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FIELD OF THE INVENTION  
       [0001]     This invention generally relates to hydrocarbon well completion, recompletion and workover and, in particular, to a casing transition nipple and method of casing a well to facilitate well completion, re-completion and workover.  
       BACKGROUND OF THE INVENTION  
       [0002]     Most oil and gas wells require some form of stimulation to enhance hydrocarbon flow to make or keep them economically viable. The servicing of oil and gas wells to stimulate production requires the pumping of fluids under high pressure. The fluids may be caustic and are frequently abrasive because they are laden with abrasive propants such as sharp sand, bauxite or ceramic granules.  
         [0003]     It is well know that advances in coil tubing technology have generated an increased interest in using coil tubing during well completion, re-completion and workover procedures. Techniques have been developed over the years for pumping well fracturing fluids through coil tubing, or pumping “down the backside” around the coil tubing. Processes and equipment have also been developed for perforating casing and fracturing a production zone in a single operation, as described in Applicant&#39;s U.S. Pat. No. 6,491,098 entitled Method and Apparatus for Perforating and Stimulating Oil Wells, which issued on Dec. 10, 2002.  
         [0004]     Although performing two or more functions in a single run down a cased wellbore is economical and desirable, there is a disadvantage with using existing techniques for performing such operations. The principal disadvantage is the height of the equipment stack that is necessary for lubricating the required tool string into the well.  
         [0005]      FIG. 1  is a schematic diagram of a setup  10  for performing a well completion in accordance with the prior art techniques in which a long tool string (not shown), e.g. a tool string for perforating and stimulating production zones of the well in a single run, are lubricated into the cased well bore.  
         [0006]     As schematically illustrated in  FIG. 1 , a wellhead generally indicated by reference numeral  12  includes a casing head  14  supported by a conductor  16 . The casing head  14  supports a surface casing  18 . A tubing head spool  20  is mounted to the casing head  14 . The tubing head spool  20  supports a production casing  22 , which extends downwardly through the production zone(s) of the well.  
         [0007]     Mounted to a top of the tubing head spool  20  is a blowout preventer (BOP)  24  for controlling the well after the production casing  22  is perforated. Optionally mounted to a top of the BOP is a “frac cross”  26 , also referred to as a fracturing head. The purpose of the frac cross  26  is to permit well stimulation fluids to be pumped down the backside, i.e. down production casing  22 , and around a coil tubing  34 .  
         [0008]     Mounted to a top of the frac cross  26  is one or more “lubricator joints”  28 . In this example three lubricator joints  28   a ,  28   b  and  28   c  are used. The lubricator joints house the downhole tool string (not shown), which is supported by the coil tubing string  34 , or a wire line (not shown). A coil tubing BOP  30  or a wire line BOP (not shown) is mounted to a top of the lubricator joints. Tubing rams of the coil tubing BOP seal around the coil tubing string  34  while the tool string is being run into and out of the well. Likewise, wire line rams of a wire line BOP seal around a wire line as it is being run into or out of the well. A coil tubing injector  32  is mounted to a top of the coil tubing BOP  30 . The coil tubing injector  32  is used to run the coil tubing string  34  into and out of the production casing  22  in a manner well known in the art. The coil tubing string  34  is supplied from a coil tubing spool  36 , which is likewise well known in the art and may be mounted on a trailer or a truck.  
         [0009]     As is apparent, the setup  10  shown in  FIG. 1  creates an equipment stack that extends  20 ′- 40 ′ from the ground. The setup  10  is in a normally assembled on the ground and place after its is assembled. For the sake of clarity, the stays, work platforms, cranes and other equipment required to assemble, disassemble, operate, and maintain the setup  10  are not shown.  
         [0010]     As will be understood by those skilled in the art, assembling and operating the setup  10  can be dangerous, because maintenance work must be performed on elevated work platforms high off the ground. As will be further understood, the setup  10  can also be dangerous because a great deal of mechanical bending and twisting stress is placed on the wellhead  12  and the lubricator  28  by the very high setup  10 , which acts as a lever when force is applied to a top of the set up  10  by operation of the coil tubing injector or  32  or the wire line unit (not shown).  
