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CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    The present application for patent claims the benefit of U.S. Provisional Applications bearing Ser. Nos. 61/254,137, 61/254,144, and 61/254,146, all filed on Oct. 22, 2009, which are incorporated by reference in their entirety. 
     
    
     BACKGROUND 
       [0002]    1. Field of the Invention 
         [0003]    This invention relates to oil field production apparatus and techniques, and more particularly, to such apparatus and techniques for use in the production of heavy oil or viscous crude oil. 
         [0004]    2. Background of the Invention 
         [0005]    It has been known to produce viscous crude oils in reservoirs by drilling vertical wells into the producing zone and then injecting steam into the producing zone to increase the mobility and reduce the viscosity of the viscous crude. This steam injection has been done in several different ways. In one technique, wells in the reservoir can be cyclically steamed using a process called cyclic steam stimulation (CSS). In this process, steam is injected down a vertical well into the producing zone. The steam is allowed to “soak” in the reservoir for a relatively short period of time to heat the crude oils, thus reducing its viscosity and increasing its mobility. The well is then placed back in production for a relatively longer period of time to extract the heated less viscous crude oil. This cycle is typically repeated until the production becomes unprofitable. 
         [0006]    Another technique which has been used to produce viscous crude reservoirs is to drill vertical wells in a geometrical pattern into the producing zone, such as in a 5-spot or 9-spot pattern. In these geometrical patterns, the wells are placed within the reservoir field, typically in a symmetric fashion, and are designated as either an injection well or a production well based on its position in the pattern. Steam is continuously injected into the producing zone via the injection wells in an attempt to heat the viscous crude oil and drive it to neighboring vertical producing wells in the geometrical array. 
         [0007]    In the initial development of a reservoir of viscous crude these described methods have worked well. Over time however, the steam tends to congregate in the upper portion of the producing zone. This, of course, may cause less heating of the viscous crude in the lower portion of the producing zone. The heavy crude saturated lower portion of the producing zone is not depleted as the high viscosity of the crude prevents its migration to the well bores of the producing wells. Thus large quantities of potentially producible crude oil can otherwise become not recoverable. 
         [0008]    It is known in the art that horizontally-oriented, or horizontal wells can be utilized to help production from the portions of the producing zone, especially the lower portion discussed above, which are typically not depleted after injecting steam with vertical wells. It is desirous in these assemblies to deliver uniformly distributed steam to the producing zone along the entire length of the horizontal section of the well. 
         [0009]    Horizontal steam injection wells are becoming more functional and efficient for heavy oil steam flooding and in many cases the only economic solution to produce some reservoirs. Successful application of horizontal steam injection requires controlled steam distribution along the entire length of the horizontal section. Many devices have been promoted as completion methods to provide this controlled distribution; however, these devices have not been tested and have severe limitations. 
         [0010]    The main limitation is that the proposed equipment can at best provide control for the injection of single phase steam (“100% quality”). The performance of such devices when extracting a portion of a wet steam flow, vapor and liquid, suffers from phase splitting effects. This phase splitting phenomenon relates to the fact that the percent of vapor extracted from the total vapor is different than the percent liquid extracted from the total liquid. For example, if the main flow has a steam quality of seventy-percent (70%), the extracted flow may have a significantly higher or lower quality. 
         [0011]    Many steam flood operations use two-phase steam consisting of both a vapor and a liquid phase. Even for operations injecting single phase, 100% quality steam at the wellhead, heat losses and water holdup can yield varying steam qualities along the subsurface horizontal section. Furthermore, if both phases do not split proportionally within a device, mass distribution is non-uniform and uniform latent heat—a more crucial reservoir performance criteria—is not achieved. 
         [0012]    Most proposed devices extract steam off the main tubing flow through a series of orifices which may or may not feed additional flow restricting mechanisms before delivery to the reservoir. The basis for many of these devices and hopes for success rely on modified Inflow Control Devices (“ICDs”) operating in a reversed flow direction (“injection mode”). Although not fully tested, such mechanisms do have potential for the distribution of single phase, 100% quality steam. However, in applications utilizing two-phase steam, flow regime effects and different phase velocities cause unknown phase distributions depending on the vapor-water separation within the device. Optimum steam distribution and latent heat delivery requires a device capable of reliably controlling injected steam over a range of qualities of about forty percent (40%) to one-hundred percent (100%). 
