Abstract:
An apparatus and method for connecting a lateral well bore to a vertical well bore using a tieback liner while providing full bore access in the vertical well bore casing. The tieback liner is rotationally aligned with respect to a window of the casing by locating a key slot formed above the window and longitudinally aligned by using a no-go device to locate the bottom edge of the window. The tieback liner includes a snap sleeve that extends into a window of the main well bore casing and connects the tieback liner to the casing. The section of the casing receiving the snap sleeve is of a larger inner diameter than the other sections of casing. The connection between the tieback liner and casing prevents the tieback liner from rotating, tilting, or moving laterally with respect to the casing. The connection imparts significant resistance to formation loading applied at the junction.

Description:
BACKGROUND OF THE INVENTION 
   1. Field of the Invention 
   The present invention relates generally to tieback systems for lateral well bores. More specifically, the invention relates to an improved apparatus used in a multilateral completion and a method of obtaining a multilateral completion. The apparatus and method are used to tieback or connect a lateral well that is drilled from a primary well, which may be vertical or deviated, by orienting a tieback assembly at the upper end of a liner in the lateral well bore adjacent a casing window using a key, key slot, no-go device, and bottom edge of the casing window to rotationally and longitudinally locate a tieback liner with respect to the casing window. The tieback liner is then coupled to a guide rail near the casing window. After the tieback liner is installed, the invention provides full bore access in the main well bore while supporting external loads on the tieback liner. 
   2. Description of Related Art 
   Lateral well bores are routinely used to more effectively and efficiently access hydrocarbon bearing formations. Typically, lateral well bores are drilled and accessed from a window that is formed in the casing of a central or primary well bore. The casing windows are often preformed at the surface of the well prior to installation of the casing. With the window formed, the lateral well bore is formed with a drill bit and drill string. Thereafter, the liner is run into the lateral well bore and “tied back” to the main well bore. This allows, for example, collection of hydrocarbons from the lateral well bore. 
   Lateral tieback systems are well known. Various types are in use, including hanger type systems that allow a lateral liner to be mechanically tied back to the main casing at the window opening with the tieback means extending at least partially into the primary well bore, thus reducing the diameter of the main casing. Flush mount systems currently available place the liner in the main casing then “chop off” the portion of the liner that extends up into the main casing. 
   Still other systems available utilize some form of liner hanger device placed in the main casing to connect the liner in the lateral well bore to the primary well bore. Some examples of lateral tieback systems are detailed in U.S. Pat. Nos. 5,944,108, 5,477,925, and 6,079,488, and those patents are incorporated herein by reference in their entirety. The “hook” liner hanger systems of the first two aforementioned patents utilize a pair of longitudinal lateral extensions (hooks) along the outside of a liner. The liner is inserted into a lateral well bore through a window formed in the main well bore casing until the hooks locate on the bottom edge of the window. The liner is then set in place to connect the lateral and primary well bores. However, in each of these systems, the liner extends significantly into the primary well bore and significantly restricts the internal diameter of the main casing. 
   Some hanger type systems do not adequately support external loads on the tieback liner, especially loads applied perpendicular to the liner, and do not prevent the liner from being pushed back into the main well bore casing. 
   There are other problems with currently available tieback systems. Systems that sever a section of the liner extending into the primary well bore require a milling process which is time consuming and expensive, always carries the risk of loss of the entire well bore during the installation process, and reduces the capacity to hold formation load. Existing liner hanger systems that use a permanent orientation device mounted in the main well bore to orient the liner window to the main casing take up space and may significantly reduce the internal diameters of both the lateral well bore liner as well as the main casing. 
   There is a need, therefore, for a tieback apparatus and method to complete a multilateral junction that will overcome the shortcomings of the prior art devices. There is a further need for a tieback apparatus that can be installed in new well bores that does not restrict the internal diameter of the primary well bore. 
