BACKGROUND OF THE INVENTION 
       [0001]    1. Field of the Invention 
         [0002]    The present invention relates to a system and method for homogenizing production fluid from an oil well having gas slugging, for the purpose of improving the flow characteristics of the well. 
         [0003]    2. Description of the Related Art 
         [0004]    In long horizontal liquid wells with a gas cap, the gas may influx into the wellbore. As it travels the horizontal length, the gas tends to segregate and migrate upwardly from the liquid, collecting and forming high pressure gas bubbles generally referred to as gas slugs. As the well turns vertically at a heel portion and continues upwardly to the surface, the segregated gas will have a tendency to form large gas slugs in the liquid medium and possibly risk killing the well due to slugging flow, and upsetting the surface facilities and related systems. 
       Horizontal Wells 
       [0005]    In long horizontal wells, the fluid flow has a tendency to segregate, with lighter fluids and gas drifting toward the top of the horizontal borehole and heavier liquids settling toward the bottom. At the heel of the well, the gas and liquids may be significantly segregated such that the segregated gas may be in slug form and provide an imbalance in the fluid lift, thereby potentially killing the well from flowing naturally. Remediation of the well would then be required to restart the well. In addition, the gas slugs passing through surface equipment can upset the surface facilities and related systems, thereby making it difficult to efficiently process the produced liquid hydrocarbons from the well. 
         [0006]    Various arrangements for separating gas from production fluids in such wells downhole are known. For example, U.S. Pat. No. 5,431,228 relates to a downhole gas-liquid separator for wells, in which gas is separated from production liquids by way of a shaped baffle disposed in the well between the distal end of the production tubing string and the point of entry of gas and liquid into the wellbore. The gas and the liquid are then directed to the surface via separate flowpaths. 
         [0007]    U.S. Pat. No. 5,482,117 is directed to a gas-liquid separator for use in conjunction with downhole motor driven pumps, particularly electric motor driven submersible pumps. A baffle is disposed in a tubular housing for separating gas from liquid. 
         [0008]    Although such prior art systems represent attempts to separate gas from liquid downhole, the problems associated with gas slugging continues to hamper production in such gaseous slug-laden wells. 
         [0009]    The present invention relates to a method and system of homogenizing the production fluid from such gaseous slug-laden wells, particularly wherein the gas slugging is at least in part due to the presence of one or more horizontal, or near horizontal boreholes communicating with the primary vertical borehole. A system for homogenizing production fluid from such wells is also disclosed. 
       SUMMARY OF THE INVENTION 
       [0010]    In the description which follows, the expression “upstream” refers to the direction toward the downhole location of the well, and the expression “downstream” refers to the direction toward locations closer to surface. 
         [0011]    The present invention relates to a system and method for improving the flow characteristics in such gas slugging wells. In particular, the method of the present invention passively separates the slugged gas from the fluid mix downhole, and then redirects the gas portion to a holding location in the form of an annulus, where the separated gas is then reinjected into the liquid column in a controlled method at a downstream location for the purpose of improving the homogeneity and flow characteristics of the production fluid. The injection of gas bubbles provides added lift to the liquid production, while improving the flow characteristics and reducing the risk of a “killed well”. This procedure prevents the upset of the surface facilities, and increases the flow rate over that of a slug-flow regime. 
         [0012]    The system of the present invention consists first of a means to separate slug or segregate gas from the fluid flow downhole, then to collect the segregated gas, and then to provide a controlled means for injecting the gas back into the liquid stream, such that the injected gas is more uniformly and homogeneously distributed through the liquid, thereby improving the flow characteristics of the liquid/gas medium. 
         [0013]    One preferred embodiment of the invention consists of first providing a passive downhole gas/liquid separation device that is located in the vertical section of the well near the heel of the uppermost horizontal wellbore. Wellbore production fluid will flow into and up the casing, until the fluid reaches the gas/liquid separation device which is located at the bottom of the production string, and which defines an annulus with the casing. The gas/liquid separation device is so constructed and configured, that the liquid continues to flow upwardly through the production flow tube, and most of the gas accumulates within the annulus defined by the flow tube and the casing. 
         [0014]    Although in one preferred embodiment of the present invention, the gas/liquid separation device is positioned in a vertical section of the well near the heel of the uppermost horizontal wellbore, the present invention also contemplates positioning the gas/liquid separator device in a horizontal section of the well, without departing from the scope of the invention. 
         [0015]    As noted, according to one preferred embodiment of the present invention, the vertical section of the well is provided with a suitable well casing which communicates with the horizontal wellbore via a heel portion. An annular section, or annulus, is defined between a production tube and the well casing, with an annular sealing device positioned above the heel portion. The gas/liquid separation device can be located in a horizontal section of the well, wherein a similar annular section will be defined by the wellbore and the production tubing. 
