Abstract:
An apparatus for deflecting a tubular string preferably comprising at least one side nozzle near the lower end of a first tubular string. The nozzle permits passage of a fluid therethrough from the first tubular string bore and deflects the first tubular string in a substantially horizontal direction. A second tubular string may be lowered over the deflected first tubular string. The second tubular string and the first tubular string are preferably lowered into the sea floor for maintaining their deflection. A method for deflecting a first tubular string and securing the first tubular string in the deflected state preferably comprises lowering the first tubular string axially so that the lower end of the first tubular string is near the sea floor. Preferably, a fluid, such as seawater, is propelled down through the bore of the first tubular string and through at least one side nozzle near the lower end of the first tubular, wherein the fluid moving through the side nozzle deflects the first tubular string. The first tubular string end is preferably lowered into the sea floor for maintaining the deflection of the first tubular string. A second tubular string may then be slidably lowered over the first tubular string for deflecting the second tubular string.

Description:
RELATED APPLICATION 
       [0001]    This application relates to U.S. patent application Ser. No. ______ filed ______, for Conductor Pipe String Deflector and Method. 
     
    
     FIELD OF THE INVENTION 
       [0002]    This invention pertains to apparatus and method for the deflection of a tubular string which may be suspended from a drilling or service rig or platform. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0003]      FIG. 1  illustrates a side elevated view of the lower portion of an offshore installation utilizing the deflector apparatus according to the present invention; 
           [0004]      FIG. 2  illustrates a side elevated, diagrammatic view of a prior art system involving a selected portion of the installation of the embodiment illustrated in  FIG. 1  with a diver and winch line in use intending to be used to be used to laterally shift the upper portion of a separated tubular string; 
           [0005]      FIG. 3  illustrates a side elevated view of an alternative prior art system involving a whipstock that has been speared into an abandoned well pipe; 
           [0006]      FIG. 4  illustrates a cross-sectional elevated side view of a deflector sub according to the present invention; 
           [0007]      FIG. 5  illustrates an exploded, elevated perspective view of an alternative embodiment of a deflector sub according to the present invention; 
           [0008]      FIG. 6  illustrates a longitudinal, cross-sectional view of the embodiment illustrated in  FIG. 5  according to the present invention; 
           [0009]      FIG. 6A  illustrates an end plan view of the embodiment illustrated in  FIG. 6  according to the present invention; 
           [0010]      FIG. 6B  illustrates an enlarged, detail view, partly in cross section of the nozzle-receiving portion of the deflector sub body illustrated in  FIG. 6A  according to the present invention; 
           [0011]      FIG. 7  illustrates a side view, partially cut away, of an alternative embodiment of the deflector sub according to the present invention; 
           [0012]      FIG. 8  illustrates a side elevated, diagrammatic view of a tubular string deflected by a fluid jet according to the present invention; 
           [0013]      FIG. 9  illustrates a side elevated, diagrammatic view of the embodiment illustrated in  FIG. 8  further illustrating a second tubular being lowered over a deflected tubular string according to the present invention; 
           [0014]      FIG. 10  illustrates a side elevated, diagrammatic view of a pair of concentric tubulars being pushed into the seabed according to the present invention; 
           [0015]      FIG. 11  illustrates a side elevated view of the internal tubular string illustrated in  FIG. 10  having been removed according to the present invention; 
           [0016]      FIG. 12  illustrates a side elevated view of an alternative embodiment with the exterior tubular illustrated in  FIG. 10  being in place during the deflection process according to the present invention; 
           [0017]      FIG. 13  illustrates a side cut away, elevated view of a jet nozzle switching apparatus, with a piston in a first position, according to the present invention; 
           [0018]      FIG. 14  illustrates a side cut away, elevated view of an alternative embodiment with a drop ball in place, with a piston in a first position, according to the present invention; 
           [0019]      FIG. 15  illustrates a side cut away, elevated view of the embodiment illustrated in  FIG. 13  with the piston in a second position according to the present invention; 
           [0020]      FIG. 16  illustrates a side cut away, elevated view of the embodiment illustrated in  FIG. 15  with the drop ball expelled according to the present invention; 
           [0021]      FIG. 17  illustrates a side cut away, elevated view of the embodiment illustrated in  FIG. 16  further illustrating a removal tool according to the present invention; 
           [0022]      FIG. 18  illustrates a side cut away, elevated view of the embodiment illustrated in  FIG. 17  with the nozzle switching apparatus removed according to the present invention; 
           [0023]      FIG. 19  illustrates an elevated, pictorial view of a drive shoe according to the present invention; 
           [0024]      FIG. 20  is a partial, elevated view of an alternative embodiment of the invention in which a nozzle is used in the side wall of a conductor pipe, thereby allowing the conductor pipe to be directly deflected; and 
           [0025]      FIG. 21  is a graphic illustration showing the resulting deflection of a tubular which is opposite from the vector sum of the thrusts generated in accordance with the invention. 
