Patent Abstract:
An apparatus and method for improving multilateral well formation and reentry are disclosed. The apparatus comprises a tubular assembly, which includes an adjustable coupling device and a packer. The method comprises the use of the tubular assembly.

Full Description:
CROSS-REFERENCE TO RELATED APPLICATIONS  
       [0001]     The priority of U.S. Provisional Application 60/673,933, filed on Apr. 22, 2005, is hereby claimed and the specification thereof is incorporated herein by reference. This application and U.S. Pat. Nos. 6,260,623, 6,427,777 and 6,622,792, which are incorporated herein by reference, are commonly assigned to KMK Trust. 
     
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH  
       [0002]     Not applicable.  
       FIELD OF THE INVENTION  
       [0003]     The present invention is directed to an apparatus and method for improving the formation of multiple lateral wells in new and pre-existing wellbores, and positive, selective reentry of each lateral well.  
       BACKGROUND OF THE INVENTION  
       [0004]     Several advantages are provided by drilling relatively high angle, deviated or lateral wells from a generally common wellbore such as a) access to the regular oil and gas reserves without additional wells being drilled from the surface, b) avoiding unwanted formation fluids, c) penetration of natural vertical fractures, and d) improved production from various types of formations or oil and gas reserves. Additionally, reentry of one or more lateral wells is often required to perform completion work, additional drilling, or remedial and stimulation work. Thus, lateral wells have become commonplace from the standpoint of new drilling operations and reworking existing wellbores.  
         [0005]     Ordinarily, lateral well completion and/or reentry requires expensive downhole wireline surveys to accurately position the diverter or whipstock which is used to direct the boring or completion tool through a wall of a generally vertical wellbore into the adjacent formation. Without a survey, the lateral well formed may not be accurately recorded for purposes of reentry. For example, U.S. Pat. Nos. 4,304,299; 4,807,704; and 5,704,437 each describe a method and/or apparatus for producing lateral wells from a generally vertical common wellbore using conventional techniques and tools. In each instance, one or more lateral wells may be produced at a different depth and location in the common wellbore and reentered. Consequently, the whipstock must be repositioned at the new depth and location. Each time the whipstock is repositioned at a different depth and location, the change in depth and lateral orientation relative to a point of reference is recorded. In many applications using conventional threaded connections, the exact depth and location of each lateral well formed cannot be accurately or efficiently recreated using the same system and technique. As a result, a downhole directional survey is necessary to relocate the exact depth and location of each lateral well upon reentry.  
         [0006]     Recognizing the disadvantages of the foregoing techniques, U.S. Pat. No. 2,839,270 and, more recently, U.S. Pat. No. 5,735,350 address the need for a more accurate method and/or apparatus for producing and reentering lateral wells without the need for a directional survey. For example, U.S. Pat. No. 2,839,270 describes a technique for selectively forming a lateral well through a wall of a common wellbore at a predetermined depth and lateral orientation by means of a supporting apparatus which includes apertures formed at predetermined locations in the supporting apparatus. The apertures determine the relative depth and lateral orientation of each lateral well and are prefabricated according to the particular common wellbore in which the supporting apparatus is installed. The whipstock is then positioned using one or more specially designed latches which engage a corresponding aperture designed for receipt of the respective latch.  
         [0007]     Similarly, U.S. Pat. No. 5,735,350 describes a method and system for creating lateral wells at pre-selected positions in a common wellbore by means of a diverter assembly having a plurality of locator keys specially designed to engage a corresponding nipple formed in the wellbore casing having a unique profile. Although this technique may be employed in new and existing wells, it is expensive and, in some instances, inappropriate because the prefabricated keys and nipples are permanently and integrally formed according to the particular formation characteristics of the common wellbore in which the system is installed.  