         [0016]    In one preferred embodiment, a passive gas/liquid separation device is located in a selected section of the well casing at the end of the string to passively separate the segregated gas portions from the liquid portions prior to directing most of the separated gas portion into the associated annulus section where it is held and permitted to rise upwardly. 
         [0017]    When the passive gas/liquid separation device is located in the vertical wellbore, the gas rises upwardly in the annulus. Where the passive gas/liquid separation device is located in a horizontal wellbore, the gas in the annulus moves downstream toward the vertical wellbore and surface. 
         [0018]    The separated gas portion in the annulus section is then dispersed back into the production tubing, preferably in controlled metered amounts to thereby result in the introduction of fine gas bubbles in the production fluid where it flows upwardly. 
         [0019]    The gas/liquid separation device can be of any of several alternative configurations. One such preferred gas separation device can be in the form of a vertically oriented spiral shaped baffle disposed in a vertical section of the tubing. 
         [0020]    The separation device can be in the form of a vertical flow tube located within the casing and provided with a series of tortuous apertures communicating between the annulus and the tubing, the apertures configured to permit passage of fluid into the tubing, while simultaneously causing the gaseous medium to rise in the annulus where it is ultimately re-introduced in a controlled manner, by injection or otherwise, into the production fluid. 
         [0021]    At the bottom of the production string, the fluid (both liquid and gas) is at a pressure, P gas/liquid . As noted, one such gas/liquid separation device includes a suitable mechanism, i.e., a spiral shaped device, or a flow tube having a series of tortuous paths, which paths strip the gas slugs from the liquid. Any of the alternative passive gas/liquid separation devices described herein can be used to separate the gas from the liquid. The gas will rise in the wellbore annulus and it will be trapped under an annular sealing device, such as a sealing packer located between the gas/liquid separation device and the casing. The pressure of the gas in the annulus, P gas , will be very nearly the same pressure as P gas/liquid  in the gas/liquid separation device. In this environment, any liquid mixed with the separated gas in the annulus will be re-directed from the annulus to the production flow tube and then proceed to flow naturally to the surface in the resultant homogeneous gas/liquid mix in the production string. 
         [0022]    The pressure head of the liquid in the liquid/gas separation device decreases as it rises to the surface, due primarily to the change in hydrostatic head, according to Bernoulli&#39;s equation, as will be described in further detail hereinbelow. As noted, at a predetermined vertical distance upwardly from the central part of the gas/liquid separation device, P gas  is greater than P liquid , i.e., P gas &gt;P liquid . The gas in the annulus below the annular sealing device will therefore be at a higher pressure than the pressure of the liquid at the same depth. Consequently, the gas in the annulus will then be directed through a gas lift valve or equivalent controlled gas injection device, and injected into the liquid production flow stream in the form of finely dispersed gas bubbles. The injection device allows one-way flow of gas from the annulus to the tubing of the gas/liquid separation device, preferably in a controlled manner, or at a metered rate, with P gas &gt;P liquid . 
         [0023]    The invention also envisions that if too much gas is produced in the gas/liquid separation step of the inventive method, it could kill the well during re-injection. Accordingly, the excess gas can be vented to the surface using a separate vent valve placed in the uppermost annular sealing packer, or at least in a proximal relation thereto. 
         [0024]    It is also envisioned, that under certain conditions, an optional compressor can be accumulated in the annulus between the gas/liquid separation device and the annular sealing packer. The compressor can thereby provide additional pressure, if needed, to the separated gas positioned in the annulus, to assist re-entry of the gases into the production tubing. Moreover, if required, an electric submersible pump (“ESP”), can be positioned in the production flow tube below the point of re-injection of the fine gas bubbles, or in proximal relation thereto, to assist fluid production flow. 
         [0025]    The system and method of the present invention not only eliminates the gas slugs which often inhibit well production, but also re-introduces the gas into the flow upstream via an injection device, thereby reducing the hydrostatic head in the flow, while providing additional lift to the output of the well. 
         [0026]    It is within the scope of the present invention to incorporate any suitable passive method to separate the gas from the liquid downhole. 
       The Bernoulli Principle 
       [0027]    The present invention relies on an application of the Bernoulli Principle as described hereinbelow. 
         [0028]    Bernoulli&#39;s Principle is derived from the principle of conservation of energy and states that, in a steady-state flow, the sum of all forms of mechanical energy in a fluid along a streamline is the same at all points on that streamline. This requires that the sum of kinetic energy and potential energy remain constant. Thus, 
         [0000]    
       