       
    
    
     DETAILED DESCRIPTION OF EMBODIMENTS 
       [0026]    It should be understood that the description herein below may use the terms drill string, pipe string, or the more general term tubular or tubular string interchangeably without intention of limitation. It should be further understood that the device and method described herein can be applied to tubulars other than drill string, casing, or tubing. 
         [0027]      FIG. 1  illustrates the lower portion of a typical fixed offshore platform  1 . It is well known in the art that the platform structure stands in the seabed  13 , is preferably anchored in a conventional manner, and preferably has vertically distributed braces such as illustrated by braces  1   a - 1   d . It is further well known that the platform comprises a plurality of “slots” through which one or more wells can be drilled. Typically, guide sleeves  15  are mounted to the braces  1   a - 1   d  and are substantially vertically aligned with the “slots”. Typically, tubulars, used for drilling and production operations are lowered through the “slots” and the corresponding vertically aligned guide sleeves  15 . Such slots and guide sleeves are conventional and well known in this art. 
         [0028]    It is well known that due to size constraints of the platform  1 , the number of “slots” is limited. It is further known that if a wellbore, which corresponds to a particular “slot” and its vertically aligned guide sleeves  15  becomes unuseable, that “slot” also becomes unuseable unless the tubular string, which is to be lowered through the unuseable “slot” can be deflected, from a substantially vertical position, in order to position a new wellbore proximate the unuseable wellbore. It is still further well known, in the art, that a wellbore becomes unuseable for a variety of reasons, including but not limited to, stuck tubulars or tools, adverse borehole conditions, and the like. Typically, in an unuseable wellbore, the tubulars are cut off below the mudline and are abandoned for the purposes of the drilling and/or production operations. Typically, after the unuseable wellbore is abandoned, all tubulars are removed from the corresponding “slot” and its vertically aligned guide sleeves  15 . Therefore, the “slot” is only unuseable from the point of view of utilizing a substantially vertical tubular string. 
         [0029]    Still referring to  FIG. 1 , when a “slot” is to be recovered, a new tubular string  2  is lowered through the particular “slot” and must be deflected, in a substantially horizontal direction, to bypass the unuseable wellbore. According to the present apparatus, this deflection is preferably accomplished by utilizing a jet sub  3   b  as further described herein below. 
         [0030]      FIGS. 2 and 3  illustrate a pair of prior art systems for attempting the tubular string deflection necessary for the “slot” recovery.  FIG. 2  illustrates the use of a diver  4 B to secure a winch line or cable  4   a  to the platform  1  in an attempt to deflect a pipe  5  in a substantially horizontal direction. A pulley  4  is secured to the platform  1 . Line  4   a  hooks around the pipe  5  and pulley  4  and leads to the surface and a winch on the platform. However, this method for deflecting a pipe string presents several problems including the fact that underwater diving operations are inherently risky and weather conditions must be acceptable for divers to operate. Therefore, the procedure is often suspended during inclement weather conditions causing unpredictable delays to the offshore operations. 