         [0008]     More recently, a system and method for use in a completed wellbore lined with casing was described in U.S. Pat. No. 6,427,777. This system uses a directional survey to position an anchor at a predetermined depth and lateral orientation relative to a longitudinal position and lateral position of the desired lateral well. Because a directional survey is used to position the anchor after the casing is set and secured, the exact location of a pre-formed opening in the casing is difficult to find. And, because the system is designed for completed wellbores, the system typically requires running equipment in the wellbore which is different than the equipment used to line and secure the wellbore with casing. Finally, the casing must be milled with a different type of bit than the bit used to drill through the formation when the system is used in a completed wellbore without pre-formed openings in the casing. As a result, the system must be run in the wellbore twice to form each lateral well.  
       SUMMARY OF THE INVENTION  
       [0009]     The present invention meets the above needs and overcomes one or more deficiencies in the prior art by providing an apparatus for adjusting alignment between one section of a tubular assembly and another section of the tubular assembly. The apparatus comprises a first coupler coupled to one section of the tubular assembly and a second coupler coupled to another section of the tubular assembly. The first coupler includes a plurality of grooves equidistantly spaced about the circumference of the first coupler. The second coupler includes a plurality of teeth equidistantly spaced about the circumference of the second coupler, wherein each tooth is cooperatively engaged with a corresponding groove from the plurality of grooves. The first coupler and the second coupler are fully engaged to prevent rotational movement therebetween at a first position and are partially engaged to prevent incremental rotational movement therebetween at a second position.  
         [0010]     In another embodiment, the present invention provides a packer for use in forming a lateral borehole through the wall of a wellbore. The packer comprises a first passage having an opening in an upper portion of the packer and a side opening in the packer and a second passage having an opening in the upper portion of the packer and an opening into the first passage for fluid communication between the first passage opening in the uppoer portion of the packer and the second passage opening in the upper portion of the packer.  
         [0011]     In yet another embodiment, the present invention provides a method for forming a lateral borehole through a wall of a wellbore with a packer having a first passage in fluid communication with a second passage. The method comprises: i) setting the packer at a predetermined depth and azimuth; ii) positioning a flexible boring tool through the first passage and a side opening in the packer; iii) forming the lateral borehole with the flexible boring tool; and iv) pumping a fluid through the second passage and a portion of the first passage. 
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0012]     The present invention is described in detail below with reference to the attached drawing figures, wherein:  
         [0013]      FIG. 1 . is an elevational view of a tubular assembly illustrating the adjustable coupling apparatus and the packer of the present invention in partial cross-section.  
         [0014]      FIG. 2A  is a cross-sectional view of the packer illustrated in  FIG. 1 .  
         [0015]      FIG. 2B  is a cross-sectional view of the packer illustrated in  FIG. 1  and a flexible boring tool inserted there through into a formation.  
         [0016]      FIG. 3A  is an elevational view of the adjustable coupling apparatus illustrated in  FIG. 1 , fully engaged.  
         [0017]      FIG. 3B  is an elevational view of the adjustable coupling apparatus illustrated in  FIG. 1 , partially engaged. 
     
    
     DESCRIPTION OF PREFERRED EMBODIMENTS  
       [0018]     In the description which follows, like parts are marked throughout this description in drawings with the same reference numerals, respectively. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated, in scale or in schematic form, in some details of conventional elements may not be shown in the interest of clarity and conciseness.  
         [0019]      FIG. 1  is an elevational view of a tubular assembly  100  shown in partial cross-section and illustrates one embodiment of the present invention. The tubular assembly  100  may be used in both new and preexisting well environments and is generally shown within a main well bore  112  that has been drilled generally vertically into a surface  114  of the earth in a conventional manner. The well bore  112  extends generally vertically downward into an area of the formation  116  where it may also be desired to induce or inject fluids. In this embodiment, the well bore  112  is generally vertical, however, may extend in other non-vertical directions approaching horizontal. The main casing  118  may be set and secured in the well bore  112  with a cement liner  120  in a conventional manner or in the manner described in U.S. Pat. No. 6,622,792. Generally, the casing  118  comprises multiple segments that may be connected at the surface  114 , wherein each connection forms a casing joint  117 , as the casing  118  is lowered into the well bore  112 . Preferably, at least one of the casing segments includes a preformed opening or window  119  in the casing  118 . The opening  119  may be covered by a fiberglass mesh (not shown) or any other substantially impermeable material to prevent the cement liner  120  from compromising the annulus between the drill string  132  and the casing  118 .  