   There is a further need, therefore, for a tieback system that more effectively facilitates the placement and hanging of a liner in a lateral well bore. There is a further need for a tieback system that can be mechanically oriented. There is yet a further need for a tieback system that can be rotationally and longitudinally located in a primary well bore using a key slot as a guide. There is yet a further need for a tieback system that can be placed in a well bore while minimizing the obstructions in the liner or the primary well bore casing after installation. 
   There is yet a further need for a tieback system that can maintain the position of the liner with respect to the main well bore casing as well as a need for a system that can support external loads applied to the liner. 
   There is yet a further need for a tieback system that can be cemented in a well bore and allows full casing access through the junction without restriction and which does not require any downhole milling of the liner with the accompanying generation of steel cuttings which can cause numerous problems like the sticking of drilling and completion tools. 
   BRIEF SUMMARY OF THE INVENTION 
   The present invention provides an apparatus and method to complete a lateral well bore. The invention provides the ability to locate the lateral well bore and connect it with the primary well bore using a tieback liner. Once the tieback liner is installed, the invention provides for the cementing of the junction. In addition, the invention does not restrict the internal diameters of the tieback liner or the primary well bore and permits full access to both the lateral and primary well bores below the junction. The liner maintains full bore access while supporting external loads applied to the liner from the surrounding formation. 
   In a preferred embodiment, the invention includes a primary well bore insert that includes a key slot for rotational orientation of the installation of a tieback liner, a lateral window for drilling and accessing the lateral well bore, a coupling stock having an inner diameter greater than the inner diameter of the main casing, and a guide rail. The tieback liner includes a snap sleeve which extends into the coupling stock to connect with the guide rail while providing full bore access in the primary well bore casing. The snap sleeve/guide rail connection prevents the tieback liner from rotating, tilting, or being pushed into the primary well bore insert and supports external loads applied to the liner. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIG. 1  is a cross sectional view of a portion of a primary well bore where a future lateral well bore is desired. 
       FIG. 2  is a side view of a primary well bore insert. 
       FIG. 3  is a sectional view of the insert taken along line A-A′ of  FIG. 2   
       FIG. 4  is an enlarged sectional view of a coupling stock taken along line B-B′ of FIG.  2 . 
       FIG. 5  is a cross sectional view of a properly installed primary well bore insert after the lateral well bore has been drilled. 
       FIG. 6  is a side view of a tieback liner for connecting the lateral well bore to the primary well bore. 
       FIG. 6A  is an elevational view of a snap sleeve in its expanded state and a guide rail. 
       FIG. 6B  is an elevational view of the expanded snap sleeve engaged with the guide rail. 
       FIG. 7  is an enlarged sectional view of a snap sleeve taken along C-C′ of FIG.  6 . 
       FIG. 8  is a side view of the tieback liner after deployment into a primary well bore casing above the primary well bore insert. 
       FIG. 9  is an enlarged cross sectional view taken along line D-D′ of FIG.  8 . 
       FIG. 10  is a side view of a running assembly and the tieback liner after the tieback liner has been rotationally aligned with respect to the lateral well bore. 
       FIG. 11  is a side view of the running assembly and tieback liner lowered until a no-go device prevents farther downhole movement. 
       FIG. 12  is a side view of the running assembly and tieback liner after being raised a short distance. 
       FIG. 13  is an enlarged cross sectional view taken along line E-E′ of  FIG. 12  showing the snap sleeve in its expanded state. 
       FIG. 14  is a side view of the snap sleeve installed onto a guide rail. 
       FIG. 15  is a side view of the running assembly being removed. 
       FIG. 16  is a side view of the connected tieback liner and primary well bore insert. 
       FIG. 17  is an enlarged sectional view of the connected tieback liner and primary well bore insert taken along line F-F′. 
   

   DETAILED DESCRIPTION OF THE INVENTION 
     FIG. 1  is a cross sectional view of a portion of a primary well bore  100  where a future lateral well bore  170  is desired. 