         [0031]      FIG. 3  illustrates using a whipstock  6  which is typically speared into the top of an existing pipe EP that has been cut off below the mud line. The whipstock wedge surface or trough  6   b  serves to guide and deflect the descending pipe string  5  horizontally. However, this method for deflecting a pipe string also presents several problems including difficulty in stabbing the whipstock into the existing pipe and the probability that the whipstock will become stuck in the mud and prematurely be set and separate from the tubular string. 
         [0032]      FIGS. 4-7  illustrate embodiments of the deflector sub  3   b,  according to the present invention.  FIG. 4  illustrates the basic structure and operation of the deflector sub  3   b.  Preferably, the deflector sub  3   b  has a closed end  19 . However, it should be appreciated that the deflector sub  3   b  does not have to be positioned at the lowermost end of the tubular string  3 , illustrated in  FIG. 1 . The deflector sub  3   b  may be positioned uphole or behind additional subs or devices ( FIG. 7 ). It should be further appreciated that the deflector sub  3  may comprise various top and bottom connections, such as, but not limited to, box and pin connections respectively, and as such, the closed end  19  may be a separate structure attached to the deflector sub  3   b  by threaded attachment, welding, or any other means of conventional attachment or may be located downhole of the deflector sub  3   b.    
         [0033]    Preferably, pumps, or other fluid driving devices, such as the rig pumps may push or propel seawater or other fluid into the tubular string  3  in the general direction indicated by the arrow  17 . The selection of the fluid, being pumped into the tubular string  3  may be dependent on the environment, particularly the environment into which the fluid will be discharged. Preferably, the seawater, or other fluid, is pumped through the tubular string  3  and into the deflector sub  3   b.    
         [0034]    Preferably a jet nozzle  3   b   2  is positioned in the sidewall of the deflector sub  3   b  and becomes the outlet for the seawater or other fluid being pumped through the deflector sub  3   b . As the fluid exits through the nozzle  3   b   2  it will produce a fluid jet  3   b   1 . The fluid jet  3   b   1 , in turn, preferably produces a thrust  3   b   3 , in a substantially opposite direction from the fluid jet  3   b   1  and thus moves the deflector sub in the direction of the thrust  3   b   3 . It should be appreciated that the amount of pressure in the bore of the tubular string  3  and the nozzle  3   b   2  size influences the amount of the thrust force  3   b   3 , which in turn substantially determines the amount of deflection of the tubular string  3 . It should be appreciated, by those skilled in the art, that nozzle  3   b   2  is typically a commercially available item and can be found in a variety of sizes. However, the utilization of non-commercial or non-conventional nozzle sizes should not be viewed as a limitation of the present apparatus or method. 
         [0035]      FIG. 5  illustrates further detail of the deflector sub  3   b  which preferably comprises a deflector sub body  16 , nozzle  3   b   2 , O-ring  18 , and retaining ring  20 . It should be appreciated that nozzle  3   b   2 , O-ring  18 , and retaining ring  20 , whether commercially available or specifically manufactured for a particular application, are well known in the art and will not be described in detail herein.  FIGS. 6 and 6A  illustrate cross-sectional, longitudinal and end views, respectively, of deflector sub body  16 . Orifice  22  is preferably machined in the wall of the deflector sub body  16  for receiving the nozzle  3   b   2 .  FIG. 6B  is an enlarged view of orifice  22  in the wall of the deflector sub body  16 . 
         [0036]      FIG. 7  illustrates an alternative embodiment of the invention in which deflector sub  3   b  is installed behind or uphole from a bit sub  13  located at the end of tubular string  3 . Bit sub  13  is preferably plugged at its lower end  14  in order to allow fluid and pressure, in the drill string or tubular string  3 , to discharge through nozzle  3   b   2 . The guide tubular  3  is illustrated as passing beside a bay brace  7  which resides on the exterior of the guide sleeve  15  through which the unusable wellbore is associated. The guide sleeve  15  is located on the lowermost horizontal rig brace ld illustrated in  FIG. 1 . 