         [0020]     The tubular assembly  100  comprises a first anchor  122 , an orienting member  124 , an extension member  126 , a packer  128  and a second anchor  130 . The first anchor  122  may include a conventional packer design or it may be designed in the same manner as the anchor described in U.S. Pat. No. 6,427,777. The first anchor  122  may be positioned within the well bore  112  at a predetermined position using a drill string  132  comprising segments of connected drill pipe. The predetermined position of the first anchor  122  may be determined by any conventional survey means, such as a directional down hole survey of the formation  116  to determine the depth (longitudinal position) and azimuth (lateral orientation) of the first anchor  122 . A conventional directional survey of the well bore  112  therefore, should reveal the longitudinal position and lateral direction of each region or area of the formation  116  where hydrocarbons may be found. Based upon the survey results, the appropriate number of lateral boreholes may be determined at a given depth and azimuth. The casing  118  may include multiple preformed openings, like opening  119 , which may be aligned with each corresponding area of the formation  116  where a lateral borehole is desired. Thus, the casing  118  and the first anchor  122  may be made up and lowered into the well bore  112  until the opening  119  is generally aligned with an area of the formation  116  where a lateral borehole is desired. The longitudinal position and lateral orientation of the opening  119  may be generally aligned with an area of the formation  116  where a lateral borehole is desired by reference to a longitudinal reference point and lateral reference point located on the first anchor  122  in the manner described in U.S. Pat. No. 6,427,777. If, however, the casing  118  does not include opening  119 , then the first anchor  122  and the casing  118  may be made up and lowered into the well bore  112  adequately below an area of the formation  116  where a lateral borehole furtherest from the surface  114  is desired.  
         [0021]     Once the casing  118  and the first anchor  122  are set and secured in the well bore  112 , the orienting member  124 , the extension member  126 , the packer  128  and the second anchor  130  may be lowered into the well bore  112  until the orienting member  124  is slidably engaged within the first anchor  122 . The first anchor  122  may be modified to include the longitudinal reference point and the lateral reference point in most applications after the first anchor  122  is permanently secured.  
         [0022]     The side opening  129  in the packer  128  may be aligned with the opening  119  in the casing  118  using the extension member  126 . Alternatively, the side opening  129  in the packer  128  may be generally positioned at a predetermined longitudinal position and lateral orientation corresponding with a preferred area of the formation  116  where a lateral bore hole may be desired. The extension member  126  includes one end  158  connected to the orienting member  124  and another end  154  connected to the packer  128 . The length of the extension member  126  may be varied by using one or more shorter or longer drill pipe segments  156 . Each unilateral connection  140  maintains lateral orientation and alignment between the orienting member  124  and the side opening  129  in the packer  128 . Each unilateral connection  140  and drill pipe segment  156  may be designed and made up in the manner described in U.S. Pat. No. 6,427,777. An adjustable coupling device  134  permits the lateral orientatin of the packer  128  to be adjusted in preselected increments as more particularly described in reference to  FIGS. 3A and 3B .  
         [0023]     The packer  128  may therefore, be positioned at any predetermined depth and lateral orientation by using the first anchor  122 , the orienting member  124  and the extension member  126 . The first anchor  122  and the orienting member  124  may therefore, be constructed and operated in the same manner as the anchor and the orienting member described in U.S. Pat. Nos. 6,427,777 and 6,662,792. Alternatively, the first anchor  122  and the orienting member  124  may be constructed and operated in the same manner as the bridge plug and orienting device described in U.S. Pat. No. 6,260,623. A second anchor  130  may be positioned above the packer  128  for additional stability, if necessary. The second anchor  130  may include another packer and/or slips, which may be integral with, or connected to, the packer  128 .  