         [0011]     As will also be appreciated by those skilled in the art, assembling the setup  10  is expensive because heavy hoisting equipment, such as an 80-ton crane, is required to hoist the equipment to those heights. The 80-ton crane must also be connected to a top of the set up  10  and used to counter force applied to the setup  10  by operation of the coil tubing injector  32  or the wire line unit. The 80-ton crane must therefore remain on the job during the entire well stimulation process. The rental of such hoisting equipment for an extended period of time is very expensive.  
         [0012]     There is therefore a need for a way of facilitating well completion, re-completion and workover while preserving the time and cost savings of being able to perform more than one function during a single run into a cased wellbore.  
       SUMMARY OF THE INVENTION  
       [0013]     It is therefore an object of the invention to provide a way of facilitating and improving the safety of well completion, re-completion and workover while preserving the time and cost savings of being able to perform more than one function during a single run into a cased wellbore.  
         [0014]     The invention therefore provides a casing transition nipple, comprising: a tubular body having a top end adapted for fluid tight connection to a well casing of a fist diameter and a bottom end adapted for fluid tight connection to a well casing of a second, smaller diameter; and a smooth annular tool guide surface between the first and second ends, the tool guide surface sloping downwardly with respect to the top end.  
         [0015]     The invention further provides a method of casing a wellbore, comprising: running a production casing of a first diameter into the wellbore until a bottom end of the production casing of the first diameter is approximately a predetermined distance from a bottom of the wellbore; connecting a bottom end of a casing transition nipple to a top end of the production casing of the first diameter; connecting a bottom end of a production casing of a second, larger diameter to a top end of the casing transition nipple, the production casing of the second diameter having a length approximately equal to the predetermined distance; and suspending the production casing of the second, larger diameter from a wellhead of the well.  
         [0016]     The invention yet further provides a method of casing a wellbore of a predetermined depth, comprising: running a production casing of a first diameter into the wellbore to a depth less than the predetermined depth of the wellbore; connecting a bottom end of a casing transition nipple to a top end of the production casing of the first diameter; connecting a bottom end of a production casing of a second, larger diameter to a top end of the casing transition nipple; and running the production casing of the second, larger diameter into the wellbore until the wellbore is cased. 
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0017]     Having thus generally described the nature of the invention, reference will now be made to the accompanying drawings, in which:  
         [0018]      FIG. 1  is a schematic diagram of a prior art setup for running a long downhole tool string into a production casing of a well in order to perform more than on function in a single run into the well;  
         [0019]      FIG. 2  is a schematic diagram of a well cased in accordance with an embodiment of the invention;  
         [0020]      FIG. 3  is a schematic diagram of a well cased in accordance with another embodiment of the invention;  
         [0021]      FIG. 4  is a schematic diagram of a well cased in accordance with yet another embodiment of the invention;  
         [0022]      FIG. 5  is a schematic diagram of a well cased in accordance with yet a further embodiment of the invention;  
         [0023]      FIG. 6  is a cross-sectional schematic diagram of the casing transition nipple shown in  FIG. 2 ;  
         [0024]      FIG. 7  is a cross sectional schematic diagram of the casing transition nipple shown in  FIG. 3 ;  
         [0025]      FIG. 8  is a cross-sectional schematic diagram of the casing transition nipple shown in  FIG. 4 ;  
         [0026]      FIG. 9  is a cross-sectional schematic diagram of the casing transition nipple shown in the  FIG. 5 ;  
         [0027]      FIG. 10  is a schematic diagram of a set up for lubricating a long downhole tool string into a well cased in accordance with the invention;  
         [0028]      FIG. 11  is a schematic diagram of the set up shown in  FIG. 10 , illustrating the long downhole tool string in a “lubricated-in” condition; and  
         [0029]      FIG. 12  is a schematic diagram of a setup in accordance with another embodiment of the invention illustrating the long downhole tool string in a lubricated in condition, the setup being configured to run the long downhole tool string into the well using a wire line unit. 
