The present invention relates in general to reamers and stabilizers for use in the drilling of boreholes, and in particular to reamers and stabilizers used in conjunction with downhole motors.
In drilling a borehole into the earth, such as for the recovery of hydrocarbons (e.g., crude oil and/or natural gas) from a subsurface formation, it is conventional practice to connect a drill bit onto the lower end of an assembly of drill pipe sections connected end-to-end (commonly referred to as a “drill string”), and then rotate the drill string so that the drill bit progresses downward into the earth to create the desired borehole. A typical drill string also incorporates a “bottom hole assembly” (“BHA”) disposed between the bottom of the drill pipe sections and the drill hit. The BHA is typically made up of sub-components such as drill collars and special drilling tools and accessories, selected to suit the particular requirements of the well being drilled, In conventional vertical borehole drilling operations, the drill string and hit are rotated by means of either a “rotary table” or a “top drive” associated with a drilling rig erected at the ground surface over the borehole.
During the drilling process, a drilling fluid (commonly referred to as “drilling mud”) is pumped downward through the drill string, out the drill bit into the borehole, and then back up to the surface through the annular space between the drill string and the borehole. The drilling fluid carries borehole cuttings up to the surface while also performing various other functions beneficial to the drilling process, including cooling the drill bit cooling and forming a protective cake on the borehole wall (to stabilize and seal the borehole wall).
As an alternative to rotation by a rotary table or a top drive, a drill bit can also be rotated using a “downhole motor” (alternatively referred to as a “drilling motor” or “mud motor”) incorporated into the drill string immediately above the drill bit, The mud motor is powered by drilling mud pumped under pressure through the mud motor in accordance with well-known technologies. The technique of drilling by rotating the drill bit with a mud motor without rotating the drill string is commonly referred to as “slide” drilling, because the nor'-rotating drill string slides downward within the borehole as the rotating drill bit cuts deeper into the formation. Torque loads from the mud motor are reacted by opposite torsional loadings transferred to the drill string.
Downhole motors are commonly used in the oil and gas industry to drill horizontal and other non-vertical boreholes (i.e., “directional drilling”), to facilitate more efficient access to and production from more extensive regions of subsurface hydrocarbon-bearing formations than would be possible using vertical boreholes.
It is very common for a BHA to incorporate a reaming tool (“reamer”) and/or a stabilizer tool (“stabilizer”). Reaming may be required to enlarge the diameter of a borehole that was drilled too small (due perhaps to excessive wear on the drill bit). Alternatively, reaming may be needed in order to maintain a desired diameter (or “gauge”) of a borehole drilled into clays or other geologic formations that are susceptible to plastic flow (which will induce radially-inward pressure tending to reduce the borehole diameter). Reaming may also be required for boreholes drilled into non-plastic formations containing fractures, faults, or bedding seams where instabilities may arise due to slips at these fractures, faults or bedding seams. A stabilizer, following closely behind the drill bit, is commonly used to keep drill string components (including the drill bit) centered in the borehole. This function is particularly important in directional drilling, in order to keep a borehole at a particular angular orientation or to change the borehole angle.
Numerous and varied types of reamers and stabilizers are known in the prior art. Representative examples of prior art reamers and stabilizers may be seen in U.S. Pat. No. 4,385,669 (Knutsen); U.S. Pat. No. 5,474,143 (Majkovic); and U.S. Pat. No. 6,213,229 (Majkovic). In prior art reamers, however, the cutting elements are effective to increase or maintain a borehole diameter only when the drill string is rotating; similarly, the centralizing elements of prior art stabilizers are effective for their purpose only when the drill string is rotating. This is because the cutting elements and centralizing elements of prior art reamers and stabilizers are typically fixed to the corresponding tool bodies, so they rotate about the longitudinal axis of the tool. As a result, the cutting and centralizing elements tend to wear evenly, which allows the reamers and stabilizers to remain effect for their respective purposes despite a certain degree of wear. However, in cases where a non-rotating drill string is being moved axially with a wellbore (such as in slide drilling and in “tripping” operations), the cutting and centralizing elements of known reamers and stabilizers do not rotate, which causes these elements to wear unevenly as they scrape against the sidewalls of the borehole.
For these reasons, there is a need for reamers and stabilizers that are effective for their respective purposes in a drill string that is being moved axially within a wellbore but without rotation. The present invention is directed to this need.
The present invention provides a downhole tool that can be used either for reaming a wellbore or for stabilizing drill string components within a wellbore. For purposes of well bore reaming, the tool will he fitted with reamer cartridges that are radially insertable into corresponding pockets formed into the circumferential surface of the tool. Each reamer cartridge includes a reamer insert having an array of cutting elements, with the reamer insert being disposed within a bushing and being rotatable relative thereto, about a rotational axis transverse to the longitudinal axis of the tool. However, the rotational axis of the reamer insert is offset from the tool's longitudinal axis, such that when the tool is being moved axially through a wellbore without rotation of the drill string, the cutting elements on one side of the reamer insert will contact the wellbore wall first, thereby imparting rotation of the reamer insert as the tool moves through the wellbore. When it is desired to use the tool as a stabilizer, the reamer cartridges are removed and replaced with stabilizer cartridges having stabilizer inserts with hard-faced stabilizer cones.
