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You are an expert at summarizing long articles. Proceed to summarize the following text: 
BACKGROUND OF THE INVENTION 
       [0001]    1. Field of the Invention 
         [0002]    This invention relates to the drilling, completion, and production of an essentially horizontal (hereafter “horizontal”) well section into and along a subsurface, geological formation that contains heavy, viscous hydrocarbons, as disclosed in U.S. Pat. Nos. 5,289,881 and 5,607,018, both issued to Frank J. Schuh. 
         [0003]    2. Description of the Prior Art 
         [0004]    U.S. Pat. No. 5,289,881 discloses in its FIG. 1 a horizontally extending well bore and casing section which contains steam injection tubing (injection tubing) 32. This injection tubing is terminated at its far down stream end by a choke 22 through which all vaporous steam (steam) injected from the surface of the earth leaves the tubing and enters the well bore casing annulus 42 for injection, through casing perforations 18, into producing zone 14. Zone 14 contains the viscous hydrocarbons that are desired to be produced to and recovered at the earth&#39;s surface. U.S. Pat. No. 5,289,881 is hereby incorporated in its entirety by reference. 
         [0005]    U.S. Pat. No. 5,607,018 discloses a related production scheme in its FIG. 9 except that steam leaves the interior of steam injection tubing 132 by way of a series of holes 133 in that tubing. Holes 133 allow steam to exit the tubing in a direction that is directly toward casing 116, i.e., a direction that is essentially perpendicular to the long axes of both the injection tubing and the casing (liner) 116. Put another way, the exiting steam from the injection tubing is pointed directly at the inner surface of the casing, and its perforations 118, for injection of that steam into the hydrocarbon bearing formation 114 to liquefy such hydrocarbons for ultimate production to and recovery at the earth&#39;s surface. It is also disclosed in this patent, column 12, that the horizontal portion of the well bore can deviate less than 90° or more than 90° from the essentially horizontal portion of the well bore. U.S. Pat. No. 5,607,018 is hereby incorporated in its entirety by reference. 
         [0006]    For sake of clarity, the horizontal sections of the well bore, casing and injection tubing are all shown in both of the aforesaid patents to be essentially straight along their longitudinal axes. In reality, this is not always the case. In drilling the horizontal portion of a well bore, the driller uses a commercially available instrument known as a three axis accelerometer to direct the drilling of that horizontal section. The typical accuracy for this instrument ranges from ¼ to ½ degree and can cause the driller to unknowingly deviate from the desired path. If the drilling path for any of a number of well known reasons, e.g., subsurface heterogeneities, tends too far upward or downward while drilling in the formation, the driller makes adjustments either up or down to the drilling apparatus to get the drill bit back on the desired drilling path. As explained hereinafter in greater detail, these adjustments, which are made while drilling proceeds unchecked, can result in the horizontal section of the well bore having, at least in parts thereof, a sinusoidal shape along the longitudinal axis of the well bore. Any sinusoidal configuration of the well bore is, upon completion of the well, transferred to the casing and injection tubing contained in the horizontal section of that well bore. 
         [0007]    Thus, in reality, there can be one or more low spots in the horizontal sections of the well bore, casing, and injection tubing which can be substantial. For example, it is not uncommon for a low spot to deviate from about one to about five feet lower in elevation than the adjacent high spot. 
         [0008]    Produced fluids, as used herein, are primarily a combination of liquid water (largely condensed steam) and liquid hydrocarbons that have been mobilized by contact with the steam injected into the formation from the injection tubing by way of the casing perforations. Produced fluids can collect in the aforementioned low spots. Undesired pools of produced fluids in such low spots not only mean lost production of desired hydrocarbons to the earth&#39;s surface, but can adversely affect the hydrocarbon production operation, e.g., by impeding or otherwise altering in a deleterious way the flow of steam in the casing annulus that surrounds the injection tubing. 
         [0009]    Accordingly, it is highly desirable to have a horizontal well bore production scheme that overcomes the ill effects of hydrocarbons collecting in casing low spots, and this invention does just that. 
       SUMMARY OF THE INVENTION 
       [0010]    In accordance with this invention, there is provided a method and apparatus for rendering mobile a viscous hydrocarbon held in a subsurface geologic formation by employing a horizontal well bore completion scheme that includes a steam injection tubing string that contains a plurality of jet nozzles that inject vaporous steam along the injection tubing, and toward a production tubing inlet. 