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS  
       [0030]     The invention provides a casing transition nipple and a method of casing a well in order to facilitate well competition, re-completion and workover. In accordance with the invention, the casing transition nipple is used to interconnect a bottom end of at least one casing joint of a first diameter having a top end connected to the wellhead and a top end of a production casing of a second, smaller diameter that communicates with production zones of the well. A well cased in accordance with the invention facilitates many well completion, recompletion and workover procedures. For example, the well cased in accordance with the invention facilitates the process of lubricating long downhole tool strings into the well and significantly reduces a distance that a coil tubing injector or a wire line unit is above the ground after the tool string has been lubricated into the well. This significantly reduces expense and improves safety by lowering working height and significantly reducing strain on the wellhead.  
         [0031]      FIG. 2  is a schematic diagram partially in cross-section showing a well cased in accordance with the invention. As schematically shown in  FIG. 2 , the surface casing  18  is supported by a casing mandrel or casing slips  46  landed in a casing bowl, in a manner well known in the art. If the casing  18  is supported by casing slips, a top of the casing is cut off after the slips are set.  
         [0032]     A casing transition nipple  40   a  connects an upper section of production casing  42  to a lower section of production casing  44 . The upper section of production casing  42  has a larger diameter than the lower section of production casing  44 . For example, the upper section of production casing  42  may have a diameter of 6-8 inches. The lower section of production casing  44  is of a standard casing size, e.g. 4½, 5 or 5½ inches. A lower section of the production casing extends from the casing transition nipple  40   a  to the bottom of the well.  
         [0033]     In one embodiment of the invention the upper section of production casing  42  has a length of 6-60 feet. It may be, for example, one joint of casing, which is typically 30 feet in length. However, the upper section of production casing  42  may be shorter or longer than 30 feet, depending on anticipated need.  
         [0034]     In this embodiment, the casing transition nipple  48  is box threaded on each end as will be explained below in more detail with reference to  FIG. 6 .  
         [0035]      FIG. 3  is a schematic diagram partially in cross-section showing a well cased in accordance with another embodiment of the invention. The upper section of production casing  42  and the lower section of production casing  44  are identical to that described above with reference to  FIG. 2 . In this embodiment, a casing transition nipple  40   b  has a box end for connection to the upper section of production casing  42  and a nipple end for connection to the lower section of production casing  44 . Consequently, a casing collar  50 , commonly known in the art for connecting joints of casing, is used to connect the nipple end of the casing transition nipple  40   b  to the lower section of the production casing  44 . This will be explained below in more detail with reference to  FIG. 7 .  
         [0036]      FIG. 4  is a schematic diagram partially in cross-section showing a well cased in accordance with yet a further embodiment of the invention. The upper section of the production casing  42  and the lower section of the production casing  44  are the same as that described above with reference to  FIG. 2 . In this embodiment, the casing transition nipple  40   c  is pin threaded for connection to the upper section of the production casing  42  and box threaded for connection to the lower section of the production casing  44 . Consequently, a casing collar  52  is used to connect the upper section of the production casing  42  to the transition nipple  40   c , as will be explained below in more detail with reference to  FIG. 8 .  
         [0037]      FIG. 5  is a schematic diagram partially in cross-section showing a well cased in accordance with yet another embodiment of the invention. The upper section of the production casing for  42  and the lower section of the production casing  44  are the same as that described above with reference to  FIG. 2 . In this embodiment, the casing transition nipple  40   c  is pin threaded for connection to the upper section of the production casing  42  and pin threaded for the connection of the lower section of the production casing  44 . Consequently, a casing collar  52  is used to connect the upper section of the production casing  42  to the casing transition nipple  40   d , and a casing collar  50  is used to connect the lower section of the production casing  44  to the casing transition nipple  40   d , as will be explained below in more detail with reference to  FIG. 9 .  
         [0038]      FIG. 6  is a cross-sectional schematic view of the casing transition nipple  40   a  shown in  FIG. 2 . The casing transition nipple  40   a  has a top end  60   a  for connection to the upper section of the production casing  42 . The casing transition nipple  40   a  also has a bottom end  62   a  for connection of the lower section of the production casing  44 . The casing transition nipple  40   a  further includes a smooth, annular downwardly inclined tool guide surface  68   a . As illustrated, in one embodiment the tool guide surface  68   a  is downwardly inclined at an angle of about 30°-60° from a plane that is perpendicular to the top end  60   a  and the bottom and  62   a  of the casing transition nipple  40   a.    
