Patent Grant
8997895
Directional drilling has proven useful in facilitating the production of formation fluid, e.g., hydrocarbon-based fluid, from a variety of reservoirs. In application, a vertical wellbore is drilled, and directional drilling is employed to create one or more deviated or lateral wellbores extending outwardly from the vertical wellbore. Often, a whipstock is employed to facilitate the drilling of the one or more lateral wellbores in a method referred to as sidetracking.
If the formation being drilled is hard or formed of abrasive rock, diamond impregnated drill bits are used. The cuffing face of diamond impregnated drill bits include diamonds, e.g., natural or synthetic diamonds, which are distributed through a supporting material, sometimes referred to as matrix material. The distributed diamonds form an abrasive layer, and during operation of the drill bit, the diamonds within the abrasive layer become exposed as the supporting material wears away. As the supporting material continues to be worn away, new diamonds are exposed to enable long-term cutting capability for the diamond impregnated drill bit.
To facilitate directional drilling with an impregnated drill bit, the whipstock is used to guide the drill bit in a lateral direction to establish a lateral or deviated wellbore branching from the existing substantially vertical wellbore. Whipstocks are designed with a face, or ramp surface, oriented to guide the drill bit in the desired lateral direction. The whipstock is positioned at a desired depth in the wellbore and its face oriented to facilitate directional drilling, i.e., sidetracking, of the lateral wellbore along the desired drill path. In many applications, sidetracking requires at least two trips downhole. In an initial trip, a short multi-ramp whipstock is delivered downhole, oriented and set at the desired wellbore location. A bi-mill is then used in conjunction with the short multi-ramp whipstock to enable drilling of a few feet of rat hole. The bi-mill is then tripped out of the wellbore. In a subsequent trip, a drilling bottom hole assembly, with an impregnated drill bit and a turbodrill, is tripped downhole to complete the drilling of the lateral wellbore. However, each trip downhole beyond the initial trip increases both the time and costs associated with the drilling operation.
A system and method which facilitate the drilling of one or more lateral wellbores, e.g., by eliminating one or more trips downhole, are disclosed. In one or more embodiments, the system and method utilize a drilling assembly comprising an impregnated drill bit, a whipstock and a connector coupled therebetween. The impregnated drill bit has a body and a plurality of cutting surfaces or blades separated by junk slots or channels. At least a portion of the impregnated drill bit is of a diamond impregnated material. The impregnated drill bit is coupled to a whipstock by a connector which may be coupled directly to the impregnated drill bit or indirectly to the impregnated drill bit via a turbine sleeve. The connector includes a separation device which facilitates decoupling of the impregnated drill bit from the whipstock once the whipstock is anchored downhole at a desired location.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
Certain embodiments will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements. It should be understood, however, that the accompanying figures illustrate the various implementations described herein and are not meant to limit the scope of various technologies described herein, and:
In the following description, numerous details are set forth to provide an understanding of one or more embodiments of the invention. However, it will be understood by those of ordinary skill in the art that the one or more disclosed embodiments may be practiced without these details and that numerous variations or modifications from the disclosed embodiments may be possible.
The present disclosure generally relates to a system and method to facilitate the drilling of a lateral wellbore, i.e., sidetracking, by eliminating one or more downhole trips. By way of example, and not limitation, the sidetracking operation may be performed with respect to an open wellbore (i.e., non-cased portion of the wellbore) to create a lateral bore extending from the open wellbore. However, one or more embodiments of the present disclosure may also be utilized in cased hole sidetracking operations.
The system and method combine an impregnated drill bit, e.g., a diamond impregnated drill bit, with a whipstock assembly for deployment in a single downhole trip. While an impregnated drill bit is disclosed in one or more embodiments herein, a hybrid drill bit or matrix drill bit (e.g., without impregnation) may be equally employed, as will be readily understood by those skilled in the art. In one or more embodiments, the whipstock is coupled to the impregnated drill bit via a connector. The connector may be arranged and designed such that the whipstock of the whipstock assembly couples to the impregnated drill bit, or to a turbine sleeve, which is in turn coupled to the impregnated drill bit. The connector may also have a separation mechanism or device, which facilitates separation of the impregnated drill bit from the whipstock of the whipstock assembly once the whipstock assembly is positioned and anchored at the desired downhole location.
In one or more embodiments, the system comprises an impregnated drill bit coupled with a turbine sleeve which is tripped downhole with a turbine or turbodrill to facilitate sidetracking. The whipstock assembly is coupled to the impregnated drill bit through the turbine sleeve via a connector. The impregnated drill bit may be constructed with a support body of tungsten carbide, steel or other material known to those skilled in the art. The cutting surfaces, i.e., blades, of the impregnated drill bit may be constructed with a diamond impregnated matrix material. The turbine sleeve may be coupled to the impregnated drill bit in any known manner including, for example, welding. Additionally, the connector may be designed to fit partially or entirely within grooves, e.g., junk slots or channels, positioned on the impregnated drill bit and on the turbine sleeve. In one or more embodiments, the connector may also be designed to fit specific drill bits, e.g., known impregnated drill bit geometries. Such specificity is based on the blade count and/or corresponding junk slots/channels, which can vary from one drill bit to another. In these embodiments, the connector does not require any changes to the cutting structure/design of the impregnated drill bit itself. As will be disclosed hereinafter, the impregnated drill bit may be designed to provide a desired area along a junk slot or other surface thereof to accommodate a connector of a desired size and/or strength.
