypass line  342  eventually ends up in the 3-phase separator  325 , this condition is undesirable as the liquid does not pass through the heater,  365  to break the emulsions. 
         [0118]    There are two methods considered in this system for sand separation; gravity settling &amp; change in momentum of the sand and cyclonic sand removal device.  FIGS. 8A &amp; 8B  shows a cyclonic sand removal device  435  adapted for use with a system  430  according to the present invention. The pipe  457  from the stilling well  350  to the inlet heater  365  is inclined at an angle to minimize the presence of sand in the production fluid to the separator. This cyclonic sand removal device  435  functions continuously where sand is removed from the Stilling Well  350  using a conventional or proprietary cyclonic device. 
         [0119]    With the introduction of a liquid jetting stream  451 , the cyclonic device  442  generates a vortex which fluidizes solids within their surrounding area so as to form a suspension of sand/solids. When fluidized, or suspended, the solids are drawn to the cyclonic device discharge pipe allowing for controlled hydro-transportation out of the stilling well. The solids are transported to the de-sander vessel  444  where the solids are separated from the discharge sand slurry stream. The de-sanding operation may be semi-automated with operators activating an automatic sequence or continuously operated depending on the sand content of the production fluid. The sand may be removed through valve controlled outlet  445  while the separator remains online with no interruption to production. To assist in the removal of sand from the slurry in the de-sander vessel  444 , a further cyclonic sand removal device  440  may be employed to separate the sand from the sand/liquid slurry. 
         [0120]    In a further embodiment, a system  460  may include a bulk water separator  465 .  FIGS. 9A and 9B  show a configuration of the system  460  for the removal of water from the system before the 3-phase separation. In this embodiment, the stilling well  350  may include an enlarged base, such as with an increasing diameter towards the base  472  of the well in order to provide adequate capacity and, consequently, residence time for the water to settle at the bottom of the Stilling Well. An outlet control valve  475  is connected at the water outlet line  474  from the Stilling Well  350  to drain the water based on the interface level control  470  should a pre-determined oil/water interface level be reached. To prevent sand entrainment, the water outlet nozzle is elevated from the base of the stilling well. The bulk water separation reduces the heat duty of the inlet heater, thus minimizes the size of the heater.