       SUMMARY 
       [0013]    According to an aspect of the present invention, a well assembly is disclosed for injecting steam into a subterranean reservoir. The well assembly includes a string of tubing in fluid communication with a producing zone of a subterranean reservoir. The string of tubing has a substantially vertical section and a substantially horizontal section extending from a lower portion thereof. The substantially horizontal section defines a heel portion at one end and a toe portion at the opposite end. An opening formed on the inner surface of the substantially horizontal section defines an inlet. An opening formed on the outer surface of the substantially horizontal section defines an outlet. A passageway extends between the inlet and the outlet such that steam received by the inlet is delivered to the outlet. A flow conditioning device is positioned in the string of tubing axially closer to the heel portion than the inlet to generate a more homogenous mixture of the vapor and liquid components of the two-phase steam. 
         [0014]    In one or more embodiments, the flow conditioning device is a stator. In one or more embodiments, the flow conditioning device is a plurality of axially spaced stators, which define a conditioning region. In one or more embodiments, the flow conditioning device includes a plurality of vanes extending inwardly from the inner surface of the string of tubing and around the circumference thereof. 
         [0015]    In one or more embodiments, the flow conditioning device is adapted to allow a logging tool to travel therethrough. 
         [0016]    In one or more embodiments, the flow conditioning device is positioned in the string of tubing a length between about four to six times the diameter of the string of tubing upstream of the inlet. 
         [0017]    In one or more embodiments, the flow conditioning device is carried within the string of tubing. In one or more embodiments, the flow conditioning device is positioned between segments of tubing within the substantially horizontal section of the string of tubing. 
         [0018]    In one or more embodiments, the string of tubing has a reduced cross-sectional flow area and the inlet is formed in the reduced cross-sectional flow area. For example, the reduced cross-sectional flow area can have an inwardly tapered surface and the inlet can be formed at least partially on the inwardly tapered surface. 
         [0019]    In one or more embodiments, the inlet is formed in the string of tubing axially closer to the heel portion than the outlet so that when steam is received by the passageway an axial momentum of the steam is maintained. For example, the passageway can extend less than about fifteen degrees from the inner surface. 
         [0020]    In one or more embodiments, an annulus that is in fluid communication with the outlet is formed in the outer surface of the string of tubing and extends around the circumference thereof. A nozzle can be positioned within the annulus to control the flow of steam received from the outlet. 
         [0021]    Another aspect of the present invention includes a well assembly for injecting steam into a subterranean reservoir. The well assembly includes a string of tubing in fluid communication with a producing zone of a subterranean reservoir. The string of tubing has a substantially vertical section and a substantially horizontal section extending from a lower portion thereof. The substantially horizontal section defines a heel portion at one end and a toe portion at the opposite end. An opening formed on the inner surface of the substantially horizontal section defines an inlet. An opening formed on the outer surface of the substantially horizontal section defines an outlet. A passageway extends between the inlet and the outlet such that steam received by the inlet is delivered to the outlet. A flow conditioning device is positioned in the string of tubing axially closer to the heel portion than the inlet. The flow conditioner has a plurality of vanes extending inwardly from the inner surface of the string of tubing and around the circumference thereof so that when steam is received by the plurality of vanes a more homogenous mixture of vapor and liquid components of the steam is generated. 
         [0022]    In one or more embodiments, the plurality of vanes extending inwardly from the inner surface of the string of tubing are axially spaced to define a conditioning region. 
         [0023]    In one or more embodiments, the plurality of vanes extending inwardly from the inner surface of the string of tubing provide sufficient clearance to allow a logging tool to travel therethrough. 
         [0024]    In one or more embodiments, the flow conditioning device is positioned in the string of tubing a length between about four to six times the diameter of the string of tubing upstream of the inlet. 
         [0025]    In one or more embodiments, the flow conditioning device is carried within the string of tubing. In one or more embodiments, the flow conditioning device is positioned between segments of tubing within the substantially horizontal section of the string of tubing. 
         [0026]    In one or more embodiments, the string of tubing has a reduced cross-sectional flow area and the inlet is formed in the reduced cross-sectional flow area. For example, the reduced cross-sectional flow area can have an inwardly tapered surface and the inlet can be formed at least partially on the inwardly tapered surface. 