     
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0011]      FIG. 1  shows a cross section of a horizontal well completion pursuant to the prior art including an exemplary low spot in the well bore and its associated casing and injection tubing. 
           [0012]      FIG. 2  shows a section of injection tubing employing a jet nozzle pursuant to this invention. 
           [0013]      FIG. 3  shows a larger portion of the injection tubing of  FIG. 2  which includes a number of variably positioned and spaced-apart jet nozzles, all within this invention. 
           [0014]      FIG. 4  shows a cross section of a portion of a well completion within this invention including a showing of how the vaporous steam injected by way of a jet nozzle interacts with produced fluids in the casing annulus surrounding the injection tubing. 
       
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
       [0015]      FIG. 1  shows earth&#39;s surface  110  into which has been drilled in a conventional manner an essentially vertical well bore  111  which has been turned essentially 90° from the vertical to form an essentially horizontal well bore section (interval)  112  in hydrocarbon containing formation (reservoir)  114 . At the upstream end of horizontal section  112  of the well bore, a pack off  126  has been installed through which passes 1) steam injection tubing  120  whose horizontal section  132  contains a plurality of apertures (holes)  133  along its longitudinal axis (see  FIG. 2 ), and 2) production tubing  124  with its associated production inlet  127 . Production string inlet  127  receives produced fluids from horizontal section  112 , and transmits them by way of production tubing  124  to earth&#39;s surface  110  for recovery and other processing as desired. 
         [0016]    Steam injected from earth&#39;s surface  110  through injection tubing  120  leaves the interior of that tubing by way of both holes  133 , as shown by arrows  130 , and choke  122 ; and enters the annulus  135  inside casing  116 , which annulus surrounds horizontal section  132  of injection tubing  120 . Annulus  135  has a substantially larger internal volume than the internal volume of injection tubing  120 , e.g., a volumetric ratio of annular volume to injection tubing volume of from about 3/1 to about 5/1. This steam then leaves the interior of casing  116  by way of certain of the apertures  118  that extend around the circumference of section  112  of casing  116 , and enters the interior of formation  114 , as shown by arrows  136 . This forms a steam cavity in formation  114  from which some hydrocarbon has been recovered and in which fresh steam is motivating (liquefying) additional viscous hydrocarbon present in the walls of such steam cavity. Produced fluids enter annulus  135  by way of certain other apertures  118  as shown by arrows  138 . 
         [0017]    Line  140  in  FIG. 1  denotes the interface between vaporous steam from holes  133  and liquid, produced fluids from certain apertures  118  as afore said, and further shows that a certain volume of produced fluids will be trapped in low spot  141  of this  FIG. 1 . Low spot  141  can contain a substantial volume of trapped produced fluids because it can extend for tens of feet in length and be from one to five feet lower in elevation  150  than its associated high spot  151 . Holes  133  inject steam directly toward the interior surface  152  and holes  118  of casing  116 , i.e., essentially perpendicular to the longitudinal axis of injection tubing  120 , and are not effective in cleaning out produced fluids trapped in low area  141  of annulus  135  for recovery of same at the earth&#39;s surface. In a given well, horizontal section  112  can contain a plurality of such low spots, just one such spot  141  being shown in  FIG. 1  for sake of brevity and clarity. 
         [0018]      FIG. 2  shows a section of injection tubing  120  that employs a jet nozzle pursuant to this invention. Tubing  120  has an outer surface  201  and an inner surface  202 . The longitudinal axis of tubing  120  is shown at  200 . Steam from the earth&#39;s surface passes through interior  203  of tubing  120  in the direction shown by arrow  204 . Steam  204  can be at a pressure of from about 250 to about 680 psia, and a temperature of from about 400 to about 500° F. Jet nozzle  205  is in fluid communication between injection tubing interior  203  and casing annulus  135 . Outer surface  201  carries a jet nozzle  205  which contains a constriction  206  which accelerates the velocity of steam  204 , and a narrower passage (choke)  207  which further accelerates the compressed, pressurized steam  208  into lower pressure, larger volume annulus  135 , thus injecting steam  208  with substantial force into annulus  135 . Such compressed steam  208  is also deliberately injected along the long axis  200 , i.e., outer surface  201 , of injection tubing  120  in a direction towards production inlet  127  ( FIG. 1 ) to move both the produced fluids and steam toward the inlet for production to the earth&#39;s surface. This injection of compressed steam  208  into annulus  135  not only forcibly moves produced fluids towards production inlet  127 , but at the same time removes essentially all trapped production fluids held in one or more low spots, e.g., area  141  of  FIG. 1 , that can occur from location to location along the length of injection tubing  120 . Choke  207  can be, but is not necessarily, essentially round, and has a diameter of from about 7/32 to about 14/32 of an inch, or the equivalent if not round. 
