Patent Application
20130319686
The present disclosure relates generally to the field of well drilling operations. More specifically, embodiments of the present disclosure relate to the use of centralizers with casing or tubing in a down-hole environment and the attachment of such centralizers or other structures to the casing or tubing.
In conventional oil and gas operations, a well is typically drilled to a desired depth with a drill string, which includes drill pipe and a drilling bottom hole assembly (BHA). Once the desired depth is reached, the drill string is removed from the hole and casing is run into the vacant hole. In some conventional operations, the casing may be installed as part of the drilling process. A technique that involves running casing at the same time the well is being drilled may be referred to as “casing-while-drilling.”
Casing may be defined as pipe or tubular that is placed in a well to prevent the well from caving in, to contain fluids, and to assist with efficient extraction of product. When the casing is properly positioned within a hole or well, the casing is typically cemented in place by pumping cement through the casing and into an annulus formed between the casing and the hole (e.g., a wellbore or parent casing). Once a casing string has been positioned and cemented in place or installed, the process may be repeated via the now installed casing string. For example, the well may be drilled further by passing a drilling BHA through the installed casing string and drilling. Further, additional casing strings may be subsequently passed through the installed casing string (during or after drilling) for installation. Indeed, numerous levels of casing may be employed in a well. For example, once a first string of casing is in place, the well may be drilled further and another string of casing (an inner string of casing) with an outside diameter that is accommodated by the inside diameter of the previously installed casing may be run through the existing casing. Additional strings of casing may be added in this manner such that numerous concentric strings of casing are positioned in the well, and such that each inner string of casing extends deeper than the previously installed casing or parent casing string.
Liner may also be employed in some drilling operations. Liner may be defined as a string of pipe or tubular that is used to case open hole below existing casing. Casing is generally considered to extend all the way back to a wellhead assembly at the surface. In contrast, a liner merely extends a certain distance (e.g., 30 meters) into the previously installed casing or parent casing string. However, a tieback string of casing may be installed that extends from the wellhead downward into engagement with previously installed liner. The liner is typically secured to the parent casing string by a liner hanger that is coupled to the liner and engages with the interior of the upper casing or liner. The liner hanger may include a slip device (e.g., a device with teeth or other gripping features) that engages the interior of the upper casing string to hold the liner in place. It should be noted that, in some operations, a liner may extend from a previously installed liner or parent liner. Again, the distinction between casing and liner is that casing generally extends all the way to the wellhead and liner only extends to a parent casing or liner. Accordingly, the terms “casing” and “liner” may be used interchangeably in the present disclosure. Indeed, liner is essentially made up of similar components (e.g., strings of tubular structures) as casing. Further, as with casing, a liner is typically cemented into the well.
Thus, establishing a down-hole operation, such as may be involved in conventional oil and gas operations, may involve deploying and operating a variety of tubular components (e.g., casing, liner, drill pipe, and so forth) down a tubular wellbore, while the wellbore is being formed or after the wellbore is formed. In certain instances, the tubular elements may be fitted with a component that acts to centralize the tubular elements within the bore, e.g., a centralizer. For example, during a casing drilling operation, a series of centralizers may be fitted to the casing during the drilling operation to keep the casing centered within the bore. For example, the centralizers may be fitted at the joints where casing segments are joined (such as every 30 feet) or at other periodic distances to insure that the casing remains centered in the bore.
In accordance with one embodiment, a wedge segment includes an arcuate body having a tapered profile sized to engage with a tubular element, a first surface of the arcuate body comprising a first surface treatment configured to grip an outer surface of the tubular element, and a second surface of the arcuate body comprising a second surface treatment configured to grip an inner surface of an annular member disposed about the tubular element.
In accordance with a second embodiment, an assembly includes a casing or liner string, a centralizer disposed around a circumference of the casing or liner string, and a first wedge segment positioned between an inner surface of a first end of the centralizer and an outer surface of the casing or liner string.
In accordance with a third embodiment, a method for coupling a centralizer to a tubular member includes disposing the centralizer about the tubular member, creating a first frictional engagement between a first wedge segment and the tubular member, and creating a second frictional engagement between the first wedge segment and the centralizer.