         [0027]    In one or more embodiments, the inlet is formed in the string of tubing axially closer to the heel portion than the outlet so that when steam is received by the passageway an axial momentum of the steam is maintained. For example, the passageway can extend less than about fifteen degrees from the inner surface. 
         [0028]    In one or more embodiments, an annulus that is in fluid communication with the outlet is formed in the outer surface of the string of tubing and extends around the circumference thereof. A nozzle can be positioned within the annulus to control the flow of steam received from the outlet. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0029]      FIG. 1  is a schematic, sectional view of a prior art steam delivery in a horizontal well in the field of hydrocarbon production. 
           [0030]      FIG. 2  is a schematic, sectional view of a prior art steam delivery in a horizontal well in the field of hydrocarbon production. 
           [0031]      FIG. 3  is a schematic, sectional view of a prior art tubing string distribution assembly for use in a horizontal well in the field of hydrocarbon production. 
           [0032]      FIG. 4  is a schematic, sectional view of a tubing string distribution assembly according to an embodiment of the present invention for use in a horizontal well in the field of hydrocarbon production. 
           [0033]      FIG. 5  is a schematic, sectional view of a tubing string distribution assembly according to an embodiment of the present invention for use in a horizontal well in the field of hydrocarbon production. 
           [0034]      FIG. 6  is a schematic, sectional view of a tubing string distribution assembly according to an embodiment of the present invention for use in a horizontal well in the field of hydrocarbon production. 
           [0035]      FIG. 7  is a schematic, sectional view of a tubing string distribution assembly according to an embodiment of the present invention for use in a horizontal well in the field of hydrocarbon production. 
           [0036]      FIG. 8  is a schematic, sectional view of a tubing string distribution assembly according to an embodiment of the present invention for use in a horizontal well in the field of hydrocarbon production. 
           [0037]      FIG. 9  is a schematic, sectional view of a flow conditioner according to an embodiment of the present invention for use in a horizontal well in the field of hydrocarbon production. 
           [0038]      FIG. 10  is a schematic, section view of the flow conditioner of  FIG. 9  engaging a tubing string steam distribution assembly. 
           [0039]      FIG. 11  is a graph of steam phase splitting for a conventional tubing string distribution assembly for use in a horizontal well in the field of hydrocarbon production. 
           [0040]      FIG. 12  is a graph of steam phase splitting for a tubing string distribution assembly according to an embodiment of the present invention for use in a horizontal well in the field of hydrocarbon production. 
       
    
    
     DETAILED DESCRIPTION 
       [0041]    Referring initially to prior art  FIG. 1 , a cross sectional view shows a wellbore  11  having vertical section  11 A and horizontal section  11 B. Wellbore  11  provides a flow path between the well surface and producing sand or reservoir  31 . Tubing string  13  and slotted liner  15  are also shown in  FIG. 1 . The horizontal section  11 B of tubing string  13  includes a heel portion  13 A and an opposite toe portion  13 B. Slotted liner  15  is a completion device lining horizontal section  11 B of wellbore  11  and is typically isolated by a lead seal  17  from vertical section  11 A of wellbore  11 . Live steam is supplied via tubing string  13  and exits from toe portion  13 B at end  19 . The steam flow is as indicated by arrows  21 . Direct impingement of live steam onto slotted liner  15  at the area numbered  23  can potentially cause erosion and collapse of the liner  15 , which is an undesirable condition. Also, using this technique the steams&#39; heat is concentrated near toe portion  13 B in areas  25  and  27  of reservoir  31  rather than along the length of slotted liner  15 . 
         [0042]    Referring now to prior art  FIG. 2 , wellbore  29  has vertical section  29 A, which goes to the surface, and horizontal section  29 B that penetrates a long horizontal section of producing sand or reservoir  31 . Slotted liner  37  lines horizontal section  29 B of wellbore  29 . Tubing string  33  is run in from the surface and, on the lower end thereof is plugged off by plug  35 . The horizontal section  29 B of tubing string  33  includes a heel portion  33 A and an opposite toe portion  33 B. The length of tubing string  33 , prior to the plug  35 , is provided with spaced apart drilled holes  39  along its entire horizontal section between heel portion  33 A and toe portion  33 B. Each drilled hole  39  is covered with a sacrificial impingement strap  41 . Sacrificial impingement straps  41  are constructed of a carbon steel material and may be ceramic coated if desired. Sacrificial impingement straps  41  are welded to tubing string  33  with an offset above each drilled hole  39 . 