         [0024]     Referring now to  FIGS. 2A and 2B , cross-sectional views of the packer  128  are illustrated with ( FIG. 2B ) and without ( FIG. 2A ) a flexible boring tool  200 . The flexible boring tool  200  may include a conventional drill bit or a fluid jet nozzle at a distal end  204  for use in forming a lateral bore hole  202  through the cement liner  120 , a wall of the well bore  112  and into the formation  116 . The flexible boring tool  200  may be positioned at the lower end of a coil tubing string. In the event that a fluid jet nozzle is preferred at the distal end  204  the flexible boring tool  200 , the fluid jet nozzle may be designed and operated in the manner described in U.S. Pat. No. 6,260,623 to bore through and/or stimulate the formation  116  with one of a fluid and another fluid.  
         [0025]     The packer  128  includes a first passage  206  for receipt of the flexible boring tool  200  and at least one of the fluid and the another fluid. The first passage  206  has an opening  208  centrally positioned in an upper portion of the packer  128  and a side opening  129 . The first passage  206  may extend from the first passage opening  208  in the upper portion of the packer  128  to the surface  114  of the well bore  112  through the drill string  132 . The packer  128  also includes a second passage  210  for receipt of one of the fluid and the another fluid. The second passge  210  has an opening  212  in the upper portion of the packer  128  and an opening  214  into the first passage for fluid communication between the first passage opening  208  in the upper portion of the packer  128  and the second passage opening  212  in the upper portion of the packer  128 . The second passage opening  214  into the first passage  206  may be closer to the side opening  129  than to the first passage opening  208  in the upper portion of the packer  128 .  
         [0026]     The packer  128  may be expanded to engage the side opening  129  of the packer  128  with the lateral bore hole  202 . The packer  128  may be expanded with a sealing element  216 , which substantially prevents the fluid, the another fluid and/or formation cuttings from passing between the formation  116  and an annulus between the casing  118  and the drill string  132 .  
         [0027]     The second passage opening  214  into the first passage  206  is positioned to direct at least one of the fluid and the another fluid toward the first passage opening  208  in the upper portion of the packer  128 . One of the fluid and the another fluid therefore, enters the second passage opening  212  in the upper portion of the packer  128  and exits through the first passage opening  208  in the upper portion of the packer  128  for controlling at least one of a plurality of entrained cuttings from the formation of the lateral bore hole  202  and a hydrostatic pressure between the well bore  212  and the lateral bore hole  202 . A check valve  218  may be positioned in the second passage  210  near the second passage opening  212  in the upper portion of the packer  128  to prevent one of the fluid and the another fluid from circulating away from the second passage opening  214  into the first passage  206  toward the second passage opening  212  in the upper portion of the packer  128 .  
         [0028]     The fluid and the another fluid may comprise at least one of a liquid and a gas that are introduced through the drill string  132  to the second passage opening  212  in the upper portion of the packer  128  and the flexible boring tool  200 . The fluid and the another fluid therefore, may or may not comprise the same fluid.  
         [0029]     The selection of the fluid and the another fluid may depend on the desire to control the velocity and the volume of entrained formation cuttings flowing through the first passage  206  and/or the hydrostatic pressure between the well bore  112  and the lateral bore hole  202 . For example, selection of a heavier fluid raises the hydrostatic pressure. Conversely, selection of a lighter fluid lowers the hydrostatic pressure. A gas, such as oxygen or nitrogen, or a combined liquid and gas (foam) may therefore, be used as the fluid or the another fluid in the second passage  210  to lower the hydrostatic pressure. A liquid or a gel, however, may be preferred to carry more formation cuttings and reduce the slip of such cuttings. As the velocity of the fluid or the another fluid is increased through the second passage  210 , more formation cuttings may be carried (entrained) through the first passage  206 .  
