The present application is a U.S. National Stage patent application of International Patent Application No. PCT/US2017/049546, filed on Aug. 31, 2017, the benefit of which is claimed and the disclosure of which is incorporated herein by reference in its entirety.
The present disclosure relates generally to a method of drilling a wellbore, and specifically, to a method of enlarging the diameter of the wellbore using a point-the-bit bottom hole assembly having a reamer to reduce dogleg capability associated with the bottom hole assembly and/or reduce wellbore tortuosity.
Directional drilling operations involve controlling the direction of a wellbore as it is being drilled. Generally, the goal of directional drilling is to reach a target subterranean destination with a drill string, and often the drill string will need to be turned through a tight radius to reach the target destination. Generally, a rotary steerable tool or a mud motor that forms a portion of the bottom hole assembly (“BHA”) is used to steer the BHA to create a curved section of the wellbore. Often, the rotary steerable tool and mud motor are fixed, when run downhole, at a given bend angle or displacement that embodies the maximum dogleg capability of the bottom hole assembly. There are instances when the maximum dogleg capability is not needed, such as when the drill string is creating a generally straight section of the wellbore and/or when the radius of a required turn is not as tight as the radius associated with the maximum dogleg capability. In these instances and when a point-the-bit bottom hole assembly with a fixed maximum dogleg capability is used, large lateral forces are exerted on the drill bit, bearings, stabilizers, pads, etc., resulting in very high stresses on housings, shafts, mandrels, internal connections, external connections, etc. of the rotary steerable tool or mud motor. These high forces and stresses can lead to equipment failures, non-productive time, and potentially the loss of a well. In addition, transitions from steering to straight drilling and vice-versa impart significant tortuosity to the wellbore.
Various embodiments of the present disclosure will be understood more fully from the detailed description given below and from the accompanying drawings of various embodiments of the disclosure. In the drawings, like reference numbers may indicate identical or functionally similar elements.
Illustrative embodiments and related methods of the present disclosure are described below as they might be employed using a point-the-bit bottom hole assembly with reamer. In the interest of clarity, not all features of an actual implementation or method are described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. Further aspects and advantages of the various embodiments and related methods of the disclosure will become apparent from consideration of the following description and drawings.
Referring to
The wellbore 75 includes any one or more of a vertical section 75a, a curved section 75b, a tangent section 75c, and a horizontal section 75d. The wellbore 75 may be an uphill wellbore and/or include multilateral wellbores. Accordingly, it should be understood by those skilled in the art that the use of directional terms such as “above,” “below,” “upper,” “lower,” “upward,” “downward,” “uphole,” “downhole” and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well, the downhole direction being toward the toe of the well. Also, even though
A point-the-bit bottom hole assembly 85, or the BHA 85, is coupled to the lower or distal end of the drill string 70 and includes a drill bit 90 that is operably coupled to a steering tool 95, such as a mud motor or a rotary steerable system, suitable for selectively changing a direction of drilling by the BHA 85. A reamer 100 also forms a portion of the BHA 85 and is coupled to, and positioned between, the drill bit 90 and the steering tool 95. This positioning between includes the reamer 100 being built into or forming a portion of the drill bit 90, and thus positioned below the steering tool 95; the reamer 100 being built into or forming another tool that is positioned between the drill bit 90 and the steering tool 95; and the reamer 100 being built into a lower end of the steering tool 95. Generally, the reamer 100 is positioned downhole from the “bend” in the steering tool 95. The reamer 100 may be any wellbore diameter enlargement device and may be a single actuation reamer or a multi-actuation reamer such that the reamer 100 can be activated and deactivated multiple times. Generally, the reamer 100 includes reamer cutting structures 100a and 100b that, when activated, extend radially in a direction perpendicular to a longitudinal axis of the reamer 100 to contact a wall of the wellbore 75 and enlarge the diameter of the wellbore 75. While only two reamer cutting structures are shown in
Often, the wellbore 75 will have a planned trajectory such that the curved section 75b is associated with a dogleg, such as for example 10 degrees per 100 ft. In these instances, and when the bend angle 102 of the steering tool 95 is fixed prior to being run downhole, the bend angle 102 (along with the other factors that determine dogleg capability) is often set to be in excess of what is needed to accomplish the 10 degrees per 100 ft. Thus, the bend angle 102 is often capable of producing a dogleg capability of, for example, 12 or 13 degrees per 100 ft. Having excess dogleg capability provides the capacity to catch up to the planned wellbore path or trajectory if the drilled wellbore gets behind the plan for any reason, but also can result in the multiple transitions from steering to drilling straight sections in order to create a curved section that has a dogleg that is less than the fixed dogleg capability that is associated with the BHA 85. Activating the reamer 100 to enlarge a diameter of the wellbore decreases the fixed dogleg capability associated with the BHA 85 to reduce the number of transitions from steering to drilling straight when creating a curved section and to reduce the stresses exerted on the BHA 85 during such transitions and when drilling straight sections.