         [0043]    A steam generator source (not shown) is located at the surface and provides an input of steam into tubing string  33 . The steam travels down tubing string  33  to its lower horizontal section  29 B where it exits via drilled holes  39 . As will be described, while steam can exit tubing string  33  between heel portion  33 A and toe portion  33 B, uniform mass distribution and latent heat is not achieved along horizontal section  29 B. 
         [0044]    Referring to  FIG. 3 , a cross-section of a portion of tubing string  33  that is located within slotted liner  37  of  FIG. 2  is shown. Sacrificial impingement straps  41  are not shown in  FIG. 3 . Tubing string  33  includes inner surface  43  and outer surface  45 . A plurality of drilled holes  39  extend from inner surface  43  to outer surface  45 . Each drilled hole  39  extends radially outward, substantially perpendicular to inner surface  43 . Typically, drilled holes  39  are intermittently spaced between heel portion  33 A and toe portion  33 B of tubing sting  33  for delivering steam to reservoir  31 . A two-phase fluid F, typically steam having vaporous water and liquid water droplets D, travel through tubing string  33  for delivery into oil sands or reservoir  31 . 
         [0045]    When two-phase fluid F is under low velocity conditions, such as less than 40 feet per second, the flow is stratified. In particular, gravity causes the liquid phase to travel along the bottom portion of the pipe. When superficial vapor and liquid velocities are both low, the interface between the liquid and vapor phases is smooth. As vapor velocities begin to increase, the interface becomes wavy. As the superficial liquid velocities increase, the flow tends to form in slugs or large waves of liquid (short in duration) separated by stratified wavy flow. At very high superficial flow velocities, the liquid forms a ring on the inner surface of the pipe wall and the vapor travels in the center of the pipe. At high superficial vapor velocities and steam qualities, the liquid becomes entrained in the vapor core such that the pipe is filled with vapor except for small droplets of liquid mist. 
         [0046]    Liquid droplets D have higher densities and thus higher momentum than the vaporous water, which restricts the ability of liquid droplets D to change direction. When liquid droplets D traveling in the main flow of fluid F encounter a smaller vapor flow, or velocity profile, toward drilled holes  39 , liquid droplets D experience a drag force to change direction. However, the momentum of liquid droplets D opposes this change of direction, thereby resulting in less movement toward drilled holes  39 . In the embodiment shown in  FIG. 3 , the liquid droplets entrained in the vapor core must make sharp, radially outward turns with respect to the flow of fluid F for liquid droplets to enter drilled holes  39  for delivery into reservoir  31 . This results in the extracted steam having less liquid droplets D such that the quality of the steam delivered at the upstream portion of tubing string  33  is different from the steam delivered to the downstream portion of tubing string  33 . In particular, more liquid droplets will be delivered toward the downstream toe portion  33 A of tubing string  33  than to heel portion  33 B. Such a phenomenon is known as “phase splitting.” 
         [0047]    In  FIGS. 4-8 , alternative tubing configurations are provided to counteract the phase splitting described above so that more uniform quality steam is delivered to reservoir  31  from both the upstream and downstream portions of the respective tubing strings. More particularly,  FIGS. 4-8  each show a portion of tubing sub or string of tubing  111  disposed between the heel portion and the toe portion of the horizontal section of a wellbore. As will be described, steam generated at the surface is delivered to tubing  111  for a more uniform steam quality distribution along the horizontal section of a wellbore into reservoir  31 . 
         [0048]    Referring to  FIG. 4 , tubing  111  includes a plurality of openings  117  extending from inner surface  113  to outer surface  115 . Openings  117  include an opening formed on inner surface  113  that defines inlet  117 A, an opening formed on outer surface  115  that defines outlet  117 B, and passageway  117 C extending between inlet  117 A and outlet  117 B such that steam received by inlet  117 A is delivered to outlet  117 B. Inlet  117 A is formed in the string of tubing axially closer to the heel portion than outlet  117 B. While openings  117  are illustrated as having about fifteen degree outward angles to the flow of fluid F, it should be understood that the optimum angle for openings  117  is the smallest angle allowed by machining tools. 