         [0037]    In recovering a “slot”, a drill string or tubular string  3  is preferably lowered, through the “slot” to be recovered and at least some of its corresponding vertically aligned guide sleeves  15 , to a point about three to four feet above the sea floor. It should be understood that the target depth can vary depending on several factors including, but not limited to, the overall ocean depth, speed of currents, amount of desired deflection, and the size/weight of the guide string. Thus, it should be appreciated that in more adverse conditions, the deflection of the tubular string  3  may need to be initiated earlier or later (i.e. further from or closer to the sea floor) in order to accomplish the desired deflection or to avoid other objects such as, but not limited to, other drill strings, or other drilling related operations. The position of tubular string  3  may then be verified with a measurement device such as a gyroscope. The tubular string  3  is then preferably deflected by energizing a deflector sub  3   b  which is preferably attached to the end of the tubular string  3 . 
         [0038]      FIG. 8  illustrates tubular string  3  being deflected by the side thrust  3   b   3  being produced by the fluid jet  3   b   1 .  FIG. 8  further illustrates an unuseable well bore  21  (the wellbore  21  being unuseable as described herein above). The deflection, of the tubular string  3 , preferably causes the tubular string  3  to bypass at least the lower most guide sleeve  15  and an unusable wellbore  21  thus recovering the previously unuseable “slot” associated with its vertically aligned guide sleeve  15  and unuseable wellbore  21 . After tubular string  3  is deflected as illustrated, it is then preferably inserted or speared into the mud or sea floor B along line  3   c.  It should be understood that line  3   c  is preferably deflected, at some desired angle, from a vertical axis passing through the recovered “slot” and its vertically aligned guide sleeves  15  and the unuseable wellbore  21 . 
         [0039]    After the tubular string  3  has been inserted or speared into the sea floor B mud line ( FIG. 9 ), the pumping of seawater is preferably stopped and measurements are taken to verify the position of the deflected drill string or tubular string  3 . The tubular string  3  may then be further lowered until it preferably supports its own weight axially. It should be appreciated that the tubular string  3  will substantially sink through the mud or sediment bottom due to its own weight. It should be appreciated that as the drill pipe or tubular string  3  is lowered further into the seabed B, it will preferably retain its deflected position and not shift in a horizontal direction to its pre-deflected vertically aligned position. The tubular string  3  may then be disconnected at the rotary table (not illustrated) on the platform, leaving a stub protruding through the rotary floor (not illustrated). Another pipe or tubular string  2  ( FIG. 9 ) may then be lowered over the deflected tubular string  3 . 
         [0040]      FIG. 9  illustrates the drive pipe or tubular string  2  installed to preferably slide over the deflected tubular string  3 .  FIGS. 9 ,  10 ,  12 , and  13  illustrate the tubular string  2  and the deflected tubular string  3  being in a substantially concentric relationship. However, this is optional since in order to maintain such a substantially concentric relationship some type of centralization device (not illustrated), such as a conventional tubular centralizer, would have to be used. The deflected tubular string  3  preferably acts as a guide string to deviate the pipe string or tubular string  2  as it is lowered, over the deflected tubular or tubular string  3 , to the sea floor B. The pipe string or tubular string  2  will preferably be thrust into the mud below mud line as illustrated in  FIG. 10 . The tubular string  3  may then be withdrawn from inside the pipe or tubular string  2 , as shown in  FIG. 11 . It should be appreciated that the conductor bay brace  7  may also aid in the offset alignment of the drive pipe or tubular string  2 . The conductor bay brace  7  will preferably aid in preventing the drive pipe or tubular string  2  from moving in a substantially horizontal direction toward the unuseable well bore  21 . 