These and other features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein:
The present disclosure relates generally to the attachment of a centralizer (or other structure) to a down-hole component, such as a casing, liner, or drill pipe. Embodiments of the present disclosure are directed to providing and using one or more wedge segments for attachment of a centralizer to a tubular component. In one implementation, an arcuate (i.e., curved) or annular (i.e., ring-like) wedge segment for attaching a centralizer has a surface texture or finish on one surface (e.g., an outer surface) to mate with an inner surface on an end of the centralizer. The wedge segment has a second surface (e.g., an inner surface) with a surface texture or finish for gripping a surface (e.g., an outer surface) of the tubular element (e.g., casing) to which the centralizer is being attached. For example, the surface textures or finishes on the first and/or second surfaces of the wedge segment may be grooves, teeth, ridges, or other surface treatments configured to create frictional resistance. In such an implementation, one or more wedge segments may be positioned at each end of the centralizer to be attached, and the wedge segments may be forced inward (e.g., towards a center of the centralizer) between the centralizer and the underlying tubular element. The wedge shape of the wedge segments causes both the centralizer and underlying tubular element to engage (e.g., frictionally) with the wedge segments so as to attach the centralizer to the underlying tubular element.
With the foregoing in mind, and turning to the figures,
While other embodiments may utilize different drilling techniques, as indicated above, the well 10 is being drilled using a casing-while-drilling technique. Specifically, the liner string 12 is being run as part of the drilling process. In the illustrated embodiment, a drill pipe 30 is coupled with the liner string 12 and a drilling BHA 32. The drilling BHA 32 is also coupled with an upper portion of the liner string 12 and extends through the liner string 12 such that certain features of the drilling BHA 32 extend out of the bottom of the liner string 12. Indeed, an upper portion of the drilling BHA 32 is disposed within the inside diameter of the liner string 12, while a lower portion of the drilling BHA 32 extends out of a liner shoe 34 at the bottom of the liner string 12. Specifically, in the illustrated embodiment, a drill bit 36 and an under reamer 38 of the drilling BHA 32 extend out from the liner string 12. Thus, the drilling BHA 32 is positioned to initiate and guide the drilling process.
The liner string 12 includes a shoe track 40, a string of tubing 42, and a liner top assembly 44. The shoe track 40 defines the bottom of the liner string 12 and includes the liner shoe 34 to facilitate guiding the liner string 12 through the wellbore. In the illustrated embodiment, the shoe track 40 also includes an indicator landing sub 46 to facilitate proper engagement with the drilling BHA 32, and various other features, such as a pump down displacement plug (PDDP). The string of tubing 42 is essentially the main body of the liner string 12 that connects the shoe track 40 with the liner top assembly 44. The liner top assembly 44, which defines the top of the liner string 12, includes a liner hanger 49 that is capable of being activated and/or deactivated by a liner hanger control tool 52. The liner top assembly 44 may also include a liner drill lock section 54, which includes a liner drill lock that facilitates engagement/disengagement of the drill string 30 from the liner string 12. The liner drill lock may be actuated by external or internal components affixed to or part of a body of the liner hanger 49.
Once a desired depth is reached, the liner string 12 may be hung or set down to facilitate detachment of the drilling BHA 32. As illustrated in
The casing and liner strings (e.g., the casing 22, the parent liner 14, and the liner string 12) are run into the well 10 using a running tool. As used herein, the terms “casing” and “liner” may be used interchangeably in the present disclosure. As will be appreciated from this discussion, a wide array of tubular elements (e.g., casing, liner, drill pipe, and so forth) may be positioned within the wellbore. For example, in the above described implementation of casing-while-drilling, casing or liner string 12 may be positioned in the well bore as part of the drilling or deployment operation. For instance, in one type of implementation, the casing may consist of 30 foot segments of a suitable diameter (e.g., 13⅜ inches) that are joined as the casing is deployed down the wellbore. As will be appreciated, in other implementations, length of the casing segments and/or the diameter of the casing may be any suitable length or diameter.