         [0049]    A plurality of openings  117  are preferably intermittently spaced along the length of tubing  111 . For example, openings  117  can be positioned every 100 to 500 feet along tubing  111 . In general, spacing of openings  117  will be dependent upon the particular reservoir characteristics. One skilled in the art will appreciate that isolation between a first group of openings  117  and a second group of openings  117  can be utilized. Furthermore, conventional sand control mechanisms, such as a sand screen, can be placed adjacent to openings  117 . In one embodiment, tubing  111  ends near the heel portion and openings  117  are configured in the liner. 
         [0050]    Openings  117  reduce the directional change necessary for liquid droplets to enter openings  117 , thereby making it easier for liquid droplets to exit tubing  111 . In particular, when steam is received by passageway  117 C an axial momentum of the steam is maintained. Accordingly, the difference in steam quality delivered from the upstream portion of tubing  111  compared with the downstream portion of tubing  111  is reduced as more liquid droplets entrained in the vapor core are able to exit openings  117 . 
         [0051]    Referring to  FIG. 5 , an alternative tubing configuration is provided to counteract the segregation of vapor and liquid in Fluid F so that more uniform quality steam is delivered to reservoir  31  from both the upstream and downstream portions of the respective tubing strings. As shown in  FIG. 5 , tubing  111  includes mandrel portion or tubing sub  120  with a reduced cross-sectional flow area and a plurality of openings  117  extending from inner surface  113  to outer surface  115 . Openings  117  include an opening formed on inner surface  113  that defines inlet  117 A, an opening formed on outer surface  115  that defines outlet  117 B, and passageway  117 C extending between inlet  117 A and outlet  117 B such that steam received by inlet  117 A is delivered to outlet  117 B. Inlet  117 A and outlet  117 B are formed at substantially the same axial locations between the heel and the toe of the string of tubing. As with the embodiment in  FIG. 4 , a plurality of openings  117  are preferably intermittently spaced along the length of tubing  111 , with each opening  117  being associated with a tubing sub  120 . 
         [0052]    Tubing sub  120  includes inwardly tapered surface  121  that extends between the portion of inner surface  113  having the normal diameter of tubing  111  and reduced diameter surface  123 , which is where openings  117  are located. Inwardly tapered surface  121  is located upstream of openings  117  to condition the flow of fluid F. Tubing sub  120  can also include outwardly tapered surface  125  that is positioned downstream of openings  117 , and that extends from reduced diameter surface  123  to the portion of inner surface  113  having the normal diameter of tubing  111 . 
         [0053]    The reduction in the diameter of tubing  111  at inwardly tapered surface  121  increases the velocity of fluid F, while the increase in diameter from outwardly tapered surface  125  reduces the velocity of fluid F. The continued variation of the velocity of fluid F along the length of tubing  111  induces mixing of liquid droplets D with the vaporous water prior to flowing toward openings  117 . Mixing fluid F can help provide a more uniform steam quality being delivered along the length of tubing  111 . By way of example, if tubing  111  were a conventional string of 4.5 inch tubing, inner diameter  113  would be about 3.96 inches. The desired velocity change could be achieved when reduced diameter surface  123  is equivalent to the inner diameter of standard 2⅜ inch tubing, which is about 2.44 inches. Preferably inwardly and outwardly tapered surfaces  121 ,  125  are at about fifteen degree respective inclines or declines. 
         [0054]    Referring to  FIG. 6 , an alternative tubing configuration is shown where tubing  111  includes openings  117  extending at an angle from inner surface  113  to outer surface  115 . Openings  117  include an opening formed on inner surface  113  that defines inlet  117 A, an opening formed on outer surface  115  that defines outlet  117 B, and passageway  117 C extending between inlet  117 A and outlet  117 B such that steam received by inlet  117 A is delivered to outlet  117 B. Inlet  117 A is formed in the string of tubing axially closer to the heel portion than outlet  117 B. 
         [0055]    In the embodiment, the diameter of inner surface  113  adjacent openings  117  is reduced, thereby making the thickness of tubing  111  immediately upstream and downstream of openings  117  thicker than in the embodiment shown in  FIG. 4 . Similar to  FIG. 5 , tubing sub  120  includes inwardly extending tapered surface  121  that extends between the portion of inner surface  113  having the normal diameter of tubing  111  and reduced diameter surface  123 , which is where openings  117  are located. Inwardly tapered surface  121  is located upstream of openings  117  to condition the flow of fluid F. Outwardly tapered surface  125  is positioned downstream of openings  117  and extends from reduced diameter surface  123  to the portion of inner surface  113  having the normal diameter of tubing  111 . 