         [0041]      FIG. 12  illustrates an alternative embodiment similar to that illustrated in  FIG. 8  except that both the tubular string  3 , with the deflector sub  3   b,  and pipe string  2  are installed/lowered together to a desired position above the seabed B. It should be understood that the tubular string  3  is installed/lowered while positioned in the throughbore of the pipe string  2 . As described herein above, pumps may be activated to cause flow through the fluid jet  3   b   1  thus producing a side load  3   b   3  and deflecting both the tubular string  3  and tubular string  2 . When deflected, both the tubular string  3  and tubular string  2  may be dropped/inserted into the mud to secure the deflected position. Further, as illustrated in  FIG. 11 , the inner tubular string  3  can be retrieved from the inner bore of the drive pipe or tubular string  2 . 
         [0042]      FIGS. 13-18  show another embodiment of a deflector sub  3   b.  This embodiment will preferably allow the deflector sub to deflect the tubular string, as described herein above, and then redirect the jet flow from a side nozzle to a bottom nozzle or aperture to aid in the insertion of the drill pipe or tubular string  3  into the seabed B or “glance” off other obstructions.  FIG. 13  illustrates the nozzle switching apparatus  23  which may be housed in a tubular section  8 . It should be appreciated that the tubular section  8  may be attached to the end of tubular string  3 , a pipe, or other tool or tubular as necessary in a manner similar to that of the deflector sub  3   b  described herein above. Preferably, the nozzle switching apparatus  23  comprises a drillable material such that the nozzle switching apparatus  23  will not restrict further drilling operations. It should be appreciated that the nozzle switching apparatus  23  may be used as part of a guide string, wherein a larger tubular string is installed over it, or the apparatus  23  may be utilized to guide and deflect the larger tubular. Still referring to  FIG. 13 , the nozzle switching apparatus further comprises a guide  8   b  which is preferably configured to guide the piston  9 . In its first position, the piston  9  isolates the bore  8   a,  of the tubular section  8  from a lower cavity  12 . The piston  9  preferably comprises a plurality of grooves  9   c,  disposed about the piston  9 , which may engage corresponding ridges  8   d,  disposed about the inner circumference of the lower portion of the tubular section  8 . The engagement of the ridges  8   d  with the grooves  9   c  will preferably prevent rotation of the piston  9  when it is necessary to drill out the nozzle switching apparatus  23  (See  FIGS. 16-18 ). The lower most portion of the tubular section  8  preferably comprises an end  8   c  preferably having an opening  8   f,  which may be circular or non-circular, as desired. 
         [0043]    The piston  9  is preferably configured with a central channel  9   a  bored in a substantially longitudinal direction to intersect with a cross bore  9   b  which passes through the piston  9  in a substantially radial direction. In the first position, the piston  9  is releasably secured such that the cross bore  9   b  is in fluid communication with a nozzle  8   e.  It should be understood that the piston  9  may be held in the first position by a variety of attachment means including, but not limited to shear screws, set screws, ridges, frangible supports, pins, rivets, screws, bolts, specific tolerance fits or a variety of other conventional retention means. 
         [0044]    As with the deflector sub  3   b,  preferably a fluid, such as seawater, is pumped into the nozzle switching apparatus  23  to activate the jet flow J 1  by pumping or propelling the fluid through the nozzle  8   e.  It should be understood that the fluid is pumped through the pipe or tubular string which extends from the tubular section  8  to the drilling rig or other drilling structure. As the fluid is pumped through the bore  8   a  of the tubular section  8 , it will preferably enter the central channel  9   a,  move into the cross bore  9   b,  and be exhausted through the nozzle  8   e  to produce the jet J 1 . The jet J 1  will preferably produce a thrust force in a similar manner to the jet  3   b   1  thus causing the tubular  8  and any attached tubular string to deflect in a direction substantially opposite the nozzle  8   e.    