As discussed herein, some of the various tubular elements, such as the casing, may have one or more centralizing elements (i.e., centralizers 50) attached using techniques in accordance with the present disclosure. The attached centralizing elements keep the tubular element centered within the wellbore when deployed and operated (e.g., rotated). Turning to
As mentioned above, the wedge segments 60 are initially positioned such that they are aligned with a lengthwise axis 105 of the centralizer 50 and generally outside of the first and second ends 102 and 104 of the centralizer 50. Subsequently, the wedge segments 60 are forced towards a central radial axis 106 of the centralizer 50 and wedged between the first and second ends 102 and 104 and the casing or liner string 12. For example, as discussed below, each end 102 and 104 of the centralizer 50 may accommodate 1, 2, 3, 4, 5, 6, or more wedge segments 60. Specifically, once the wedge segments 60 are positioned at the respective ends 102 or 104 of the centralizer 50, the wedge segments 60 are forced inward by annular plates 108 disposed about the casing or liner 12 on opposite ends of the centralizer 50. More specifically, the annular plates 108 may be coupled to hydraulic rams 110, and the hydraulic rams 110 may contract or shorten to translate the annular plates 108 toward one another. In this manner, the annular plates 108 may drive the wedge segments 60 between the centralizer 50 and the casing or liner 12. As the wedge segments 60 are forced or wedged between the centralizer 50 and the casing or liner 12, the inner and outer surfaces of the wedge segments 60 may frictionally engage with the casing or liner 12 and the centralizer 50, respectively, thereby securing the centralizer 50 to the casing or liner 12.
As shown in the embodiment illustrated by
Furthermore, the outer surface 122 of the wedge segment 60 also includes teeth 126. The teeth 126 formed on the outer surface 122 engage with similar teeth 128 formed on an inner surface 130 of the centralizer 50. As shown, the teeth 126 formed in the outer surface 122 are angled so as to facilitate movement of the wedge segment 60 inward towards the central radial axis 106 of the centralizer 50, but resist movement of the wedge segment 60 outward. More specifically, the teeth 128 formed in the centralizer 60 are angled outward, and therefore engage with the teeth 126 formed in the outer surface 122 of the wedge segment 60 to block or resist movement of the wedge segment 60 outwards. For example, the teeth 126 of the wedge segment 60 and the teeth 128 of the centralizer 50 may have similar but opposite angles to facilitate engagement of the teeth 126 and 128 to block movement of wedge segment 60 in an outward direction. In other embodiments, one or both sets of teeth 126 and 128 may be excluded.
As similarly discussed above, in the illustrated embodiment, the wedge segment 60 may have a tapered configuration. In other words, the inner and outer surfaces 120 and 122 may be disposed at an angle relative to one another, thereby giving the wedge segment 60 a wedge shape. Consequently, as the wedge segment 60 progresses toward the radial axis 106 during coupling of the centralizer 50 to the casing or liner 12, a radially inward force is increasingly applied to the casing or liner 12 as the wedge segment 60 is forced between the centralizer 50 and the casing or liner 12 by the annular plate 108. As the radially inward force is applied to the casing or liner 12, the surface treatment 150 of the inner surface 120 of the wedge segment 60 increasingly engages the casing or liner 12. As a result, frictional forces are created between the wedge segment 60 and the casing or liner 12, thereby blocking or resisting movement of the wedge segment 60 outward and securing the centralizer 50 to the casing or liner 12.
As discussed above, the teeth 124 may be carburized teeth and may be suitably dimensioned so as to facilitate cutting into and/or gripping the casing or liner string 12 when the wedge segment 60 is in place. For example, turning to
While the preceding discussion has generally related to the application of a centralizer 50 to a casing or liner 12 using wedge segments 60, it should be appreciated that this implementation has been provided by way of example only, and is not intended to limit the scope of the present disclosure. That is, the use of wedge segments 60 as disclosed herein may be similarly applied to attach other elements or structures to a tubular element. For example, wedge segments 60 as disclosed herein may be used to apply wear bands or other structures to a casing or liner string 12 or to any other suitable tubular element. With the foregoing discussion in mind, it should be appreciated that certain presently described embodiments allow engagement of a structure, such as a centralizer or wear band, to a tubular element, such as a casing or liner string by the use of wedge rings as discussed herein.
While only certain features of the invention have been illustrated and described herein, many modifications and changes will occur to those skilled in the art. It is, therefore, to be understood that the appended claims are intended to cover all such modifications and changes as fall within the true spirit of the invention.