         
           
             
               
                 
                   Z 
                   1 
                 
                 + 
                 
                   
                     P 
                     1 
                   
                   
                     ρ 
                     1 
                   
                 
                 + 
                 
                   
                     v 
                     1 
                   
                   
                     2 
                      
                     g 
                   
                 
               
               = 
               
                 
                   Z 
                   2 
                 
                 + 
                 
                   
                     P 
                     2 
                   
                   
                     ρ 
                     2 
                   
                 
                 + 
                 
                   
                     v 
                     2 
                   
                   
                     2 
                      
                     g 
                   
                 
                 + 
                 
                   H 
                   L 
                 
               
             
             ; 
           
         
       
     
         [0000]    where 
         [0000]    
       
         
           
             
               v 
               n 
             
             
               2 
                
               g 
             
           
         
       
     
         [0000]    goes to 0, where: 
         [0029]    Z 1  is potential static pressure head (ft) at upstream location 1 
         [0030]    Z 2  is potential static pressure head (ft) at downstream location 2 
         [0031]    P 1  is pressure (lbs/in 2 ) at upstream location 1 
         [0032]    P 2  is pressure (lbs/in 2 ) at downstream location 2 
         [0033]    ρ 1  is density (lbs/in 3 ) at upstream location 1 
         [0034]    ρ 2  is density (lbs/in 3 ) at downstream location 2 
         [0035]    v 1  is flow velocity (ft/sec.) at upstream location 1 
         [0036]    v 2  is flow velocity (ft/sec.) at downstream location 2 
         [0037]    g is gravity constant (32.2 ft/s 2 ) 
         [0038]    H L  is loss of static pressure head due to flow (ft) (i.e., pressure losses from location 1 to 2 due to tubing wall friction), resulting in: 
         [0000]        P   1−2   =Z   1−2   +H   L ×ρ 1−2  
 
         [0039]    In particular, it can be seen from the above equation, that the difference in pressure between locations 1 and 2 is equal to the change in elevation/height, plus friction loss, multiplied by the change in density. 
         [0040]    Alternatively, the equation may be written as follows: 
         [0000]        P   1−2   =Z   2−1   +H   L *ρ 1-2  
 
         [0041]    Thus the fluid pressure will be reduced due to a change in fluid elevation in the vertical section as well as head loss caused by friction during flow. The gas in the annulus will maintain a similar pressure at the gas separation location and under the annulus sealing packer. 
       Liquid Pressure and Height Using Water as an Example 
       [0042]    Using water as an example, water undergoes a pressure increase of approximately 0.433 psi per ft. For 100 feet of vertical distance in a tube open to the atmosphere, the hydrostatic pressure at the bottom of the tube would measure about 43.3 psi. Gas, on the other hand, can be considered to have the same pressure over the entire distance of 100 ft. Therefore, if the gas is removed at the bottom of a 100 foot tubing at 43.3 psi, it would theoretically have the same pressure of 43.3 psi at the top of the tubing. Accordingly, the contained gas at the top of the tubing would be at 43.3 psi, while the liquid at the top of the tubing would be at 0 psi. Therefore the gas would tend to flow from the high pressure zone of the annulus to the lower pressure liquid zone in the tubing. The velocity of the liquid does not change at the two locations. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0043]      FIG. 1  is an elevational cross-sectional view of a vertical borehole, partially cased, and communicating with a horizontal borehole which merges with the cased vertical borehole at the heel of a well, illustrating a first embodiment of the invention for breaking up gas slugs into a plurality of smaller gaseous bubbles, and for re-introducing the bubbles into the production flow where they provide homogeneity and lift assist to the flow stream; 
           [0044]      FIG. 1A  is a cross-sectional view, taken along lines  1 A- 1 A of  FIG. 1 ; 
           [0045]      FIG. 2  is a cross-sectional view of a lower portion of a vertical section of a cased borehole similar to  FIG. 1 , incorporating alternative embodiment of a passive gas/liquid separation device according to the invention, for eliminating gas slugging and for improving the fluid flow upstream, the passive gas/liquid separation device shown being in the form of a flow tube, plugged at the lowermost end, and provided with a plurality of tortuous paths for entry of liquid into the flow tube, while permitting the gas slugs to be stripped out and move up the annulus; 
           [0046]      FIG. 3  is a cross-sectional view, taken along lines  3 - 3  of  FIG. 2 ; 
           [0047]      FIG. 4  is an enlarged cross-sectional view of a lower portion of yet another embodiment of the invention similar to  FIGS. 2 and 3 , incorporating a flow tube closed at the lowermost distal end by an integral bottom wall, and including an internal baffle system which produces tortuous paths for separating the gas slugs and breaking them up into small bubbles; 
           [0048]      FIG. 5  is an elevational cross-sectional view of a wellbore similar to the previous FIGURES, showing an alternative embodiment of the invention, wherein the passive gas/liquid separation device of  FIG. 1  is located in the horizontal borehole; 
           [0049]      FIG. 6  is an elevational cross-sectional view of a wellbore similar to the previous FIGURES, showing an alternative embodiment of the invention, wherein the passive gas/liquid separation device of  FIG. 2  is located in the horizontal borehole; and 
           [0050]      FIG. 7  is a graph which illustrates the liquid and gas pressures in relation to the depth of the well, in feet, for the embodiments of the present invention. 
       