         [0039]     The upper end  60   a  has a box thread  64   a , which engages a pin threaded end of the upper section of the production casing  42 . The box thread  64   a  is shown schematically. As is understood by those skilled in the art, casing is available in a plurality of thread patterns. For example, casing may be threaded using a Buttress, Hydril, Acme, Rucker Atlas, EUE 8-round, EUE 10-round, EUE 8-V or EUE 10-V thread pattern, and this list is not exhaustive. It should therefore be understood that the thread pattern used to machine threads on any of the box threaded or pin threaded ends described above and below is purely a matter of design choice, and the schematically illustrated threads shown in  FIGS. 6-9  are intended to be representative of any thread pattern applied to casing, as well as any other method that may be used for connecting the casing  40 ,  42  to the casing transition nipple  40   a - d . The bottom end  62   a  likewise includes a box thread  66   a  for direct connection of a pin threaded top end of the lower section of the production casing  44 .  
         [0040]      FIG. 7  is a cross-sectional schematic diagram of the casing transition nipple  40   b  shown in  FIG. 3 . The casing transition nipple  40   b  is identical to the casing transition nipple  40   a  described above with reference to  FIG. 6  with the exception that the bottom end  62   b  is pin threaded. As explained above with reference to  FIG. 3 , a casing collar  50  is used to connect the lower section of production casing  44  to the pin thread  70   b  of the casing transition nipple  40   b.    
         [0041]      FIG. 8  is a schematic cross-sectional view of a casing transition nipple  40   c  described above with reference to  FIG. 4 . The casing transition nipple  40   c  is the same as the casing transition nipple  40   a  described above, with the exception that the top end  60   c  is pin threaded and the bottom end  62   c  is box threaded. Consequently, a casing collar  52  is used to connect the production casing  42  to the top end  60   c  of the casing transition nipple  40   c . As explained above, the lower section of production casing  44  is connected directly to the box thread  66   c  of the casing. transition nipple  40   c.    
         [0042]      FIG. 9  is a schematic cross-sectional view of the casing transition nipple  40   d  described above with reference to  FIG. 5 . The casing transition nipple  40   d  is the same as the casing transition nipple  40   a  described above with reference to  FIG. 6  with the exception that the top end  60   d  is pin threaded and the bottom end  62   d  is also pin threaded. Consequently, as described above with reference to  FIG. 5 a  casing collar  52  is used to connect the upper section of production casing  42  to the pin thread  72   d  of the top end  60   d . Likewise, a casing collar  50  is used to connect the lower section of production casing  44  to the pin thread  70   d  of the bottom end  62   d  of the casing transition nipple  40   d.    
         [0043]     As will be understood by those skilled in the art, any of the above the threaded connections may be made permanent using a thread glue such as Baker Lock®. Furthermore, any of the above connections may be welded connections, glued connections, or connections made using any one of a number of fluid tight quick-lock, screw-lock or other locking connectors that are known in the art.  
         [0044]      FIG. 10  is a schematic view partially in cross-section of a setup  100  for running a long downhole tool string  102  into a wellbore cased in accordance with the invention. As used in this document, a “long downhole tool string  102 ” means any one or more of a perforating gun; jetting tool; packer; plug; a selective acidizing and/or fracturing tool; a casing or tubing cutter; a fishing tool; a pulling tool; a grapple; etc. in any combination.  
         [0045]     The setup  100  is very similar to the setup  10  described above with reference to  FIG. 1 , with the exception that the lubricator  28   a - c  is replaced by a subsurface lubricator  104  that is schematically illustrated. The subsurface lubricator  104  is not described because it is not within the scope of this invention. None of the control structure for the subsurface lubricator  104  is illustrated for the purposes of clarity. In this example, the subsurface lubricator  104  is mounted to a top of the frac cross  26 , which is in turn mounted to a top of a blowout preventer  24  as described above with reference to  FIG. 1 . As will be understood by those skilled in the art, prior to lubricating in the long downhole tool string  102  blind rams  106  of the blowout preventer  24  are closed to seal an annulus of the upper section of the production casing  42 . Due to a length of the downhole tool string  102 , a height of the set up  100  is 20′-40′, similar to the set up  10  shown in  FIG. 1 .  