         [0030]     In another embodiment, the packer  128  may comprise a third passage  220  for receipt of one of the fluid and the another fluid. The third passage  220  has an opening  222  in the upper portion of the packer  128  and an opening  224  into the first passage  206  for fluid communication between the third passage opening  222  in the upper portion of the packer  128  and the first passage opening  208  in the upper portion of the packer  128 . The third passage  220  may be used to improve the velocity and the volume of entrained cuttings flowing from the formation of the lateral bore hole  202  through the first passage  206  and control the hydrostatic pressure between the well bore  112  and the lateral bore hole  202  in the same manner as described in reference to the second passage  210 .  
         [0031]     In this embodiment, for example, the first passage  206  may comprise an independent passage throughout the full length of the drill string  132 , while the second passage  210  and the third passage  220  may be limited to the packer  128 . The one of the fluid and the another fluid may be introduced through the flexible boring tool  200 , which returns, with the formation cuttings, through the first passage  206  in the drill string  132  to the surface  114  of the well bore  112  in  FIG. 1 . The one of the fluid and the another fluid may also be introduced through the second passage  210  and the third passage  220 , which returns, with the formation cuttings, through a portion of the first passage  206  in the drill string  132  to the surface  114  of the well bore  112  in  FIG. 1 . The one of the fluid and the another fluid may be introduced through the annulus between the casing  118  and the drill string  132  to the second passage opening  214  and the third passage opening  222  in the upper portion of the packer  128 . In this manner, the fluid and/or the another fluid may originate from the same, or separate, source(s) and return through the first passage  206  in the drill string  132  to the same source at the surface  114  of the well bore  112  in  FIG. 1 .  
         [0032]     The packer  128  may therefore, be used to form the lateral bore hole  202  through a wall of the well bore  112  by first setting the packer  128  at a predetermined depth (longitudinal position) and azimuth (lateral orientation) as described in reference to  FIG. 1 . The side opening  129  of the packer  128  is initially aligned with the opening  119  in the casing  118 . The flexible boring tool  200  is then positioned through the first passage  206  and the side opening  129  in the packer  128 . If milling through the casing  118  is unnecessary, then the flexible boring tool  200  may be fitted with a drilling bit or fluid jet nozzle at its distal end  204  that is capable of forming the lateral bore hole  202  through a preferred area of the formation  116 . In one embodiment, the fluid jet nozzle may be used to form the lateral bore hole  202  by introducing one of a fluid and another fluid through the fluid jet nozzle attached to the distal end  204  of the flexible boring tool  200  at a high velocity to form the lateral bore hole  202 . As the lateral bore hole  202  is formed, formation cuttings and one of the fluid and the another fluid are forced through the lateral bore hole  202  and the side opening  129  of the packer  128  into the first passage  206 . The sealing element  216  substantially prevents formation cuttings and one of the fluid and the another fluid from entering the annulus between the casing  118  and the drill string  132 .  
         [0033]     In order to facilitate entrainment of the formation cuttings and one of the fluid and the another fluid into the first passage  206 , one of the fluid and the another fluid may be introduced through the second passage  210  and a portion of the first passage  206 , between the second passage opening  214  into the first passage  206  and the first passage opening  208  in the upper portion of the packer  128 , at a sufficient velocity to entrain the formation cuttings and at least one of the fluid and the another fluid through the first passage opening  208  in the upper portion of the packer  128 , away from the side opening  129  in the packer  128 . Introducing one of the fluid and the another fluid through the second passage  210  and the portion of the first passage  206  may also control hydrostatic pressure between the well bore  112  and the lateral bore hole  202 .  
         [0034]     Once the lateral bore hole  202  is formed, the process may be repeated as described to form multiple lateral bore holes, at the same depth or longitudinal position, without removing the packer  128  from the well bore  112 . The packer  128  may therefore, be used to entrain formation cuttings, control hydrostatic pressure and/or drill in underbalanced conditions.  