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     A First Embodiment 
       [0051]    Referring initially to  FIG. 1 , there is illustrated a system  10  constructed according to one preferred embodiment of the invention. According to this embodiment, the system  10  is installed in vertical wellbore  12  of a well, the wellbore  12  being lined with casing  14 . 
         [0052]    The system  10  includes a passive gas/liquid separation device  16  in the form of flow tube  18  which is located above the heel portion  20  of the well, which heel portion  20  connects the vertical wellbore  12  with a generally horizontal borehole  22 . 
         [0053]    The fluid flow  38  (i.e., liquid, gas slugs and water) from horizontal borehole  22  reaches the heel  20  as shown, and rises upwardly in the vertical casing where it meets the flow tube  18 . At this location, the fluid enters the vertical flow tube  18  and proceeds upwardly along the spiral path defined by spiral baffle  24 . 
         [0054]    The system of  FIG. 1  includes one preferred form of gas/liquid separation device  16  in the form of spiral baffle, or auger  24 , positioned in flow tube  18  and defining a spiral path for the gas/liquid mix rising from the horizontal borehole  22 . The spiral shaped path of baffle  24  tends to separate the gas slugs  26  from the liquid medium by centrifugal forces imposed on the liquid, which forces cause the liquid portion to migrate radially outwardly from the center of baffle  24 , as the mix rises and increases in velocity. The lighter gas portion will remain closer to the center and enter central gas tube  28  via apertures  30 , to be directed into the annulus  32  defined between flow tube  18  and casing  14 . The gas portion in the center of baffle  24  may include a relatively lesser portion of liquid in the mix. 
         [0055]    As noted, as the gas/liquid mix rises up the spiral path of the gas/liquid separation baffle  24 , the heavier liquid portion migrates outwardly along the spiral path, and the gaseous portion enters apertures  30  in the center of the spiral baffle  24  and is directed into annulus  32 . 
         [0056]    Annular packer  34  is provided with vent valve  36 , which is adapted to vent excess gas to the atmosphere in the event an excessive amount of gas is produced and accumulated in the annulus  32  to form a high pressure zone. 
         [0057]    In particular, as can be seen from the FIGURES, liquid will enter the annulus  32 ; however a reduced flow rate due to a large “settling area” will allow the liquid and gas to separate by density differences. The separated liquid will be directed to the tubing, the gas will remain in the annulus, captured under the packer until reinjected into the tubing. 
         [0058]    It will be appreciated that the combination of the continuous rotational path of the fluids while traveling upwardly along the spiral path, and the progressively increasing velocity of the fluids as they rise upwardly, will cause radially outward migration of the heavier liquids (i.e., oil and water) and retention of the most gaseous phase closer to the center as shown by arrow  23 . Simultaneously, by the action of the spiral path, the gaseous slugs  26  will be broken up into smaller bubbles, which enter central gas flow tube  28  via inlet aperture(s)  30 . 
         [0059]    Thereafter, as noted, the liquid phase of oil (sometimes combined with water) will proceed upwardly into production flow tube  18 , while the gaseous phase in the form of relatively smaller bubbles will migrate upwardly, or will be lifted by compressor  44  (if required) and then proceed to injection device  40 , which allows one-way flow of gas from annulus  32  into production flow tube  18 , preferably in a controlled manner, where the gases are mixed with the liquid phase in a dispersed and uniform manner. In the flow tube  18 , an optional electric submersible pump  42  can also be installed in flow tube  18  as shown in phantom lines in  FIG. 1 , to assist the production flow upward toward surface if required by the conditions prevailing in the well. 
         [0060]    Annular packer  34  will contain the mostly gaseous medium formed by the dispersed slugs, if and until the pressure exceeds the pre-set pressure of relief valve  36 . Should the pre-set pressure be exceeded, the relief valve  36  will permit the gaseous medium to escape into the annulus and rise to the surface as illustrated schematically by the arrow  35  shown in phantom lines. 
         [0061]    In  FIG. 1 , injection device  44  is positioned in the annulus  32  as shown, and arranged to communicate with the production flow tube  18  such that gas exiting central gas tube  28  can be directed into the annulus  32 , and then into the production flow tube  18  in a controlled manner and the form of relatively fine bubbles, at an elevated location immediately below packer  34 . Thereafter, the merged fine gas bubbles and the production liquid mix is allowed to flow to elevated locations above packer  34  and proceed upwardly to the wellhead at the earth&#39;s surface. 
         [0062]    As noted, depending upon the particular characteristics and conditions in the well, an optional compressor  44  can be positioned as shown in  FIG. 1 , in the annulus  32  to assist the upward movement of the predominantly gaseous medium exiting central gas tube  28  and entering annulus  32  via apertures  30 . Compressor  44  comprises an artificial lift system that electrically drives multiple centrifugal stage impellers to increase the pressure and thereby lift the predominantly gaseous medium from annulus  32 . The compressor  44  may be powered by electric power provided from the surface. Depending upon the circumstances and well completion conditions, the compressor can be in any of several forms. 
         [0063]    The steps of diffusing the gaseous slugs into predominantly fine gas particles, and then re-introducing them into the predominantly liquid phase of the production flow increases the flow rate of the produced fluid stream and maintains the continuous operational characteristics of the well. 
         [0064]    It is also noted that the assist provided by the optional compressor  44  promotes improved merging of the now dispersed gaseous medium with the predominantly liquid flow in the production flow tube  18 . 