         [0046]     The set up  100  is assembled on the ground in a manner to that described above with reference to  FIG. 1 . The set up  100  may be hoisted into position using, for example, a coil tubing unit crane, because as will be explained below with reference to  FIG. 11 , an 80-ton crane is not required to stabilize the setup  100  after it is “lubricated in”.  
         [0047]      FIG. 11  is a schematic diagram partially in cross-section of the setup  100  after it has been lubricated into the wellbore cased in accordance with the invention. As will be understood by those skilled in the art, the subsurface lubricator  104  has been lowered down through the blowout preventer protector  24  and the wellhead  14  and into the upper section of the production casing  42  to a locked-down condition in which a well completion, recompletion or workover procedure is ready to be performed. As can be seen, in the locked-down position a height of a top of the coil tubing injector  32  is about 15′-18′ above the ground, as opposed to about 40′ above the ground for the setup  10  shown in  FIG. 1 . The setup  100  reduces cost because a crane is not required to stabilize the setup  100  after it is lubricated in. The setup  100  also significantly improves a work safety and facilitates equipment maintenance because of the reduced working height. As will be understood by those skilled in the art, mechanical bending and twisting stresses on the wellhead  14  are also significantly reduced. This is not only due to the reduced working height of the setup  100 , but also due to the subsurface lubricator  104  which runs inside the upper section of the production casing  42  and thereby lends significant rigidity to the wellhead components through which it is run. Consequently, rather than mechanically stressing the wellhead, the setup  100  actually reinforces the wellhead and substantially eliminates any possibility that the wellhead could be damaged by the mechanical bending and twisting forces exerted by coil tubing or wireline units when long tool strings are lubricated into or out of the well.  
         [0048]      FIG. 12  is a schematic diagram partially in cross-section of another setup  110  in accordance with the invention, showing the long downhole tool string  102  in a lubricated in condition. The setup  110  is configured to lower the long downhole tool string  102  into the wellbore cased in accordance with the invention using a wireline unit  106 , which is schematically illustrated. As understood by those skilled in the art, a wireline  84  of the wireline unit  106  runs over a wireline sheave  88  and through a grease injector  82 . The grease lines, pumps and other components of the grease injector  82  are not shown. The wireline  84  runs through a wireline BOP  80  and the frac cross  26 . The wireline  84  is connected to a top of the long downhole tool string  102 . In this example, the wireline sheave  88  is supported by a sheave boom  86  mounted to a side of the subsurface lubricator  104 , so that a crane is not required to support the wireline sheave  88 . The setup  110  provides all of the advantages described above with reference to the setup  100 .  
         [0049]     A wellbore cased in accordance with the invention therefore improves work safety, enables downhole operations that were heretofore impossible, impractical or excessively dangerous, and reduces cost by lowering the overall working height after a long downhole tool string has been lubricated into the cased well.  
         [0050]     As will be understood by those skilled in the art, the above-noted dimensions of the upper section of production casing  42  and the casing transition nipple  40   a  are exemplary only. The dimensions of the upper section of the production casing  42 , a lower section of the production casing  44  and the casing transition nipple  40   a - d  are, within certain limits, a matter of design choice. It is only important that the upper section of production casing  42  has an internal diameter large enough to accept a subsurface lubricator that provides full-bore access to the lower section of production casing  44 . A difference in the two diameters of about 1½″-3½″ is generally sufficient. It is also important that a burst strength of a the upper section of production casing  42  be at least as high as a burst strength of the lower section of production casing  44 , or at least as high as anticipated well stimulation fluid pressures, plus a margin for safety.  
         [0051]     The embodiments of the invention described are therefore intended to be exemplary only, and the scope of the invention is intended to be limited solely by the scope of the appended claims.

Summary:
A casing transition nipple and method of casing a well facilitates well completion, re-completion and workover while increasing safety and reducing expense. The casing transition nipple provides a connection between a large diameter production casing joint suspended by a wellhead and a standard production casing string. The large diameter production casing joint permits long downhole tool strings to be lubricated into the well without leaving a high lubricator profile and reduces the cost of performing many other well completion, re-completion and workover procedures.