         [0019]      FIG. 3  shows a longer section of injection tubing  120  containing a plurality of jet nozzles  205 . Note that downstream end  300  is closed and does not contain a choke  122 . Thus, choke  122  has been eliminated with out eliminating the function thereof. The injection of compressed steam  208  into annulus  135  is so robust that nozzles  205  can be spaced about the outer surface (periphery)  201  of tubing  120  in a random or patterned fashion and the results of this invention still realized. Thus, as shown in this Figure, nozzles  205  can be distributed on the top, bottom, and/or sides of tubing  120  as desired, or any individual choice or combination thereof. 
         [0020]    By using a plurality of nozzles  205  that discharge steam essentially parallel to the long axis  200  of injection tubing  120 , and toward the production inlet  127 , sufficient flow-energy is generated to transport essentially all produced fluids, including any and all produced fluids trapped in low spots, to production inlet  127 . 
         [0021]    The amount of flow-energy generated, and the lift capacity of the nozzle array employed will vary considerably depending on the details of the particular well completion, and can be controlled by the steam injection rate at the earth&#39;s surface, the production rate of produced fluids at the earth&#39;s surface, and nozzle sizing, spacing, and positioning along the injection tubing, all of which can readily be determined by one skilled in the art once apprised of this invention. With close spaced nozzles, the available energy is greater than required to transport produced fluids, and the uniformity of steam distribution maximized. With widely spaced nozzles, the available energy exceeds the transport requirement. Although nozzle spacing can vary widely, from a practical point of view a maximum spacing could be about 400 feet, and a minimum spacing about 35 feet. The spacing is from about 100 to about 150 feet under most conditions. Injection tubing  120  can, if desired, be essentially centralized inside annulus  135  to provide a clearer path for steam flow around the entire circumference of the injection tubing. Desirably, nozzles  205  will be located near the center of annulus  135  between the outer surface  201  of the injection tubing and the inner surface  400  (see  FIG. 4 ) of casing  116 . Also desirably, the operation is carried out at an essentially constant temperature and pressure within the steam cavity formed by mobilizing hydrocarbons in formation  114 . Minimizing any excess of flow-energy can be obtained by maintaining an essentially constant pressure, which also favors close spaced nozzles. 
         [0022]    The maximum lift capacity can occur at the bottom of the horizontal portion of the well bore adjacent the closed end  300  ( FIG. 3 ) of injection tubing  120 . At that location, a  280  foot spacing of nozzles can provide an average of about 3 feet of lift per hundred foot of horizontal bore hole. This lift rate can vary from about 1.2 to about 4.8 per hundred feet over the life of the well. In the middle of the horizontal interval the lift capacity is less than half of the maximum, while the lift rate for the first nozzle below packer  126  is about 30% of the maximum. Selecting a spacing that provides the required lift for the upward undulations in the horizontal interval of the well bore can lessen the variation of pressure along the horizontal borehole. 
         [0023]    The produced fluids rate at the earth&#39;s surface increases rapidly as the steam cavity expands upward to the top of formation  114 . From that point it declines until the economic production rate limit is reached. The rate of liquid steam condensate production at the earth&#39;s surface is essentially the same as the steam injection rate at the earth&#39;s surface. Thus, for a typical design the steam injection rate at the earth&#39;s surface can start at about 12,000 pounds per hour, reach a peak of about 21,000 pounds per hour, and drop to about 11,000 pounds per hour as the economic production limit is reached. 