         [0065]    As shown in  FIG. 1 , an electric submersible pump  42  can optionally be positioned in production flow tube  18  above compressor  44  to provide artificial lift to the predominantly liquid medium in flow tube  18 . 
         [0066]    In  FIG. 1 , the production flow tube  18  is open at the mouth  45  to receive fluids as depicted by arrows  46 . 
         [0067]    In  FIG. 1 , the fluid (both liquid and gas) at the mouth  45  of the flow tube  18  would generally be at a first pressure, designated as P gas/liquid . Once the flow of liquid and gas slugs enters the flow tube  18  and gas/liquid separation device  16  as shown in  FIG. 1 , and the separation of the gas from the liquid takes place by the gas passing through the path of spiral baffle or auger  24 , the gas will rise in the wellbore annulus  32  and it will be ultimately trapped therewithin under an annular sealing device, such as packer  34 , or the like. 
         [0068]    Since the pressure P gas  of the gas in the annulus  32 , prior to re-entry into the flow tube  18 , by injection device  40 , is greater than the liquid pressure P liquid  in the flow tube  18 , any relatively small amount of liquid in the annulus  32  will be redirected from the annulus  32  into the flow tube  18 , and then flow naturally within the flow tube  18  toward the surface in flow tube  18  along with the production flow. 
         [0069]    As the liquid rises in the flow tube  18 , the hydrostatic pressure will decrease primarily due to the change in height. As noted, the pressure of the liquid will be different at the various locations in the tubing string and an upper location will have a lower pressure than a deeper location as will be explained hereinbelow, using water as an example. 
         [0070]    Referring again to  FIG. 1 , at a predetermined vertical distance above the mouth  44  of flow tube  18 , P gas  will be greater than P liquid . At this location, the primarily gas flow in the annulus  32  below the packer  34  will be at a higher pressure than that of the medium in the flow tube  18 , which is comprised primarily of a liquid. The gas will then be directed via a controlled gas injection device  40  for injection into the liquid stream. As noted, the gas injection device  40  will control the rate of gas injection into the flow tube  18 , as shown schematically by arrows  46  in  FIG. 1 . 
         [0071]    The gas injection device  40  is a valve used in a gas lift system which controls the flow of lift gas into the production tubing conduit in a controlled manner. The gas injection device  40 , which can be in the form of an injection valve, is located in a gas lift mandrel  48 , which also provides communication with the gas supply in the tubing annulus  32 . Gas lift mandrel  48  is a device installed in the tubing string and is shown schematically in  FIG. 1 . Operation of the gas injection device  40  is determined by preset opening and closing pressures in the tubing of the annulus, depending upon the specific application. 
         [0072]    The gas lift injection device  40  or other suitable gas injection controlled metering device, or nozzle is preferably capable of providing specifically controlled metered gas flow into the liquid stream in the flow tube  18  in a manner to produce finely dispersed gas bubbles in the liquid stream. In particular, the gas injection device  40  allows one-way flow of gas from the high pressure zone of annulus  32  into flow tube  18 , as explained previously, due to the fact that P gas  is greater than P liquid  at such elevated location. Any relatively small amount of liquid which is mixed with the gas in the annulus  32  will naturally flow back into the flow tube  18  through gas injection device  40 . Injection device  40  preferably will be arranged to re-inject the gas into the tubing at the same rate that it is stripped out of the liquid/gas flow by the passive gas separation process of gas/liquid separation device  16 . 
         [0073]    A venting device such as vent valve  36 , is positioned preferably within the packer  34  to vent excess gas to the atmosphere in the event such an excessive amount of gas is produced and accumulated in the annulus  32  to form a high pressure zone. Therefore, if the gas is not reinjected at the same rate that it is stripped, the gas will fill the annulus  32  until it reaches the stripped pressure. The passive gas/liquid separation system will no longer strip out the gas; rather the gas will stay in solution with the liquid and will be injected into the tubing. 
       A Second Embodiment 
       [0074]    Referring now to  FIGS. 2-3 , there is illustrated an alternative embodiment  100  of the inventive system, which includes passive gas/liquid separation device  102  in the form of flow tube  116 . Wellbore  112  is lined with casing  114  in which flow tube  116  is positioned to form annulus  118  with casing  114 , as shown. In this embodiment, flow tube  116  is closed at its lowermost end by plug  120 . In principle, the operation of the embodiment of  FIGS. 2 and 3  differs from the previous embodiment, but the objectives and results are similar. The tortuous apertures  124  in flow tube  116  receive and direct the liquid  126  containing gaseous slugs  128  into the flow tube  116  as shown, while the major portion of the gaseous medium is permitted to move upwardly into annulus  118  via apertures  124 . The flow tube  116  includes a central separator baffle  130  for further assistance and guidance of the liquid medium, the central baffle  130  being surrounded by circular baffle  132  as shown in  FIGS. 2 and 3 . Major portions of the gaseous slugs  128  are broken up while entering the flow tube  116  via tortuous apertures  124 , which are so configured as shown, as to encourage the liquid component to enter the circular baffle  132 , as shown schematically by arrows  134 . The gaseous medium is “encouraged” to move upwardly and outwardly toward annulus  118  as depicted schematically by arrows  136 , and the predominantly liquid flow is depicted by arrow  137 . 
         [0075]      FIG. 3  is a cross-sectional view taken along lines  3 - 3  of  FIG. 2 , illustrating the escape of gaseous medium by arrows  136  which were previously in the form of gaseous slugs  128 , via tortuous apertures  124  and into annulus  118 . In particular, a controlled gas injection device  138  is positioned above compressor  140  and below packer  142 , which is provided with vent valve  144  as in the embodiment of  FIGS. 1 and 2 . 