     FIG. 2  is a side view of a primary well bore insert  14 for deployment into the primary well bore  100 . The insert  104  comprises an upper section of casing  115 , a lower section of casing  120 , and a coupling stock  125  interposed between the upper and lower sections of casing  115 ,  120 . The coupling stock  125  is attached to the upper casing  115  and lower casing  120 . This can be accomplished via threaded connections (not shown). Once the threaded connections are made, the coupling stock  125  is welded (or otherwise solidly fastened) to the upper and lower casing sections  115 ,  120  so that the three components will stay in the same position relative to each other when the primary well bore insert  104  is deployed in the well bore  100 . 
   The primary well bore insert  104  further includes a window  135  that will allow access to the lateral well bore  170  when the insert  104  is placed in the correct position in the primary well bore  100 . The window  135  may be formed entirely in the coupling stock  125 , as shown, or in the coupling stock  125  and lower casing section  120 . A key slot  145  is located above the window  135 . The key slot  145  may be formed in the coupling stock  125  and/or upper casing section  115 . The window  135  and key slot  145  are machined in the insert  104  prior to deployment into the primary well bore  100 . 
     FIG. 3  is a sectional view of the insert taken along line A-A′ of FIG.  2 . Except for the portion including a guide rail  150  (as shown in FIG.  4 ), the coupling stock  125  has an internal diameter  140  that is larger than the internal diameters  144  of the upper casing  115  and lower casing  120 . The guide rail  150  extends vertically along the inside of the coupling stock  125  and is located directly across from the window  135 . 
     FIG. 4  is an enlarged sectional view of the coupling stock  125  taken along line B-B′ of FIG.  2 . The inner diameter  140  of the coupling stock  125  is constant except where the guide rail  150  is located. The guide rail  150  has an inner diameter  155  (measured as though the guide rail  150  extended around the entire inner circumference of the coupling stock  125 ) approximately equal to the inner diameters  144  of the upper and lower casing sections  115 ,  120 . As a result, the guide rail  150  does not restrict full bore access when compared to the upper and lower casing sections  115 ,  120 . 
   To use the current invention, prior to deploying the insert  104  downhole, a window cap (not shown) is connected to the outside of the coupling stock  125  to cover and seal the window  135 . The cap has a semi-circular cross section with the curvature of its inside surface approximating that of the outside diameter of the coupling stock  125 . The cap also has a length sufficient to cover the entire window  135  and is made of an easily drillable material such as aluminum. The cap is connected to the coupling stock  125  either above or below the window  135  by any mechanical connection that will hold the sleeve in position. Examples include set screws, welding, or brazing. Once in place, the window cap covers the entire window  135  in order to prevent materials, such as cement, from passing through the window  135 . The cap has a sealing surface on the inside surface where it contacts the coupling stock  125  around the window  135 . This provides pressure integrity to the casing string. 
   Next, the desired position of a lateral well bore  170  must be determined. The insert  104  is then run into the primary well bore  100  and, using a downhole survey device (such as a steering tool, surface reading gyroscope, or measurement-while-drilling tool), it is positioned such that the window  135  is properly oriented, both axially and longitudinally, with respect to where the lateral wellbore  170  is desired. The primary well bore casing is cemented. The lateral well bore  170  is then drilled from the main well bore  100  through the window  135  of the insert  104  and through the portion of the window cap covering the window  135 . This may be accomplished through the use of a whipstock. The cuttings generated by drilling through the window cap do not cause the same problems associated with milling the steel main casing or tieback liners of prior art systems because the cap is made from a relatively soft material. 
     FIG. 5  is a cross sectional view of a properly installed primary well bore insert  104  after the lateral well bore  170  has been drilled. Note that the key slot  145  is positioned above the lateral well bore  170 . 