         [0024]      FIG. 4  shows a cross-section of how produced fluids flow in the operation of this invention between adjacent jet nozzles  205  and  405 , with nozzle  405  being located on the side of injection tubing  120 , rotated about 90° from nozzle  205 . Nozzle  205  is designed to introduce the steam vapor at the rate that will enter the steam cavity between nozzles  205  and  405 . Line  406  shows the interface between essentially only vaporous steam, and essentially liquid produced fluids. Thus, immediately adjacent the outlet of nozzle  205  is primarily steam with a minor amount of liquid at the bottom of annulus  135 . Intermediate nozzles  205  and  405 , as steam escapes into formation  114  by way of holes  118  (arrows  136 ), the share (fraction) of liquid in annulus  135  increases. Just up stream of nozzle  405  the last of the steam vapor exits the annulus at that location. Thus it can be seen that steam  208  is a substantial propellant of liquid (produced fluids) that enters the annulus by way of holes  118  at the bottom of casing  116  as shown by arrow  138 . Note that the produced fluids are also forcibly propelled in the direction of arrows  208  which is essentially parallel to long axis  200  ( FIG. 3 ) and toward production inlet  127  ( FIG. 1 ). 
         [0025]      FIG. 5  shows a cross section  5 - 5  of  FIG. 4 , and further shows that annulus  135  is essentially 90% full of produced fluids at this location. 
         [0026]      FIG. 6  shows a cross section  6 - 6  of  FIG. 4 , and further shows that annulus  135  is about 40% full of produced fluids at this location. 
         [0027]      FIG. 7  shows a cross section  7 - 7  of  FIG. 4 , and further shows that annulus  135  is about 80% full of produced fluids at this location. 
         [0028]    Thus, it can be seen that produced fluids are driven by steam  208  toward inlet  127 , and, because of the flow-energy imparted by a plurality of spaced apart jet nozzles along the length of injection tubing  120 , not only moves newly entering produced fluid, but, at the same time, moves trapped produced fluids from low spots such as area  141  ( FIG. 1 ). 
       EXAMPLE 
       [0029]    Formation  114  is at a depth of about 100 feet, and a thickness of about 36 feet. A well bore is drilled down to the formation and then horizontally in that formation for about 1,300 feet about 1 foot above the bottom of the formation. The well is cased with 9⅝ inch casing from the earth&#39;s surface to the beginning of the horizontal interval. The horizontal interval is cased with pre-perforated 7 inch outer diameter liner  116  (6.366 inch inner diameter). The 3½ inch outer diameter (2.992 inch inner diameter) production tubing string  124  extends from the earth&#39;s surface to and just through the dual packer  126 , terminating at production inlet  127 . Four inch outer diameter (3.548 inch inner diameter) steam injection tubing  120  extends essentially to the bottom of the well bore, i.e., far end of the horizontal section of the well bore and its casing ( FIG. 1 ). Thirteen horizontally oriented (with respect to the long axes of both the casing and injection tubing) steam injection nozzles  205 ,  405 , etc. are placed at about 100 foot intervals along and around ( FIG. 3 ) the length of the injection tubing with their outlets facing toward inlet  127 . 
         [0030]    The horizontal section of the well bore and the steam cavity in formation  114  are kept at an essentially constant temperature and pressure of about 350° F. and about 135 psia. 
         [0031]    The  13  nozzles use an initial steam injection rate of about 945 pounds per hour per nozzle, using nozzle chokes from about 0.302 to about 0.308 inches. Individual nozzle steam emission velocities are about 1,339 feet per second. The horizontal interval varies in a sinusoidal manner up and down from the intended well bore path about 1 foot. 
         [0032]    After 3.5 years of production, the maximum steam injection rate is about 20.6 million BTU&#39;s per hour, thereby producing about 200 barrels of hydrocarbon per day and about 1,520 barrels of water per day. At this time each nozzle is emitting about 1,620 pounds of steam per hour at an exit velocity of about 1,384 feet per second. 
         [0033]    At the multi-year producing life of the well, the injection rate is 11.1 million BTU&#39;s per hour of steam. The final producing rate is about 71 barrels of hydrocarbon per day and about 820 barrels of water per day. The final individual nozzle flow rate is about 865 pounds per hour with a steam emission velocity of about 1,334 feet per second.

Summary:
A method and apparatus for recovering viscous hydrocarbons from a subsurface reservoir holding the same using an essentially horizontal well bore having a production inlet and containing steam injection tubing that carries a plurality of jet nozzles oriented to emit steam along said injection tubing towards said production inlet.