         [0056]    Tubing sub  120  in  FIG. 7  is substantially the same as in  FIGS. 5 and 6  except that openings  117  extend axially through tubing  111  from inwardly tapered surface  121 . Openings  117  include an opening formed on inner surface  113  that defines inlet  117 A, an opening formed on outer surface  115  that defines outlet  117 B, and passageway  117 C extending between inlet  117 A and outlet  117 B such that steam received by inlet  117 A is delivered to outlet  117 B. Inlet  117 A is formed in the string of tubing axially closer to the heel portion than outlet  117 B. Preferably, openings  117  are as close to parallel with the axial flow of fluid F as possible with machining capabilities. Locating openings  117  on inwardly tapered surface  121  allows liquid droplets to enter outlets  117  with minimal deviation from the path of liquid droplets D prior to encountering reduced diameter surface  123 . For example, the inwardly tapered surface  121  can be tapered about fifteen degrees from an axis of the tubing  111  and the inlet can be about parallel to the axis of the tubing  111 . 
         [0057]    As shown in  FIG. 7 , openings  117  extend axially to an annulus  129  formed radially outward of reduced diameter surface  123 . In particular, annulus  129  is formed in the outer surface  115  of the string of tubing and extends around the circumference thereof. However, in some embodiments annulus  129  is not present and openings  117  axially extend between inwardly tapered surface  121  and outer surface  115 . 
         [0058]    The embodiment shown in  FIG. 8  is substantially the same as  FIG. 7  except that nozzles  131  are positioned in annulus  129  to receive fluid from openings  117 . Nozzles  131  can be sized to more precisely control the rate of steam delivery into reservoir  31  from each opening  117  along tubing  111 . Examples of nozzles  131  include an orifice with a reduced cross-section or a venturi. Additionally, because nozzles  131  are controlling the rate of steam delivery in this embodiment, openings  117  can be enlarged to enhance liquid droplet D capture to a predetermined amount. 
         [0059]    As will be readily understood by those skilled in the art, tubing  111  for each of the embodiments shown in  FIGS. 4-8  can be a tubing sub that is positioned between pairs of tubing rather than being integrated in the string of tubing itself. This type of delivery can prevent steam migration into the underlying water zone or into the upper desaturated portion of the reservoir. Also by delivering the steam uniformly along the entire horizontal portion of the producing zone penetrated by the horizontal portion of the well, any potential damage to a production liner in this horizontal bore is reduced. Furthermore, the above embodiments reduce phase splitting along the horizontal portion of the wellbore, thus delivering a uniform steam quality and ensuring uniform latent heat to the reservoir. 
         [0060]    Referring to  FIG. 9 , a flow conditioner or conditioning sub  133  includes a conditioner housing  135  that is substantially tubular. Frusto-conical end pieces  137 , 139  are positioned at each end of housing  135  with an opening  141  being formed at upstream end piece  137  and an opening  143  being formed at downstream end piece  139 . End pieces  137 , 139  are tapered such that openings  141 ,  143  have a smaller diameter than housing  135 . 
         [0061]    Carried within housing  135  is a conditioning mechanism  145  extending coaxially with housing  135 . Conditioning mechanism  145  includes a plurality of inwardly extending vanes or stators  147  that are intermittently spaced around the inner circumference of conditioning mechanism  145 . Stators  147  typically extend axially downstream, and provide enough clearance between their respective radially inward tips so as to define a clearance  148  through which conventional logging tools can be deployed and retrieved. 
         [0062]    Each set of circumferentially spaced stators define a conditioning stage  149 . Preferably, conditioning mechanism  145  includes a plurality of spaced-apart conditioning stages  149  along the length of conditioning mechanism  145  to create a conditioning region  151 . Typically a conditioning region of about ten (10) to thirty (30) inches is sufficient to obtain homogeneous mixture of the two-phase fluid F. For example, inwardly extending vanes  147  can be made longer to achieve a greater amount of mixing over a shorter length. Furthermore, the flow of two-phase fluid F can be increased to obtain a greater amount of mixing. Components of conditioning mechanism  145  are preferably hardened metals for the severe environmental operating conditions associated with steam distribution for hydrocarbon production. 