In one or more other embodiments, the connector is coupled between the whipstock of the whipstock assembly and a surface of the impregnated drill bit, i.e., a direct or semi-direct connection. As with other embodiments, the cutting surfaces, i.e., blades, of the impregnated bit may be constructed with a diamond impregnated matrix material. Also, the impregnated drill bit may be constructed with a support body of tungsten carbide, steel or other material known to those skilled in the art. As will be disclosed in greater detail herein, the support body may be specifically designed, e.g., with a desired profile or construction, to facilitate coupling between the connector and the impregnated drill bit. In such embodiments, the material of construction and its configuration are selected to provide sufficient strength to withstand the loads, e.g., tensile loads, encountered when shearing the connector or otherwise separating the impregnated drill bit from the whipstock assembly.
In the embodiments described above, the connector may be coupled to a upper end portion of a whipstock, which forms part of the whipstock assembly. For example, a lower end portion of the connector may be welded to an upper end portion of the whipstock. In one or more embodiments, the drill bit may be coupled to a bit motor or a turbine, e.g., via a threaded connection, prior to coupling of the connector.
The separation mechanism/device of the connector facilitates separation of upper and lower portions of the connector once the whipstock assembly is anchored or secured at the desired downhole location. By way of example, and not limitation, the separation mechanism or device may be a shear member, such as a shear bolt, which fastens two portions of the connector together. The separation mechanism or device may also be a shear portion/region, which is designed to shear upon application of a predetermined loading/force to the connector. Such shear portion/region may be a groove or notch disposed in a surface of the connector. After shearing, an upper portion of the connector remains coupled to the impregnated drill bit (i.e., within one or more junk slots or channels), which reduces the amount of shrapnel that would otherwise be milled by the impregnated drill bit during initial sidetracking operations.
Referring generally to
Lateral wellbore drilling system/assembly 20 may also comprise other components of a bottomhole assembly depending on the specifics of the drilling application. Examples of other bottomhole assembly components that may be coupled to the drill string above impregnated drill bit 22 include directional drilling and measurement equipment. While not shown in
Depending on the specific sidetracking operation to be performed, the whipstock assembly 24 may comprise a variety of components to facilitate anchoring of the whipstock 26 and guiding of the impregnated drill bit 22 during drilling of a lateral wellbore. By way of example, the whipstock assembly 24 may include a setting assembly (not shown) which facilitates the engagement of the whipstock 26 with a sidewall of the wellbore (not shown) when locating the whipstock 26 of the whipstock assembly 24 at a desired location within the wellbore. The setting assembly may utilize an anchor (not shown) having a relatively large ratio of expanded diameter to unexpanded diameter to facilitate anchor engagement with the wellbore sidewall. The anchor may employ a plurality of slips which are expandable between a running position (unexpanded) and an anchoring position (expanded). In at least some embodiments, the slips are hydraulically set by directing high pressure, hydraulic actuating fluid along a suitable passageway or conduit in or along the whipstock 26. Nevertheless, the setting assembly may utilize other systems/devices known to those skilled in the art to secure the whipstock 26 of the whipstock assembly 24 in the wellbore.
According to one embodiment, the lateral wellbore drilling system/assembly 20 is conveyed downhole to a desired location and rotated to the desired orientation in which to drill the lateral wellbore/borehole. Hydraulic fluid is then delivered downhole via a passageway 64 and/or a conduit 68 (see
With additional reference to
In one or more embodiments, and as best shown in
In the embodiment illustrated in
As previously disclosed, connector 28 has a longitudinal member 50 which includes the separation mechanism 30, e.g., shear region 32, disposed between an upper portion and a lower portion of the longitudinal member 50. The separation mechanism 30 is positioned just above the top end portion of whipstock 26 to minimize exposure while sidetracking. Thus, the separation mechanism/device 30 may be positioned and designed to shear generally flush or nearly flush with the top end portion of the whipstock 26 so as to leave minimal, if any, protrusion of the remaining lower portion of longitudinal member 50 above the top end portion of whipstock 26 after shearing. The lower portion of the longitudinal member 50 is secured to an upper end portion, e.g., the back, of whipstock 26. By way of example, the lower end portion of longitudinal member 50 may be secured to the upper end portion of the whipstock 26 by a suitable fastener 52. According to one embodiment, the lower portion of longitudinal member 50 is welded to the upper end portion of whipstock 26 such that the weldment serves as fastener 52. The upper portion of longitudinal member 50, which is coupled to turbine sleeve 34, may remain with the turbine sleeve 34 and the impregnated drill bit during the sidetracking drilling operation, e.g., disposed partially or fully within grooves/junk slots or channels 40, 44.