         [0045]    When the desired deflection is achieved and/or it is desired to switch operation from the side nozzle  8   e  to the bottom nozzle or aperture  8   f,  a ball  10  or other stopper is preferably dropped down the bore of the tubular, attached to the tubular section  8 , to close channel  9   a  as illustrated in  FIG. 14 . With the seawater still being pumped into the bore  8   a,  the pressure builds up against the top of piston  9  and preferably forces the piston  9  downward to a second position as illustrated in  FIG. 15 . It should be appreciated that the pressure increase, which preferably occurs due to the ball or stopper  10  blocking channel  9   a,  will shear or break any support maintaining the piston  9  in its initial position and thus allowing for its downward travel. After the piston  9  moves from the first position, cross bore  9   b  will no longer communicate with the nozzle  8   e.  In the second position, cross bore  9   b  will preferably open to the cavity  12 . 
         [0046]    After the piston  9  has moved to the second position, the pressure in bore  8   a  is further raised to pump the ball  10  through the central channel  9   a  and the cross bore  9   b  to permit flow through the bottom hole  8   f.  It should be understood that ball  10  may be comprised of a variety of materials including, but not limited to, elastomeric, plastic, or frangible materials such as to allow the ball  10  to deform or break in order to pass through the central channel  9   a,  the cross bore  9   b,  and into the lower cavity  12 . After the ball  10  is pushed out of the piston  9 , as illustrated in  FIG. 16 , any flow though the bore  8   a  is preferably directed through the bottom hole  8   f  to aid in reducing interference from mud and sediment which is preferably loosened or removed by the flow through the bottom hole  8   f.  It should be appreciated that the bottom hole  8   f  can also be configured to accept a nozzle, such as  8   e  or  3   b   1  to produce a more forceful jet flow for reducing the interference. 
         [0047]      FIG. 17  illustrates an embodiment wherein the interior components of the tubular section  8  and the attached tubular string are ready to be drilled out for subsequent activity. A milling or drilling assembly  11 , which may be commonly run on a drill string, includes at least one cutter insert  11   a.  It should be understood, by those in the art, that a conventional milling or drilling assembly  11  will preferably drill or mill out substantially all material attached to the inside diameter of tubular  8 .  FIG. 18  illustrates the pipe string or tubular  8  after the drilling operation has been carried out. Typically, the side nozzle  8   e  can remain unplugged. 
         [0048]    Referring now to  FIGS. 19 and 20 , the lowermost end of the drive pipe or tubular string  2  will preferably, comprise a drive shoe  26  which may be integral to the lowermost section of the drive pipe or tubular string  2  or may be a separate drive shoe attached to the lowermost section of the drive pipe or tubular string  2 . It should be appreciated that the attachment of the drive shoe  26  is well know in the art and will not be described in detail herein. It should be understood, that although the embodiments illustrated herein show the lower most end of the tubular string  2  as having an angular shaped end, the shape should not be viewed as limiting. A variety of other end configurations should be included within the scope of this invention as the end serves to allow easier entry into the seabed B and aid in guiding the tubular string  2  past obstructions as it is lowered from the rig to the seabed B. 
         [0049]    As illustrated in  FIG. 19 , an embodiment of the drive-shoe  26  may comprise a miter cut  28 , a solid bottom end  35 , and a hole  34  offset from the longitudinal centerline of the shoe  26 . The solid bottom  35  may be a plug, a cap, a molded cap, a welded end, or other desirable closure member. Preferably, solid bottom  35  will be of an easy drillable, frangible, or otherwise removable material, for example, high density polyethylene. The hole  34  allows the deflector sub  3   b,  and any attached tubulars to pass through as the larger diameter tubular  2  is lowered over the drill string or tubular string  3 . The miter cut  28  preferably permits the conductor pipe  2  to “glance” off and not become hung up on the conductor bay brace  7  (see for example  FIGS. 8 and 9 ), other tubular strings, or other drilling and production equipment should it come in contact with them. It should be appreciated that when the drive shoe  26  initially contacts the conductor bay brace  7 , other tubular strings, or other drilling and production equipment there will be a point force exerted on the drive shoe  26  from the contact. The hole  34  is preferably provided so that the position of the conductor or tubular string  2  with respect to the drill pipe or tubular string  3  can be controlled. Preferably, the drive-shoe  26  on the conductor pipe or tubular string  2  will effectively “ramp” off the conductor bay brace  7  with little resistance and allow the tubular string  2  to enter the seabed B. 