         [0076]    In all other respects, the uppermost structure and operation of the embodiment of  FIGS. 2 and 3  are the same as the operation of the previous embodiments. 
       A Third Embodiment 
       [0077]    Referring now to  FIG. 4 , there is illustrated an enlarged cross-sectional view of a lowermost portion of yet another alternative embodiment  200  of the invention, in which the flow from a horizontal borehole of the well enters the tube  210 , which is closed at its lowermost end by integrally formed base plate  212 , the flow tube  210  including apertures  214  which create respective tortuous paths as depicted by arrows  216 , for separation of the gas from the liquid. This path causes the gas slugs to be broken up and to be stripped from the liquid while entering the annulus  218  formed between the flow tube  210  and the casing  220 . The gas is thus stripped from the liquid/gas mix and then permitted to accumulate in the annulus  218 , where it is reinjected into the flow tube  210  at the upper end (not shown in  FIG. 4 ) in the same manner as described in connection with the previous embodiments. 
         [0078]    In all other respects, the operation and the remaining structure and function of the embodiment of  FIG. 4 , are the same as with the previous embodiments. 
       A Fourth Embodiment 
       [0079]    Referring now to  FIG. 5 , there is shown yet another alternative embodiment  300  of the invention, in which the passive gas/liquid separation device  324  is positioned in the horizontal borehole of the well. The system of  FIG. 5  is similar in most respects to the gas/liquid separation device system of  FIGS. 1 and 2 , except that it is located in the horizontal borehole. 
         [0080]    The well completion system  300  is comprised of vertical borehole  310  provided with vertical casing  312  surrounding production flow tube  314  to form annulus  316 . 
         [0081]    Horizontal borehole  322  is depicted schematically as being joined with vertical borehole  310  at heel  320 . Located in horizontal borehole is a passive gas/liquid separation device  324 , which is structurally and functionally identical to the passive gas/liquid separation device shown in  FIGS. 1 and 2 , including a spiral shaped baffle or auger  326  positioned and adapted to receive gaseous slug-laden fluids from the well through the horizontal borehole  322 , as depicted by arrows  328  and slugs  330 . 
         [0082]    The slug-laden fluids depicted by arrows  328  enter mouth  334  of the gas/liquid separation device  324  and proceed downstream to passively separate the gas components from the liquid components while breaking up the gaseous slugs into relatively smaller pluralities of bubbles. 
         [0083]    As in the system of  FIGS. 1 and 2 , the gaseous slugs are broken up into smaller bubbles and exit flow tube  336 . Thereafter the primarily gaseous medium is assisted by compressor  339  if needed, and then injected into vertical flow tube via controlled injection device  338  where it is mixed with the predominantly liquid medium passing through spiral shaped baffle or auger  326  as in the system disclosed in  FIGS. 1 and 2 . 
         [0084]    The now homogeneous liquid/gas mixture flows with the assistance of electric submersible pump (designated as “ESP”)  340  and then to vertical flow tube  314  where it proceeds upwardly through surface as shown by arrow  342 . 
         [0085]    In all other respects, the operation of this embodiment is the same as the previous embodiments. 
       A Fifth Embodiment 
       [0086]    Referring now to  FIG. 6 , there is shown yet another alternative embodiment  400  of the invention, in which the passive gas/liquid separation device  410  is positioned in the horizontal borehole of the well. The passive gas/liquid separation device  410  of this system is similar to the system of  FIGS. 2 ,  3  and  6 . 
         [0087]    System  400  is comprised of a vertical borehole  412  provided with vertical casing  414  surrounding production flow tube  415  to form annulus  416 . 
         [0088]    Horizontal borehole  422  is depicted schematically as being joined with vertical borehole  414  at heel  420 . Located in horizontal borehole  422  is a passive gas/liquid separation device  410  which is structurally and functionally identical to the passive gas/liquid separation device shown in  FIGS. 2 ,  3  and  5 , including flow tube  426  containing central baffle  428  surrounded by circular baffle  430 . 
         [0089]    As described in connection with the embodiment of  FIGS. 2 and 3 , the slug-laden fluids proceed from the well through horizontal borehole  422  as shown schematically by arrows  432 . As the fluids flow through the horizontal borehole  422 , the gaseous slugs  431  are made to pass through a series of tortuous paths where they are divided into a plurality of relatively smaller bubbles as the slugs are dispersed. The mostly gaseous medium then migrates toward annulus  434  and toward compressor  436 , and is then injected under controlled conditions by injection device  435  into the flow tube  426  where a homogeneous mix  438  of liquid and relatively smaller gas bubbles is produced. 
         [0090]    Annulus packer seal  440  is positioned in the annulus and includes having a release vent valve  442  which permits release of the predominantly gaseous media in the event the pressure rises in annulus  434  exceeds a pre-set value. 
         [0091]    The resultant homogeneous mixture depicted by arrow  438  is then directed to surface. 
         [0092]    In all other respects, the passive gas/liquid separation system shown in  FIG. 6  is structurally and functionally the same as the corresponding system of  FIGS. 2 and 3 . 
         [0093]      FIG. 7  is a graph which illustrates the liquid and gas pressures in relation to the depth of the well, in feet, for the embodiments of  FIGS. 1-6 . In particular, the liquid and gas conditions at two different depth locations identified respectively as “upstream location 1” and “downstream location 2” are shown in the graph. 
         [0000]    
       