In some embodiments and generally when the steering tool 95 is a mud motor, the drilling string 70 is not rotated during steering of the BHA 85 such that the orientation of the steering tool 95 in the wellbore 75 is stationary. However, in other embodiments and generally when the steering tool 95 is a rotary steerable system, the drilling string 70 is rotated while steering of the BHA 85, but the orientation of the steering tool 95 in the wellbore 75 is stationary. Generally, when drilling a straight section of the wellbore 75, the drilling string 70 and the BHA 85 rotate together or at least the orientation of the BHA 85 in the wellbore 75 is not stationary.
In an exemplary embodiment, as illustrated in
The step 110 includes the sub steps of creating, using the drill bit 90, the wellbore 75 having an original diameter illustrated by the dimension having the reference numeral 75e in
When it is desired to create a portion of the wellbore that has a radius of curvature that is greater than the first radius of curvature, the reamer cutting structures 100a and 100b are deployed or activated such that the reamer 100 is in the second configuration to enlarge the original wellbore 75e to an enlarged diameter illustrated by the dimension having numeral 75f in
The step 115 includes the sub steps of the step 110a, enlarging the diameter of the wellbore 75 to the enlarged diameter 75f at step 115a, and laterally offsetting the steering tool 95 in the enlarged diameter 75f of the wellbore 75 at step 115b.
The step 120 includes the sub steps of the steps 110a, 115a, and 115b, and is similar to the step 115 except that the step 115 occurs during steering of the BHA 85 and the step 120 occurs when the BHA 85 rotates to drill a straight section. Thus, the step 120 results in a generally straight section of the wellbore 75.
Any variety of wellbore diameter enlarging tools can be used in place of the reamer 100. In some cases, a single actuation of the reamer 100 may be acceptable. For example, once the curved section 75b is drilled using the first dogleg capability (i.e., the reamer 100 in the first configuration), the reamer 100 may be irreversibly activated such that the reamer cutting structures 100a and 100b are moved outward to enlarge the wellbore for the remainder of the bitrun in order to drill with a dogleg capability that is less than the first dogleg capability associated with the BHA 85 while in the first configuration. Examples of single, irreversible activation of the reamer 100 include the use of shear pins based on high differential pressure and ball drops.
In some embodiments, a control unit 150 as illustrated in
While the bend angle 102 of the steering tool 95 described by way of example as being fixed when downhole, a tool may alternately include an adjustable bend angle, in which case, one or more embodiments of the steering tool 95 may have at least a straight mode with zero or near zero bend angle or displacement that can alternate between deflected and straight modes downhole. Optionally, the bend angle may be selectively adjustable to any of a range of values. Use of the steering tool 95, when the steering tool 95 has the ability to alternate between deflected and straight modes downhole, in the method 105 results in the creation of intermediate dogleg capabilities when the diameter of the wellbore 75 is enlarged.
Moreover, another embodiment of the steering tool 95 has self-adjusting dogleg capabilities. Use of the steering tool 95, when the steering tool 95 has self-adjusting dogleg capabilities, in the method 105 results in the reduction of the dogleg capability when the diameter of the wellbore 75 is enlarged.
In an exemplary embodiment, creating a generally straight section of the wellbore includes creating a section of the wellbore that is intended to be generally straight but includes some deviations.
In several exemplary embodiments, the method 105 may be implemented in whole or in part by a computer. The plurality of instructions stored on the computer readable medium 150b, the plurality of instructions stored on the computer readable medium 155b, a plurality of instructions stored on another computer readable medium, and/or any combination thereof, may be executed by a processor to cause the processor to carry out or implement in whole or in part the method 105, and/or to carry out in whole or in part the above-described operation of the BHA 85. In several exemplary embodiments, such a processor may include the one or more processors 150a, the one or more processors 155a, one or more additional processors, and/or any combination thereof.
As noted above, having excess dogleg capability provides the capacity to catch up to the planned wellbore path or trajectory if the drilled wellbore gets behind the plan for any reason. Use of the BHA 85 and/or the method 105 allows for the use of the excess bend angle when necessary, but otherwise reduces the effects of the excess bend angle when the excess bend angle is not required. Thus, when creating the curved section 75b, the BHA 85 creates a curved section having a radius of curvature that is greater than the radius of curvature associated the excess bend angle. This reduces the need for approximating the desired curve by creating alternate segments of the wellbore 75 when steering to create a curvature is too tight and drilling straighter segments. Thus, the BHA 85 and/or the method 105 reduces the number of transitions from steering drilling to straight drilling. Transitions from steering to straight drilling involves “back-bending”, or forcing the bend angle 102 against the curvature created during steering as the bend angle 102 is rotated. Large lateral forces on the drill bit 90, bearings, stabilizers, etc. are exerted during “back-bending” and result in very high stresses on housings, shafts mandrels, internal connections, external connections, etc. of the steering tool 95 (e.g., rotary steerable tool or mud motor). These high forces and stresses can lead to equipment failures, non-productive time, and potentially the loss of a well. In addition, transitions from steering to straight drilling and vice-versa can impart significant tortuosity to the wellbore 75. Wellbore tortuosity creates higher contact forces with the BHA 85 and/or the drill string 70, increasing frictional drag which inhibits weight transfer to the drill bit 90, which impedes drilling ahead, drilling long tangent or horizontal/lateral sections beyond the curve, and running casing and completions equipment. Thus, as the BHA 85 and/or the method 105 reduces the number of transitions from steering to straight drilling, the BHA 85 and/or the method 105 reduces lateral forces on the BHA 85, such as on the drill bit 90, bearings, stabilizers, etc. and reduces the associated stresses on the BHA 85, such as on housings, shafts, mandrels, internal connections, external connections, etc. Moreover, use of the BHA 85 and/or the method 105 reduces wellbore tortuosity. Moreover, when the drill string 70 extends within or through the enlarged diameter wellbore 75f, friction forces acting on the drill string 70 due to the contact with a wall of the wellbore 75 are generally less than friction forces acting on the drill string 70 when the drill string 70 extends through the original diameter wellbore 75e.