In another embodiment of the present disclosure, as illustrated in
The configuration of impregnated drill bit 22 may change depending on the specific drilling applications for which it is designed. In the embodiment illustrated in
Referring generally to
The tougher, e.g., harder, material 70 may be positioned along recess 56 into which pin 54 is received. By way of example, and not limitation, the tougher material 70 may be positioned radially inward relative to the surrounding material 72 along recess 56, e.g., recess 56 may be lined with the tougher material 70. In some embodiments, the material 70 is secured in place during formation of the drill bit 22. For example, the material 70 may comprise a metal material and the surrounding material 72 may comprise a metal carbide material held together by a binder used during formation, e.g., molding or casting, of the drill bit 22. The tougher material 70 may be thermally fused or otherwise fused with the surrounding material 72 during formation of the impregnated drill bit 22. However, the tougher material 70 may be formed as a separate component, e.g., a sleeve, which is brazed, adhered, secured by casting or otherwise secured at the desired location in impregnated drill bit 22.
Depending on the drilling application for which it is designed, the composite, impregnated drill bit 22 may comprise a variety of materials. By way of example, the material 70 that surrounds recess 56 may be a metal material, such as tungsten, steel, or another suitable metal. Depending on its properties, the material 70 may initially be in a powdered form prior to formation, e.g., molding, of drill bit 22. The surrounding material 72 may comprise a variety of materials or combinations of materials. For example, surrounding material 72 may comprise a metal carbide, such as tungsten carbide, and/or an impregnated material, such as a diamond impregnated material. In the embodiment illustrated, the blades 38 may be formed from an impregnated material 74, e.g., a diamond impregnated material, which may be molded from a suitable diamond premix. Also in this embodiment, the body 27 or portions of the body 27 may be formed from a metal carbide material 76, such as a tungsten carbide material.
In some embodiments, other portions of the impregnated drill bit 22 may comprise other materials, such as a steel blank section 78. However, the various materials are provided as examples and the specific types of materials and/or combinations of materials may change from one drilling application to another. In any of these embodiments, the tougher material 70 positioned in the impregnated drill bit 22 around the connector 28 prevents the potentially detrimental effects of contact stresses incurred during deployment of and/or separation from the whipstock 26.
The drill bit 22 and the related components designed to facilitate deployment of whipstock 26 may be adjusted according to the parameters of a given deployment operation. In the embodiment illustrated, for example, the secondary flow passage 68, e.g., a hydraulic conduit or hose, is deployed through drill bit 22 along central flow passage 64. During deployment, the central flow passage 64 may be blocked by a suitable blocking member 80, e.g., a burst disc, which may be positioned in an upper section 82 of the drill bit. The blocking member 80 is designed to prevent flow of fluid along passage 64 during deployment and setting of the whipstock 26.
In any of the embodiments described above with respect to
The drilling system/assembly 20 (
In operation, the drilling system/assembly 20 is tripped downhole with the whipstock assembly 24 secured to the impregnated drill bit 22 via connector 28. In a variety of drilling applications, the drilling assembly 20 and the whipstock assembly 24 are delivered downhole into a wellbore that is open and thus not lined with a casing. Once at the desired downhole wellbore location, the whipstock 26 is oriented. By way of example, the whipstock 26 may be oriented with the aid of a measurement-while-drilling/gyro system. The whipstock 26 is then set by anchoring the whipstock assembly 24 via, for example, an expandable slip style anchor. After setting the whipstock 26, the impregnated drill bit 22 is released, e.g., sheared, from the whipstock assembly 24 by separating, e.g., shearing, the connector 28 via separation mechanism/device 30. The drilling assembly 20 may be disengaged or released from the whipstock 26 by pulling on the drilling assembly 20 to shear the connector 28 via separation mechanism/device 30 at shear region 32. If employed in the system/assembly 20, the turbodrill 36 or bit motor (e.g., positive displacement motor) may be unlocked, and a bent housing of the drilling system/assembly 20 may be oriented to point the impregnated drill bit 22 away from the whip face of the whipstock 26. The impregnated drill bit 22 is then operated to perform the directional drilling operation, i.e., sidetracking, in which a lateral wellbore is at least partially formed along a desired path to a target destination.
In this disclosure, several embodiments have been described in detail. However, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this disclosure. Accordingly, such modifications are intended to be included within the scope of this invention.
The present document is based on and claims priority to U.S. Provisional Patent Application Ser. No. 61/476,013, filed on Apr. 15, 2011, the disclosure of which is incorporated by reference herein in its entirety.
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