         
               
             
               
               
               
             
           
               
                   
               
               
                 LIST OF REFERENCES 
               
               
                   
               
             
             
               
                   
               
             
          
           
               
                 10 
                 System 
                 FIG. 1, FIG. 1A 
               
               
                 12 
                 Vertical Wellbore 
                 FIG. 1, FIG. 1A 
               
               
                 14 
                 Casing 
                 FIG. 1, FIG. 1A 
               
               
                 16 
                 Gas/Liquid Separation Device 
                 FIG. 1, FIG. 1A 
               
               
                 18 
                 Flow Tube 
                 FIG. 1, FIG. 1A 
               
               
                 20 
                 Heel Portion 
                 FIG. 1, FIG. 1A 
               
               
                 22 
                 Horizontal Borehole 
                 FIG. 1 
               
               
                 23 
                 Arrow 
                 FIG. 1 
               
               
                 24 
                 Spiral Baffle, or Auger 
                 FIG. 1, FIG. 1A 
               
               
                 26 
                 Gaseous Slugs 
                 FIG. 1, FIG. 1A 
               
               
                 28 
                 Central Gas Flow Tube 
                 FIG. 1, FIG. 1A 
               
               
                 30 
                 Apertures in Gas Tube 28 
                 FIG. 1 
               
               
                 32 
                 Wellbore Annulus 
                 FIG. 1, FIG. 1A 
               
               
                 34 
                 Annular Packer 
                 FIG. 1 
               
               
                 35 
                 Arrow 
                 FIG. 1 
               
               
                 36 
                 Vent Valve 
                 FIG. 1 
               
               
                 38 
                 Fluid Flow (i.e., liquid, gas slugs and water) 
                 FIG. 1 
               
               
                 40 
                 Gas Injection Device 
                 FIG. 1, FIG. 1A 
               
               
                 42 
                 Optional Electric Submersible Pump 
                 FIG. 1 
               
               
                 44 
                 Compressor 
                 FIG. 1 
               
               
                 45 
                 Mouth of Flow Tube 18 
                 FIG. 1 
               
               
                 46 
                 Arrows Depicting Fluid Flow 
                 FIG. 1 
               
               
                 47 
                 Arrows Depicting Gas Flow 
                 FIG. 1, FIG. 1A 
               
               
                 48 
                 Gas Lift Mandrel 
                 FIG. 1 
               
               
                 100 
                 Alternative Embodiment 
                 FIGS. 2, 3 
               
               
                 102 
                 Gas/Liquid Separation Device 
                 FIGS. 2, 3 
               
               
                 112 
                 Wellbore 
                 FIGS. 2, 3 
               
               
                 114 
                 Casing 
                 FIGS. 2, 3 
               
               
                 116 
                 Flow Tube 
                 FIGS. 2, 3 
               
               
                 118 
                 Annulus 
                 FIGS. 2, 3 
               
               
                 120 
                 Plug 
                 FIGS. 2, 3 
               
               
                 124 
                 Tortuous Apertures 
                 FIGS. 2, 3 
               
               
                 126 
                 Liquid Flow 
                 FIG. 2 
               
               
                 128 
                 Gaseous Slugs 
                 FIG. 2 
               
               
                 130 
                 Central Separator Baffle 
                 FIG. 2 
               
               
                 132 
                 Circular Baffle 
                 FIG. 2 
               
               
                 134 
                 Arrows Depicting Fluid Flow 
                 FIG. 2 
               
               
                 136 
                 Arrows Depicting Gaseous Flow 
                 FIG. 2 
               
               
                 137 
                 Liquid Flow 
                 FIG. 2 
               
               
                 138 
                 Gas Injection Device 
                 FIG. 2 
               
               
                 140 
                 Compressor 
                 FIG. 2 
               
               
                 142 
                 Packer 
                 FIG. 2 
               
               
                 144 
                 Vent Valve 
                 FIG. 2 
               
               
                 200 
                 Another Alternative Embodiment 
                 FIG. 4 
               
               
                 210 
                 Flow Tube 
                 FIG. 4 
               
               
                 212 
                 Base Plate of the Flow Tube 
                 FIG. 4 
               
               
                 214 
                 Apertures in Flow Tube 
                 FIG. 4 
               
               
                 216 
                 Arrows Depicting Gaseous Flow 