Rotation of the reamer and stabilizer inserts about a transverse axis facilitates optimal tool performance by minimizing torque and drag on the reaming and stabilizing elements, thereby promoting more even wear and longer downhole service life before requiring replacement. The rotation of the inserts, whether during operations in which the downhole tool is rotating with a rotating drill string, or during operations in which a non-rotating drill string incorporating the downhole tool is being moved axially with a wellbore, reduces or eliminates drag and differential sticking against the wellbore wail (drag and differential sticking being particularly problematic when drilling non-vertical wellbores). In addition, the rotation of the reamer and stabilizer inserts has the further effect of reducing the torque required to rotate the drill string in both vertical and non-vertical wellbores, due to reduced drag and differential sticking.
In accordance with a first aspect, the present invention provides a downhole tool comprising an elongate main body having a longitudinal axis; an outer surface; and a plurality of channels formed into said outer surface, with said channels dividing the main body into a plurality of blade sections corresponding in number to the number of channels; with each of at least two of the blade sections having one or more cartridge pockets formed into the outer surface thereof, with each cartridge pocket being configured to receive a tool cartridge housing a tool insert such that the tool insert is rotatable about a rotational axis transverse to the longitudinal axis of the main body.
Embodiments of the drilling tool as described immediately above may be used effectively in a rotating drill string for either reaming or stabilizing purposes (depending on the type of tool insert used) when the tool is set up with only one tool insert is each blade section.
In another embodiment, the present invention provides a downhole tool comprising an elongate main body having a longitudinal axis; an outer surface; three channels formed into said outer surface, with said channels dividing the central portion of the main body into three blade sections; and with one or more cartridge pockets being formed into each blade section. In this embodiment, at least one cartridge pocket in each blade section has a tool cartridge removably retained therein, with the tool cartridge comprising: a cartridge bushing having a cylindrical bore with a centroidal axis transverse to, and offset from, the longitudinal axis of the main body; and a tool insert rotatable within the cartridge bushing about a rotational axis coincident with said centroidal axis of the cartridge bushing.
In both of the embodiments of the downhole tool described above, the tool insert may be adapted for reaming a wellbore, stabilizing drill string components within a wellbore, or for other wellbore conditioning purposes. In preferred embodiments, the channels in the main body will be angularly skewed relative to the longitudinal axis. In alternative embodiments, however, the channels could have a different orientation (for example, parallel to the longitudinal axis of the main body).
In accordance with a second aspect, the present invention provides a tool cartridge having a rotatable tool insert, for use in conjunction with the aforesaid downhole tool. The tool insert may be a reamer insert or a stabilizer insert, or may be designed to carry out other types of wellbore conditioning or accessory functions, in various different field applications and in different positions in the drill string.
Embodiments of the invention will now be described with reference to the accompanying figures, in which numerical references denote like parts, and in which:
Upper and lower ends 22A and 22B of tool body 20 are adapted for connection to other drill string components (e.g., taper-threaded “pin” and “box” connections, as commonly used in drilling oil and gas wells). In the illustrated embodiment, tool body 20 has an enlarged central section 30 with an outer surface 31. In the illustrated embodiment, central section 30 is of generally cylindrical configuration, with a diameter greater than the outer diameter of tool body 20 at its upper and lower ends 22A and 22B. In alternative embodiments, however, tool body may have a substantially uniform cross-section (of circular or other configuration) along its length, rather than having sections of reduced size at one or both ends.
A plurality of channels 32 are formed into the outer surface 31 of central section 30, to allow upward flow of drilling fluid and wellbore cuttings. In the illustrated embodiments, channels 32 are diagonally or helically-oriented relative to longitudinal axis A-1 of tool body 20. However, this is not essential, and in alternative embodiments channels 32 could be of a different orientation (for example, parallel to longitudinal axis A-1). Channels 32 may extend partially into regions of tool body 20 beyond central section 30, as illustrated in
Formed into outer surface 31 of each blade 35 are one or more cartridge pockets 37, as best seen in
Cartridge bushing 40 is configured to receive a tool insert in the form of a reamer insert 50 as in
As indicated above, rotational axis A-2 of each tool insert is transverse to longitudinal axis A-1 of tool body 20, but this is not to be understood as requiring precise perpendicularity, In some embodiments, rotational axis A-2 will be precisely perpendicular to longitudinal axis A-1, but this is not essential. In alternative embodiments, rotational axis A-2 may be tilted from perpendicular relative to longitudinal axis A-1, which configuration may be beneficial in inducing rotation of the tool inserts during operations in which the drill string is being rotated.