     FIG. 6  is a side view of a tieback liner  175  for connecting the lateral well bore  170  to the primary well bore  100 . The tieback liner  175  includes a bent joint  177  attached to a liner  178 , a tieback junction  182 , a swivel  179  interposed between the liner  178  and tieback junction  182 , and a snap sleeve  183  attached to the end of the tieback junction  182  that is opposite the swivel  179 . The swivel  179  allows the bent joint  177  to rotate independently of the tieback junction  182  to facilitate insertion of the bent joint  177  into the lateral well bore  170 . In a preferred embodiment, the swivel  179  is a tension swivel that only rotates under a minimum threshold of tension. This allows the liner  178  and bent joint  177  to rotate independently of the tieback junction  182  when upward force is applied to the junction  182 . Otherwise, the tension swivel does not rotate and the liner  178  and bent joint  17  in unison with the tieback junction  182 . The bent joint  177  is a curved section of tubing designed to be pointed in the direction of the window  135  of the primary well bore insert  104  to facilitate the movement of the tieback junction  182  into the lateral well bore  170  from the primary well bore  100 . 
   The tieback junction  182  includes an opening  185  that is positioned at the window  135  of the primary well bore insert  104  upon installation of the tieback junction  182 . The opening  185  is formed at an angle such that it aligns the tieback junction  182  with the window  135  of the insert  104  but does not allow any portion of the tieback junction  182  to extend into and obstruct the internal diameter of the insert  104 . 
     FIG. 6A  is an elevational view of the snap sleeve  183  in its expanded state (as detailed below) and the guide rail  150 . The guide rail  150  is located within the coupling stock  125  of the insert  104 , as shown in FIG.  3 . The snap sleeve  183  includes mounting surface  186  with a configuration that corresponds to the mounting surface  126  of the guide rail  150 . The snap sleeve  183  also includes slots  189  used to attach it to a running assembly  200  (not shown) and an opening  187  that corresponds to a top portion of the opening  185  in the tieback junction  182 . The opening  187  is shaped such that it allows full bore access to the tieback junction  182 . 
     FIG. 6B  is an elevational view of the expanded snap sleeve  183  engaged with the guide rail  150 . The corresponding configuration of the mounting surfaces  186 ,  126  provides a flush connection between the snap sleeve  183  and guide rail  150 , which in turn provides an effective connection between the tieback liner  175  and primary well bore insert  104 . This connection prevents the snap sleeve  183  (and the tieback junction  182  attached thereto) from rotating or tilting with respect to the primary well bore insert  104 . It also prevents the snap sleeve  183  from being pushed farther into the insert  104 , which maintains full bore access in the primary well bore. 
     FIG. 7  is an enlarged sectional view of the snap sleeve  183  taken along C-C′ of FIG.  6 . The snap sleeve  183  also has an inner diameter  142  and outer diameter  143 . In its original state and prior to being deployed downhole, the snap sleeve&#39;s  183  inner and outer diameters  142 ,  143  are approximately equal to those of the primary well bore casing  188  (not shown). In a preferred embodiment, the snap sleeve  183  is manufactured from the same type of tubing as the primary well bore casing  188 . In this original uncompressed state, the snap sleeve  183  cannot fit into the primary well bore casing  188 . However, an opening  153  in the snap sleeve  183  makes it a partial ring, which allows the sleeve  183  to be compressed to a smaller diameter in order to fit into the primary well bore casing  188  for being deployed downhole. The opening  153  also allows the snap sleeve  183  to later be expanded to a larger diameter. 
     FIGS. 8-17  illustrate a preferred method for installing the tieback liner  175  into the primary well bore insert  104  after the insert  104  has been installed downhole and the lateral well bore has been drilled (as shown in FIG.  5 ). 
     FIG. 8  is a side view of the tieback liner  175  during deployment into the primary well bore casing  188  above the primary well bore insert  104  (not shown). The running assembly  200  is used to carry the tieback liner  175  downward into the casing  188 . The running assembly  200  includes an orienting keysub  205 , hydraulically activated sleeve  215  (see FIG.  9 ), holding sleeve  220 , a spring loaded no-go device  225 , and tubing  210  interposed between the surface and keysub  205 , between the keysub  205  and sleeves  215 ,  220 , and between the sleeves  215 ,  220  and no-go device  225 . 
   The orienting keysub  205  includes a spring loaded key  207 . As shown, the key  207  is compressed by the casing  188 , with at least a portion of the key  207  being recessed in a housing formed in the keysub  205 . The key  207  is spring loaded to prevent interference between the key  207  and the wall of the casing  188  as the running assembly  200  is deployed. 