         [0035]     Referring now to  FIGS. 3A and 3B , elevational views of the adjustable coupling apparatus  134  are illustrated in a fully engaged first position ( FIG. 3A ) and a partially engaged second position ( FIG. 3B ). The adjustable coupling apparatus  134  may be used to align the packer  128  with an opening in the casing  118  or preferred lateral orientation to form a lateral bore hole without removing the packer  128  from the well bore  112 . The adjustable coupling apparatus  134  therefore, may be used to adjust alignment between one section of the tubular assembly  100  connected to one end  138  of the adjustable coupling apparatus  134  and another section of the tubular assembly  100  connected to another end  136  of the adjustable coupling apparatus  134 . The adjustable coupling apparatus  134  includes a first coupler  300  coupled to the one section of the tubular assembly  100  at the another end  136 , and a second coupler  304  coupled to the another section of the tubular assembly  100  at the end  138 . The first coupler  300  includes a plurality of grooves  302  equidistantly spaced about a circumference of the first coupler  300 . The second coupler  304  includes a plurality of teeth  306  equidistantly spaced about a circumference of the second coupler  304 . Each tooth  306  is cooperatively engaged with a corresponding groove  302 .  
         [0036]     In  FIG. 3A , the first coupler  300  and the second coupler  304  are fully engaged at a first position by a force  308 . The first coupler  300  and the second coupler  304  are restricted from rotational movement at the fully engaged first position. In  FIG. 3B , the first coupler  300  and the second coupler  304  are partially engaged at a second position by a force  312 . The first coupler  300  and the second coupler  304  may be incrementally rotated in a clockwise direction  310  at the partially engaged second position. Alternatively, the adjustable coupling apparatus  134  may be designed to permit full engagement between the first coupler  300  and the second coupler  304  by a force in a direction opposite to the force  308  illustrated in  FIG. 3A . Likewise, the adjustable coupling apparatus  134  may be designed to permit partial engagement by a force in a direction opposite to the force  312  illustrated in  FIG. 3B . The adjustable coupling apparatus  134  may also be designed to permit incremental rotational movement between the first coupler  300  and the second coupler  304  in a counter-clockwise direction, instead.  
         [0037]     The first coupler  300  and the second coupler  304  therefore, permit rotational alignment in a single direction between the one section of the tubular assembly  100  and another section of the tubular assembly  100 . The first coupler  300  and the second coupler  304  are therefore, longitudinally movable between the first position illustrated in  FIG. 3A  and the second position illustrated in  FIG. 3B . The adjustable coupling apparatus  134  enables the packer  128  to be used with the flexible boring tool  200  to form multiple equidistantly spaced lateral bore holes at the same depth or longitudinal position within the well bore  112 . As illustrated in reference to  FIG. 1 , additional lateral bore holes may be formed at other depths or longitudinal positions by removing the tubular assembly  100  and adjusting the length of the extension member  126 . Accordingly, the tubular assembly  100  may be utilized to form multiple lateral bore holes through a wall of the well bore  112  at multiple lateral positions at the same or different longitudinal positions (depths) in preexisting or new well bores with fewer runs and fewer tools.  
         [0038]     Because the tubular assembly  100  comprises many conventional or standard components, this tubular assembly  100  costs less to manufacture than any alternative systems, which may require specially designed casing and other components manufactured in accordance with the specific requirements of the particular site and well bore. Additionally, the tubular assembly  100 , and use thereof, may be employed in new and preexisting well bores using the same components, which substantially reduces production costs.  
         [0039]     While preferred embodiments of the present invention have been illustrated in detail, it is apparent that modifications and adaptations of the preferred embodiments will occur to those skilled in the art. However, it is to be expressly understood that such modifications and adaptations are within the spirit and scope of the present invention as set forth in the following claims.

Technology Classification (CPC): 4