         [0063]    Referring to  FIG. 10 , conditioning sub  133  is positioned upstream of steam distribution assembly  153 . For example, flow conditioning device can be positioned in the string of tubing a length of approximately four to six times the diameter of tubing  111  upstream of opening  117 . Accordingly, for 4.5 inch tubing the conditioning sub  133  is positioned approximately between 18 and 27 inches upstream of opening  117 . The positioning of conditioning sub  133  can however be positioned closer to or farther from steam distribution assembly  153  if desired such as two to ten times the diameter of tubing  111 . Openings  141 ,  143  of conditioning sub  133  engage segments of tubing  111 , such as tubing  111  of upstream steam distribution assembly  153 . Distribution assembly  153  can be, for example, those discussed in  FIGS. 4-8  or another steam distribution assembly such as the Equalizer Steam Distribution Sub commercially available from Baker Hughes. 
         [0064]    Conditioning the flow of fluid F, or generating a more homogenous mixture, immediately upstream of distribution assembly  153  will result in a more representative sample or extraction of the two-phase fluid F. In annular flow regimes, conditioning sub  133 , through the plurality of conditioning stages  149 , helps to remove water film or collected condensation from the inner surface of tubing  111  and to homogenize it with the vapor in fluid F. The inner diameter of housing  135  and conditioning mechanism  145  can be increased in order to increase the size and number of stators  147  for more conditioning as desired. 
       Example I 
       [0065]    As will be described below, the performance of an alternative tubing configuration using flow conditioner or conditioning sub  133  was compared to a conventional tubing string distribution assembly using a surface horizontal steam injection facility. The horizontal steam injection facility is capable of testing a wide range of full-sized downhole completion equipment, such as tubing and liner flow control devices, at the surface at controlled conditions. Additional details of the surface horizontal steam injection facility can be found in S.P.E. paper #132410, titled, “Addressing Horizontal Steam Injection Completions Challenges with Chevron&#39;s Horizontal Steam Injection Test Facility.” 
         [0066]    The steam quality extracted from each tubing configuration was measured for all possible combinations of three inlet pressures, two inlet steam qualities, six inlet rates and two pressure extraction ratios. The figures below show the difference between the steam quality extracted through the device&#39;s exit and the steam quality flowing in the tubing as a function of the tubing superficial vapor velocity. 
         [0067]      FIG. 11  shows steam quality results obtained using 4.5 inch tubing with four one-quarter inch holes drilled perpendicular from horizontal and phased 90 degrees around the circumference. This tubing device is similar to that shown in  FIG. 3 , where liquid droplets must make a sharp 90 degree turn with respect to the flow of fluid for the liquid droplets to enter the holes for delivery into the reservoir. The range of steam quality differences between the entrance and extraction of the device has a large variation of −15 to +15 steam quality units. 
         [0068]      FIG. 12  shows steam quality results conducted using the flow conditioning device positioned upstream of the device that produced the results shown in  FIG. 11 . Improvement is seen over the entire velocity range with significant improvement above 40 ft/sec which roughly corresponds to the transitional velocity from stratified to annular flow. In this annular flow regime the steam quality differences are centered around a value greater than zero but show a significantly smaller variation and thus are more predictable. The steam quality over the entire velocity range yields a tighter steam quality difference band compared to the steam quality obtained using the four ¼″ holes drilled perpendicular from horizontal shown in  FIG. 11 . As previously discussed, flow conditioning device induces mixing of liquid droplets with the vaporous water prior to the steam exiting via the drilled holes. 
         [0069]    While the invention has been shown in only some of its forms, it should be apparent to those skilled in the art that it is not so limited, but susceptible to various changes without departing from the scope of the invention. For example, tubing  111  could end near the heel portion such that conditioning sub  133  and steam distribution assembly  153  are configured and intermittently spaced within the liner.

Summary:
Methods and apparatus for enhanced and improved viscous oil recovery are disclosed. A horizontal well is drilled through the viscous oil formation. A specially designed tubing string includes outlets that deliver steam more uniformly into the entire horizontal extent of the well borehole. Heat from the steam mobilizes and lowers the viscosity of the heavy crude wherein the crude is then produced to the surface via conventional lift arrangements.