   The no-go device  225  includes an obstruction  226  that is spring loaded and remains at least partially recessed in a housing formed by the tieback liner  175  until exposed by the tieback liner  175  moving into the lateral well bore  170 . In another embodiment, a simple mechanical linkage runs between the key  207  and the no-go device  225  whereby the no-go device  225  is released only upon engagement of the key  207  in the key slot  145 . In yet another embodiment, the no-go device can utilize a fixed obstruction rather than being spring loaded. As shown, the no-go device  225  is in its compressed state. 
   The tieback liner  175  is held by the running assembly  200 , in part, by connecting the snap sleeve  183  to the holding sleeve  220 , as explained below. 
     FIG. 9  is an enlarged cross sectional view taken along line D-D′ of FIG.  8 . The snap sleeve  183  is connected to the holding sleeve  220  prior to deploying the running assembly  200  downhole. This is accomplished by compressing the snap sleeve  183  and placing it onto the holding sleeve  220 , as described below. The holding sleeve  220  includes slots  235  that correspond to the slots  189  (see  FIG. 8 ) in the snap sleeve  183 . The snap sleeve  183  and holding sleeve  220  are then positioned such that their respective slots  189 ,  235  are in alignment. Pins  236  are then placed through the slots  189 ,  235  to connect the snap sleeve  183  to the holding sleeve  220 , which in turn connect the tieback liner  175  to the running assembly  200 . The pins  236  also maintain the snap sleeve  183  in its compressed state, which also allows the snap sleeve  183  to fit within the primary well bore casing  188 . 
   The running assembly  200  also includes expansion lugs  230  that extend from the inside of the hydraulically activated sleeve  215 , through the hydraulic sleeve  215  and holding sleeve  220 , to the inner surface of the snap sleeve  183 . 
     FIG. 10  is a side view of the running assembly  200  and tieback liner  175  after the tieback liner  175  has been rotationally aligned with respect to the lateral well bore  170 . This is accomplished by lowering the running assembly  200  and tieback liner  175  in the primary well bore casing. If a tension swivel  179  is used, the swivel  179  is not under sufficient tension to rotate during this step, which allows the liner  178  and bent joint  177  (not shown) to rotate in unison with the running assembly. This in turn facilitates the rotational positioning of the bent joint  177  for feeding into the lateral well bore  170 . The bent joint  177  and liner  178  are fed into the lateral well bore  170  through the window  135  in the insert  104  until the depth of the keysub  205  is a short distance above the depth of the key slot  145  formed in the insert. The depth of the key slot  145  may be determined by the length of main well bore casing  188  deployed downhole. The depth of the keysub may be determined by the length of pipe deployed with the running assembly  200  or by a wireline tool that measures the length of main well bore casing  188  through which the running assembly  200  has traveled. The running assembly is then slowly lowered and rotated until an increase in torque resistance is detected. This signifies that that the spring loaded key  207  has extended into the key slot  145  and, as a result, that the tieback liner  175  is rotationally oriented with respect to the window  135  leading to the lateral well bore  170 . 
   The running assembly  200  is then lowered so that the tieback junction  182  is fed into the lateral well bore  170  through the window  135 . The obstruction  226  of the spring loaded no-go device  225  is now extended by operation of its spring since it is no longer being held in its compressed state by the upper casing  115  or coupling stock  125 . The running assembly  200  is lowered even farther until the obstruction  226  hits a lower edge  240  of the window  135 , as shown in FIG.  11 . The obstruction  226  prevents farther downhole movement of the assembly  200  and signifies that the tieback liner  175  is longitudinally oriented with respect to the window  135 . The running assembly  200  is then lifted up a predetermined distance, preferably about 2 meters, as shown in  FIG. 12 , so that the snap sleeve  183  can be expanded. 