Persons skilled in the art will appreciate that the present invention is not limited or restricted to the use of any particular style of cutting element or any particular cutting element materials. Moreover, the present invention is not limited or restricted to the use of cutting elements disposed within cutter pockets as shown in the exemplary embodiment of
In the embodiment shown in
Reamer insert 50 is mounted in cartridge bushing 40 so as to he freely rotatable within cartridge bushing 40, about rotational axis A-2. Persons skilled in the art will appreciate that this functionality can be provided in a variety of ways using known technologies, and the present invention is not limited to any particular way of mounting reamer insert 50 in or to cartridge bushing 40. In the non-limiting exemplary embodiment shown in
Cartridge bushing 40 is formed with a cylindrical cavity defined by a perimeter wall 41 with an inner cylindrical surface 41A having a diameter slightly larger than the diameter of cylindrical side surface 51A (so as to allow free rotation of reamer insert 50 within cartridge bushing 40, preferably with minimal tolerance); a base section 42 bounded by cylindrical side wall 41 and having an upper surface 42A; and a circular opening 44 extending through base section 42 and having a centroidal axis coincident with rotational axis A-2, with circular opening 44 being sized to receive cylindrical hub 55 of reamer insert 50. Reamer insert 50 is positioned within cartridge bushing 40 with cylindrical hub 55 disposed within circular opening 44 and projecting below base section 42. Reamer insert 50 is rotatably retained within bushing 40 by means of a snap ring 56 disposed within a corresponding groove in the perimeter surface of cylindrical hub 55, below base section 42, as shown in
Reamer cartridges 500 are removably retained within corresponding cartridge pockets 37 in reamer/stabilizer 10. Persons skilled in the art will appreciate that this can be accomplished in a number of ways using known methods, and the present invention is not limited to any particular method or means of removably retaining reamer cartridges 500 within their respective cartridge pockets 37. However, in the preferred embodiment shown in
Referring to
This particular method of assembly facilitates quick and simple cartridge change-out in the shop or in the field, without need for special tools. To remove a cartridge from reamer/stabilizer 10, the corresponding spring pins 39 may be simply driven out of their spring pin bores 36 using a hammer and a suitable metal rod having a smaller diameter than the spring pin bore 36. The cartridge can then be easily pried out of its cartridge pocket 37, preferably with the aid of longitudinally-oriented pry grooves 38 formed into blade 35 at each end of each cartridge pocket 37, as shown in
When it is desired to use reamer/stabilizer 10 as a stabilizer, reamer cartridges 500 may be removed from their respective cartridge pockets 37 and replaced with stabilizer cartridges 600. As illustrated by way of exemplary embodiment in
The configuration and features of stabilizer insert 60, in the embodiment shown in
In some applications, it may be beneficial to fit reamer/stabilizer 10 with a combination of reamer cartridges 500 and stabilizer cartridges 600. In addition, it is possible that other wellbore conditioning needs may require or suggest the use of tool cartridges adapted for purposes other than reaming and stabilizing, and the use of such alternative types of tool cartridges is intended to come within the scope of the present invention. In other applications, effective use of reamer/stabilizer 10 may be possible with well conditioning cartridges installed in some but not all of the cartridge pockets 37 of reamer/stabilizer 10.
In alternative embodiments of reamer/stabilizer 10, the rotational axis A-2 of the tool inserts (e.g., reamer inserts 50 and stabilizer inserts 60) may intersect longitudinal axis A-1 of tool body 20, rather than being offset as shown in FIG, 2. This configuration may result in the inserts being less readily rotatable during non-rotating axial movement of the drill string, but will not detract significantly or at all from the effectiveness of reamer/stabilizer 10 during operations in which the drill string is being rotated.
It will be readily appreciated by those skilled in the art that various modifications of the present invention may be devised without departing from the scope and teaching of the present invention, including modifications which may use equivalent structures or materials hereafter conceived or developed. It is to be especially understood that the invention is not intended to he limited to any described or illustrated embodiment, and that the substitution of a variant of a claimed element or feature, without any substantial resultant change in the working of the invention, will not constitute a departure from the scope of the invention. It is also to he appreciated that the different teachings of the embodiments described and discussed herein may be employed separately or in any suitable combination to produce desired results.
In this patent document, any form of the word “comprise” is to be understood in its non-limiting sense to mean that any hem following such word is included, but items not specifically mentioned are not excluded. A reference to an element by the indefinite article “a” does not exclude the possibility that more than one of the element is present, unless the context clearly requires that there be one and only one such element. Any use of any form of the terms “connect”, “engage”, “couple”, “attach”, or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the subject elements, and may also include indirect interaction between the elements such as through secondary or intermediary structure. Relational terms such as “parallel”, “perpendicular”, “coincident”, “intersecting”, and “equidistant” are not intended to denote or require absolute mathematical or geometrical precision. Accordingly, such terms are to be understood as denoting or requiring substantial precision only (e.g., “substantially parallel”) unless the context clearly requires otherwise.
Number | Date | Country | Kind |
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2665260 | May 2009 | CA | national |
Filing Document | Filing Date | Country | Kind | 371c Date |
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PCT/CA10/00697 | 5/5/2010 | WO | 00 | 11/2/2011 |