                 FIG. 4 
               
               
                 218 
                 Annulus 
                 FIG. 4 
               
               
                 220 
                 Casing 
                 FIG. 4 
               
               
                 300 
                 Alternative Embodiment/System 
                 FIG. 5 
               
               
                 310 
                 Vertical Borehole 
                 FIG. 5 
               
               
                 312 
                 Vertical Casing 
                 FIG. 5 
               
               
                 314 
                 Vertical Production Flow Tube 
                 FIG. 5 
               
               
                 316 
                 Annulus 
                 FIG. 5 
               
               
                 318 
                 Packer Seal 
                 FIG. 5 
               
               
                 320 
                 Heel 
                 FIG. 5 
               
               
                 322 
                 Horizontal Borehole 
                 FIG. 5 
               
               
                 324 
                 Gas/Liquid Separation Device 
                 FIG. 5 
               
               
                 326 
                 Spiral Shaped Baffle or Auger 
                 FIG. 5 
               
               
                 328 
                 Arrows 
                 FIG. 5 
               
               
                 330 
                 Slugs 
                 FIG. 5 
               
               
                 334 
                 Mouth of Gas/Liquid Separation Device 
                 FIG. 5 
               
               
                 336 
                 Flow Tube 
                 FIG. 5 
               
               
                 338 
                 Compressor 
                 FIG. 5 
               
               
                 339 
                 Gas Injection Device 
                 FIG. 5 
               
               
                 340 
                 Electric Submersible Pump (“ESP”) 
                 FIG. 5 
               
               
                 342 
                 Arrows Depicting Homogeneous Fluid Flow 
                 FIG. 5 
               
               
                 400 
                 Alternative Embodiment - System 
                 FIG. 6 
               
               
                 410 
                 Passive Gas/Liquid Separation Device 
                 FIG. 6 
               
               
                 412 
                 Vertical Borehole 
                 FIG. 6 
               
               
                 414 
                 Vertical Casing 
                 FIG. 6 
               
               
                 415 
                 Vertical Flow Tube 
                 FIG. 6 
               
               
                 416 
                 Annulus 
                 FIG. 6 
               
               
                 418 
                 Optional Packer Seal 
                 FIG. 6 
               
               
                 420 
                 Heel 
                 FIG. 6 
               
               
                 422 
                 Horizontal Borehole 
                 FIG. 6 
               
               
                 426 
                 Horizontal Flow Tube 
                 FIG. 6 
               
               
                 428 
                 Central Baffle 
                 FIG. 6 
               
               
                 430 
                 Circular Baffle 
                 FIG. 6 
               
               
                 431 
                 Gaseous Slugs 
                 FIG. 6 
               
               
                 432 
                 Arrows Depicting Fluid From Well 
                 FIG. 6 
               
               
                 434 
                 Annulus 
                 FIG. 6 
               
               
                 435 
                 Injection Device 
                 FIG. 6 
               
               
                 436 
                 Compressor 
                 FIG. 6 
               
               
                 438 
                 Arrows Depicting Homogeneous Mix 
                 FIG. 6 
               
               
                 440 
                 Packer Seal 
                 FIG. 6 
               
               
                 442 
                 Release Vent Valve 
                 FIG. 6
A system and method for improving the flow characteristics of gaseous slug-laden liquid hydrocarbon wells, particularly from horizontal, of similar boreholes. The invention provides a system and method which essentially homogenizes the liquid and the gas, utilizing a unique flow tube arrangement and a sequence of steps by first breaking up and separating the slugged gas from the liquid at a first location, and then gathering it into holding location--i.e., an annulus section--where it is re-introduced in controlled amounts into the liquid downstream of the first location. The gas is re-introduced into the liquid flow in such pre-determined and controlled quantities as to promote better pressure and flow characteristics of the hydrocarbon liquid product. Various alternative gas/liquid separation devices are incorporated into the system of the invention, which devices may be located either in a vertical wellbore or a horizontal wellbore, depending upon the particular well characteristics. Optionally, an electric submersible pump may be incorporated where needed to assist the mixed production flow toward surface. A compressor may optionally be provided in the gaseous holding location, where needed. An apparatus for homogenizing production fluid from an oil well having one or more horizontal bores is also disclosed.