         [0050]    As further illustrated in  FIG. 19 , an embodiment of the drive shoe joint  26  preferably comprises a miter cut  28  with reinforcing material  30  on the long end to prevent curling of the tip  32 . The remainder of the drive shoe is preferably manufactured from steel or another non-drillable material. The miter cut  28  may comprise various angles depending on factors such as, but not limited to, spacing of other guide sleeves  15  ( FIG. 1 ), other drilling strings, casing, tubing, tool joints, tubulars, and other drilling related operations. 
         [0051]    It should be understood that the drive shoe  26 , with the miter cut  28 , may also be utilized to avoid collisions with other tubular strings in a manner similar to the “glancing” effect described herein above. Further, the combination of the drive shoe  26 , with the miter cut  28 , and the guide string  3 , similar to the embodiment illustrated in  FIG. 12 , may be utilized to avoid collisions by activating the fluid jet  3   b   1  in conjunction with the miter cut  28  “glancing” operation. It should also be appreciated, that when desired, fluid may also be moved through the bore of the shoe  26  such that the fluid, when exiting through the hole  34  may aid in moving the drive shoe through the softer sediment and mud. 
         [0052]    Referring now to  FIG. 20 , there is illustrated the lower end of a conductor pipe  200  having an end  202  having at least one nozzle  204  located in the side wall  206  of the conductor pipe  200 . In the operation of the conductor pipe  200 , fluid flowing through the nozzle  204  will cause conductor pipe  200  to be thrust in the direction of the arrow  208 . With this embodiment, by putting the nozzle in the conductor pipe directly, there is no requirement of using a drill string and then lowering the conductor pipe over the drill string. In this embodiment, the conductor pipe is directly deflected. 
         [0053]    As an option, the lower end of the conductor pipe  200  can be filled with an easy drillable material  210 , for example, hard plastic. 
         [0054]    Referring now to  FIG. 21 , an alternative embodiment of the invention, which illustrates the use of a plurality of nozzles in the side wall of a tubular, for example, nozzles  220  and  230  which generate a resulting thrust along the dotted line  240  indicative of the vector sum of the multiple thrusts which result in a deflection of the tubular along the arrow  215 . 
       Operation 
       [0055]    In practicing the present invention, in order to recover the use of an existing slot which has formerly been used in an abandoned wellbore, the existing string or strings of pipe have to first be removed. 
         [0056]    All uncemented strings of pipe, if not stuck within the wellbore, are pulled from the abandoned wellbore, and usually also any pipes remaining between the seabed and the slot to be recovered. 
         [0057]    Any remaining strings of pipe are cut approximately eighty feet below the mudline by conventional apparatus and methods which are well known in the art of cutting tubulars such as casing cutters, production tubing cutters, drill pipe cutters, and the like. Such well-known tubular cutting technology includes the use of mechanical cutters, explosive cutters, chemical cutters, and combinations thereof. 
         [0058]    After the existing strings of pipe have been removed, new strings of pipe are run through the recovered slot and then through the vertically spaced braces such as the guide sleeves  15  used with the braces  1   a - 1   d  discussed herein with respect to  FIG. 1 . The new string or strings are then run down to or into the mudline and the string or strings can then be moved laterally by the various fluid jetting processes herein described. 
         [0059]    From the foregoing, it will be seen that this invention is one well adapted to attain all of the ends and objects hereinabove set forth, together with other advantages which are obvious and which are inherent to the tubular string deflector and method of the present invention. 
         [0060]    The tubular string deflector and method of the present invention and many of its intended advantages will be understood from the foregoing description. It will be apparent that, although the invention and its advantages have been described in detail, various changes, substitutions, and alterations may be made in the manner, procedure and details thereof without departing from the spirit and scope of the invention. It should be understood that certain features and sub-combinations are of utility and may be employed without reference to other features and sub-combinations. This is contemplated by and is within the scope of the claims.