     FIG. 13  is an enlarged cross sectional view taken along line E-E′ of  FIG. 12  showing the snap sleeve  183  in its expanded state. This is accomplished by applying hydraulic pressure within the tubing  210  sufficient to force the expansion lugs  230  outward. The lugs  230  push against the inner surface of the snap sleeve  183  causing it to expand. Hydraulic pressure is applied until the snap sleeve  183  is fully expanded against the inner surface of the coupling stock  125 . 
   The assembly  200  is then pushed downward until the expanded snap sleeve  183  interlocks with the guide rail  150 , as shown in  FIG. 14  (see also FIGS.  6 A and  6 B). The mounting surfaces  126  of the guide rail  150  correspond to the mounting surfaces  186  of the snap sleeve  183 , thus locking the tieback liner  175  into a position that orients it towards the window  135  and into the lateral well bore  170  (not shown). Cement is then applied in the annulus outside the insert  104  and tieback liner  175  (not shown). For example, cement can be pumped through the running assembly  200  tubing  210  to the lower end of the liner  178 , or through special subs, called port collars, inserted in the liner  178  for this purpose, where it is circulated back up in the annulus between the bore hole and liner  178  and eventually to the annulus surrounding the junction between the tieback liner  175  and insert  104 . In a preferred embodiment, the cemented junction forms a Level 4 junction under the Technology Advancement Multi Lateral (“TAML”) organization&#39;s classification system, which ranges from Level 1 to Level 6. 
   After cementing is completed, additional downward force is applied to the running assembly to shear the pins  236  that hold the tieback liner  175  to the running assembly  200 , thus releasing the tieback liner  175  from the running assembly  200 . 
     FIG. 15  is a side view of the running assembly  200  being removed. The running assembly is removed after the tieback liner  175  has been released. The released tieback liner  175  remains downhole, thus connecting the lateral well bore  170  to the primary well bore  100 . 
     FIG. 16  is a side view of the connected tieback liner  175  and primary well bore insert  104 . The primary well bore  100  is connected to the lateral well bore  170 , and the running assembly  200  has been removed so that there are no obstructions in the primary or lateral well bore  100 ,  170 . 
     FIG. 17  is an enlarged sectional view of the connected tieback liner  175  and primary well bore insert  104  taken along line F-F′. The expanded snap sleeve  183  and guide rail  150  have an inner diameter  245  equal to the inner diameter  144  of the upper and lower casing sections  115 ,  120  (not shown). Thus, once the snap sleeve  183  is in place, it allows full bore access of the primary well bore  100  because the snap sleeve  183  and guide rail  150  do not obstruct the normal interior diameter  144  of the primary well bore casings  115 ,  120 . Also, the connection between the snap sleeve  183  and guide rail  150  extends along the inside circumference of the coupling stock  125 , which prevents the tieback liner  175  from rotating or tilting with respect to the primary well bore. The connection also prevents the tieback junction  182  from being pushed into the insert  104 . 
   Several benefits are achieved by this invention. The invention provides a mechanism and method to mechanically orient a tieback liner with respect a lateral well bore. Once oriented, the invention provides a connection between the lateral well bore and primary well bore that does not restrict full bore access in the primary well bore or lateral well bore casings. This is accomplished in part by utilizing a coupling stock  125  having an inner diameter  140  greater than the inner diameter  144  of the primary well bore casing, which creates space for a connecting mechanism (snap sleeve  183  and guide rail  150 ) that does not decrease the inner diameter of the primary well bore casing. Full bore access is further maintained by not extending any portion of the tieback junction  182  into the primary well bore  100 . This invention further allows the junction between the main casing and this tieback liner  175  to be cemented into place. The invention avoids hanging the weight of the tieback liner  175  on the window  135  of the primary well bore casing, and also provides a connection that prevents the tieback liner  175  from rotating or tilting with respect to the primary well bore casing  188 . The connection also prevents the tieback junction  182  from being pushed into the primary well bore casing. This type of connection also allows the invention to support external loads on the tieback liner  175 . All of these benefits are accomplished without any downhole milling during the setting of the tieback liner  175 , which generates steel cuttings, or the use of a permanent orientation device, which reduces the inner diameter of the casing.