FIELD OF THE INVENTION 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 TM DRAWINGS FIG. 1 illustrates a side elevated view of the lower portion of an offshore installation utilizing the deflector apparatus according to the present invention;
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;
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;
FIG. 4 illustrates a cross-sectional elevated side view of a deflector sub according to the present invention;
FIG. S illustrates an exploded, elevated perspective view of an alternative embodiment of a deflector sub according to the present invention;
FIG. 6 illustrates a longitudinal, cross-sectional view of the embodiment illustrated in FIG. 5 according to the present invention;
FIG. 6A illustrates an end plan view of the embodiment illustrated in FIG. 6 according to the present invention;
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;
FIG. 7 illustrates a side view, partially cut away, of an alternative embodiment of the deflector sub according to the present invention;
FIG. 8 illustrates a side elevated, diagrammatic view of a tubular string deflected by a fluid jet according to the present invention;
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;
FIG. 10 illustrates a side elevated, diagrammatic view of a pair of concentric tubulars being pushed into the seabed according to the present invention;
FIG. 11 illustrates a side elevated view of the internal tubular string illustrated in FIG. 10 having been removed according to the present invention;
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;
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;
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;
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;
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;
FIG. 17 illustrates a side cut away, elevated view of the embodiment illustrated in FIG. 16 further illustrating a drill bit according to the present invention;
FIG. 18 illustrates a side cut away, elevated view of the embodiment illustrated in FIG. 17 with the nozzle switching apparatus drilled out according to the present invention; and
FIG. 19 illustrates an elevated, pictorial view of a closed end drive shoe according to the present invention.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS 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.
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 B, is preferably anchored in a conventional manner, and preferably has vertically distributed braces such as illustrated by braces 1a-1d. 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 1a-1d 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.
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, the existing well being depleted, or 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.
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 3b as further described herein below.
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 4B to secure a winch line or cable 4a 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 4a 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.
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 6b 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 tubular string will permanently separate from the whipstock.
FIGS. 4-7 illustrate embodiments of the deflector sub 3b, according to the present invention. FIG. 4 illustrates the basic structure and operation of the deflector sub 3b. Preferably, the deflector sub 3b has a closed end 19. However, it should be appreciated that the deflector sub 3b does not have to be positioned at the lowermost end of the tubular string 3, illustrated in FIG. 1. The deflector sub 3b 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 3b by threaded attachment, welding, or any other means of conventional attachment or may be located downhole of the deflector sub 3b.
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 3b.
Preferably a jet nozzle 3b2 is positioned in the sidewall of the deflector sub 3b and becomes the outlet for the seawater or other fluid being pumped through the deflector sub 3b. As the fluid exits through the nozzle 3b2 it will produce a fluid jet 3b1. The fluid jet 3b1, in turn, preferably produces a thrust 3b3, in a substantially opposite direction from the fluid jet 3b1 and thus moves the deflector sub in the direction of the thrust 3b3. It should be appreciated that the amount of pressure in the bore of the tubular string 3 and the nozzle 3b2 size influences the amount of the thrust force 3b3, 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 3b2 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.
FIG. 5 illustrates further detail of the deflector sub 3b which preferably comprises a deflector sub body 16, nozzle 3b2, O-ring 1 8, and retaining ring 20. It should be appreciated that nozzle 3b2, 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 3b2. FIG. 6B is an enlarged view of orifice 22 in the wall of the deflector sub body 16.
FIG. 7 illustrates an alternative embodiment of the invention in which deflector sub 3b 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 3b2. 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 id illustrated in FIG. 1.
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 3b which is preferably attached to the end of the tubular string 3.
FIG. 8 illustrates tubular string 3 being deflected by the side thrust 3b3 being produced by the fluid jet 3b1. 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. While tubular string 3 is deflected as illustrated, it is then preferably inserted or speared into the mud or sea floor B along line 3c. It should be understood that line 3c 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.
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 portion of the string 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.
FIG. 9 illustrates the drive pipe or tubular string 2 installed, preferably slid over the deflected tubular string 3. FIGS. 9, 10, and 12 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.
FIG. 12 illustrates an alternative embodiment similar to that illustrated in FIG. 8 except that both the tubular string 3, with the deflector sub 3b, 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 3b1 thus producing a side load 3b3 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.
FIGS. 13-18 show another embodiment of a deflector sub 3b. 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 3b 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 8b which is preferably configured to guide the piston 9. In its first position, the piston 9, having an upper surface (unnumbered) tapered inwardly towards channel 9a, isolates the bore 8a, of the tubular section 8 from a lower cavity 12. The piston 9 preferably comprises a plurality of grooves 9c, disposed about the piston 9, which may engage corresponding ridges 8d, disposed about the inner circumference of the lower portion of the tubular section 8. The engagement of the ridges 8d with the grooves 9c will preferably prevent rotation of the piston 9 when it is necessary to drill out the nozzle switching apparatus 23 (See FIGS. 15-17). The lower most portion of the tubular section 8 preferably comprises an end 8c preferably having an opening 8f, which may be circular or non-circular, as desired.
The piston 9 is preferably configured with a central channel 9a bored in a substantially longitudinal direction to intersect with a cross bore 9b 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 9b is in fluid communication with a nozzle 8e. 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.
As with the deflector sub 3b, 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 8e. 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 8a of the tubular section 8, it will preferably enter the central channel 9a, move into the cross bore 9b, and be exhausted through the nozzle 8e to produce the jet J 1. The jet J 1 will preferably produce a thrust force in a similar manner to the jet 3b1 thus causing the tubular 8 and any attached tubular string to deflect in a direction substantially opposite the nozzle 8e.
When the desired deflection is achieved and/or it is desired to switch operation from the side nozzle 8e to the bottom nozzle or aperture 8f, a ball 10 or other stopper is preferably dropped down the bore of the tubular, attached to the tubular section 8, to close channel 9a as illustrated in FIG. 14. With the seawater still being pumped into the bore 8a, 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 9a, 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 9b will no longer communicate with the nozzle 8e. In the second position, cross bore 9b will preferably open to the cavity 12.
After the piston 9 has moved to the second position, the pressure in bore 8a is further raised to pump the ball 10 through the central channel 9a and the cross bore 9b to permit flow through the bottom hole 8f, as illustrated in FIG. 16. 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 9a. After the ball 10 is pushed out of the piston 9, as illustrated in FIG. 16, any flow though the bore 8a is preferably directed through the bottom hole 8f to aid in reducing interference from mud and sediment which is preferably loosened or removed by the flow through the bottom hole 8f. It should be appreciated that the bottom hole 8f can also be configured to accept a nozzle, such as 8e or 3b1 to produce a more forceful jet flow for reducing the interference.
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 11a. 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 8e can remain unplugged.
Referring now to FIG. 19, 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.
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. The hole 34 allows the deflector sub 3b, 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 (FIG. 8), 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.
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.
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 3b1 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.
Operation
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.
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.
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.
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 1a-1d 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.
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.
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.