The BHA 85 and/or the method 105 results in the ability to have a high dogleg capability for the curved section 75b of the wellbore 75 and a reduced dogleg capability for making corrections in other portions of the wellbore 75 thereby creating a multi-dogleg-capability BHA 85. The multi-dogleg-capability 85 reduces equipment failures, non-productive time, and potentially the loss of a well. The multi-dogleg-capability BHA 85 reduces frictional drag, which improves weight transfer to the drill bit 90 which supports drilling ahead, drilling long tangent or horizontal/lateral sections beyond the curve, and running casing and completions equipment.
In some embodiments and if the diameter of the wellbore 75 is enlarged sufficiently, the effect of the bend angle 102 on dogleg capability can be completely overcome. Enlarging the diameter of the wellbore 75 provides room for the contact points, such as 95b of the steering tool 95 or other contact points of the BHA 85, to shift laterally, which reduces the effect of the bend angle 102 on the side-cutting force or leverage applied to the drill bit 90 and thereby results in a lower dogleg capability.
In some embodiments, the BHA 85 and/or the method 105 reduces the number of bitruns for each well as the BHA 85 is capable of creating a variety of segments of the well (e.g., the vertical section 75a, the curved section 75b, the tangent section 75c, the horizontal section 75d) while reducing stresses on the BHA 85 and reducing wellbore tortuosity.
Thus a method has been described. Embodiments of the method may generally include extending a wellbore using a drill bit; enlarging a diameter of the wellbore using a first tool; and laterally offsetting a second tool in the enlarged diameter wellbore; wherein the first tool, the second tool, and the drill bit are coupled together such that the first tool is positioned between the drill bit and the second tool; and wherein a bend angle is defined between a central axis of the second tool and a central axis of the drill bit. Any of the foregoing embodiments may include any one of the following elements, alone or in combination with each other:
Thus a method has been described. Embodiments of the method may generally include extending a wellbore, using a drill bit and a mud motor having a bend angle, while simultaneously enlarging a diameter of the wellbore using a reamer positioned between at least a portion of the drill bit and at least a portion of the mud motor. Any of the foregoing embodiments may include any one of the following elements, alone or in combination with each other:
Thus, a point-the-bit BHA has been described. Embodiments of the BHA may generally include a drill bit; a mud motor operably coupled to the drill bit; and a reamer positioned between one end of the mud motor and the drill bit. Any of the foregoing embodiments may include any one of the following elements, alone or in combination with each other:
The foregoing description and figures are not drawn to scale, but rather are illustrated to describe various embodiments of the present disclosure in simplistic form. Although various embodiments and methods have been shown and described, the disclosure is not limited to such embodiments and methods and will be understood to include all modifications and variations as would be apparent to one skilled in the art. Therefore, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed. Accordingly, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the disclosure as defined by the appended claims.
In several exemplary embodiments, while different steps, processes, and procedures are described as appearing as distinct acts, one or more of the steps, one or more of the processes, and/or one or more of the procedures could also be performed in different orders, simultaneously and/or sequentially. In several exemplary embodiments, the steps, processes and/or procedures could be merged into one or more steps, processes and/or procedures.
It is understood that variations may be made in the foregoing without departing from the scope of the disclosure. Furthermore, the elements and teachings of the various illustrative exemplary embodiments may be combined in whole or in part in some or all of the illustrative exemplary embodiments. In addition, one or more of the elements and teachings of the various illustrative exemplary embodiments may be omitted, at least in part, and/or combined, at least in part, with one or more of the other elements and teachings of the various illustrative embodiments.
In several exemplary embodiments, one or more of the operational steps in each embodiment may be omitted. Moreover, in some instances, some features of the present disclosure may be employed without a corresponding use of the other features. Moreover, one or more of the above-described embodiments and/or variations may be combined in whole or in part with any one or more of the other above-described embodiments and/or variations.
Although several exemplary embodiments have been described in detail above, the embodiments described are exemplary only and are not limiting, and those skilled in the art will readily appreciate that many other modifications, changes and/or substitutions are possible in the exemplary embodiments without materially departing from the novel teachings and advantages of the present disclosure. Accordingly, all such modifications, changes and/or substitutions are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.
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