Patent Application
20210254447
The present invention relates to the field of directional drilling, and in particular to a downhole tool for controlling the build of drilling apparatus.
Directional drilling involves controlling the direction of a wellbore as it is being drilled. Directional drilling typically utilizes a combination of three basic techniques, each of which presents its own special features. First, the entire drill string may be rotated from the surface, which in turn rotates a drilling bit connected to the end of the drill string. This technique, sometimes called “rotary drilling,” is commonly used in non-directional drilling and in directional drilling where no change in direction during the drilling process is required or intended. Second, the drill bit may be rotated by a downhole motor that is powered, for example, by the circulation of fluid supplied from the surface. This technique, sometimes called “slide drilling,” is typically used in directional drilling to effect a change in direction of a wellbore, such as in the building of an angle of deflection, and almost always involves the use of specialized equipment in addition to the downhole drilling motor. Third, rotation of the drill string may be superimposed upon rotation of the drilling bit by the downhole motor. Additionally, a new method of directional drilling has emerged which provides steering capability while rotating the drill string, referred to as a rotary steerable system.
The most common way to directional drill is through the use of a bend near the bit in a downhole steerable mud motor. Directional drilling is accomplished with the alternating combination of two drilling operations. In the sliding mode, the drill string is slowly rotated to orient the bend in the desired direction so that the bend points the bit in a direction different from the axis of the wellbore. Once oriented, the bit turns by pumping mud through the mud motor, while the drill string does not rotate but rather slides, allowing the bit to drill in the direction it points. When a particular wellbore direction is achieved, that direction may be maintained by rotating the entire drill string so that the bit does not drill in a single direction off the wellbore axis, but instead sweeps around and its net direction coincides with the existing wellbore.
This technique has required operators to maintain an inventory of downhole tools with different bend angles to accommodate different amounts of “build rate” while drilling. In directional drilling, higher build motors allow for more rapid changes in the direction of the wellbore. However, higher build rates can result in higher loads on the drill string, due to increased doglegs and more severe wellbore spiraling. Further, large bend angle motors experience larger lateral loads while rotating and as such pipe fatigue becomes a concern. A too small bend angle limits the driller's ability to follow a planned well path or to make corrections when deviations occur. Changing the bend angle would require pulling the bottom hole assembly and refitting with a new downhole tool with a different amount of bend, which is a costly and time-consuming project.
The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems outlined above.
In one aspect, a downhole tool for use in directional drilling comprises an outer housing having an opening; an insert disposed within the outer housing, comprising: a piston; and a pad disposed radially outward of the piston, wherein extension of the piston urges the pad outward through the opening of the outer housing for engagement with a wellbore and increasing build rate while drilling; an electric motor, configured to cause extension of the piston; and circuitry configured to control the electric motor upon receipt of a command received from uphole.
In another aspect, a method of changing build rate while directionally drilling comprises receiving by a downhole tool a first command to increase build rate from uphole; extending a pad outward from the downhole tool responsive to the first command; and engaging the pad with a wellbore.
The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate an implementation of apparatus and methods consistent with the present invention and, together with the detailed description, serve to explain advantages and principles consistent with the invention. In the drawings,
In the following description, for purposes of explanation, numerous specific details are set forth in order to provide a thorough understanding of the invention. It will be apparent, however, to one skilled in the art that the invention may be practiced without these specific details. In other instances, structure and devices may be shown in block diagram form in order to avoid obscuring the invention. References to numbers without subscripts are understood to reference all instance of subscripts corresponding to the referenced number. Moreover, the language used in this disclosure has been principally selected for readability and instructional purposes, and may not have been selected to delineate or circumscribe the inventive subject matter, resort to the claims being necessary to determine such inventive subject matter. Reference in the specification to “one embodiment” or to “an embodiment” means that a particular feature, structure, or characteristic described in connection with the embodiments is included in at least one embodiment of the invention, and multiple references to “one embodiment” or “an embodiment” should not be understood as necessarily all referring to the same embodiment.
The terms “a,” “an,” and “the” are not intended to refer to a singular entity unless explicitly so defined, but include the general class of which a specific example may be used for illustration. The use of the terms “a” or “an” may therefore mean any number that is at least one, including “one,” “one or more,” “at least one,” and “one or more than one.”
The term “or” means any of the alternatives and any combination of the alternatives, including all of the alternatives, unless the alternatives are explicitly indicated as mutually exclusive.
The phrase “at least one of” when combined with a list of items, means a single item from the list or any combination of items in the list. The phrase does not require all of the listed items unless explicitly so defined.
In this description, the term “couple” or “couples” means either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection or through an indirect connection via other devices and connections. The recitation “based on” means “based at least in part on.” Therefore, if X is based on Y, X may be a function of Y and any number of other factors.
In describing various locations relative to the Figures the term “downhole” refers to the direction along the axis of the wellbore that looks toward the furthest extent of the wellbore. Downhole is also the direction toward the drill bit location. Similarly, the term “lower end” refers to the portion of the assembly located at the downhole end of the respective assembly. The term “uphole” refers to the direction along the axis of the wellbore that leads back to the surface, or away from the drill bit. Similarly, the term “upper end” refers to the portion of the assembly located at the uphole end of the respective assembly. The term “clockwise” refers to rotation to the right as seen looking downhole and the term “counterclockwise” refers to rotation to the left as seen looking downhole. In a situation where the drilling is more or less along a vertical path, downhole is truly in the down direction, and uphole is truly in the up direction. However, in horizontal drilling, the terms up and down are ambiguous, so the terms downhole and uphole are necessary to designate relative positions along the drill string.
By providing a downhole tool that can alternately extend a pad outward from the tool and retract the pad inward to the tool, a variable build downhole tool allows changing the build rate while directional drilling without the delays, cost, and risks involved in pulling fixed build tools from the wellbore. By extending a pad near the bend point, the lateral forces on the bit are increased, thereby increasing the build rate.
Beginning with
In this embodiment, a pad 110 is mounted on the insert 145 through an opening in the outer housing 125. The pad may be made of a suitable steel for use downhole with a surface application of wear-resistant material such as carbide hardfacing, carbide tiles, thermally stable polycrystalline (TSP) diamond, or some combination known to the industry to reduce abrasion effects of contact with the borehole. In operation, the pad 110 may be extended outward from the insert 145 to increase the build rate and retracted inward to decrease the build rate. One or more pistons 115 may be used to push the pad 110 outwardly, causing the build rate to increase when in operation. As illustrated in
The amount of extension of the pad 110 may be any desired amount, although the amount of extension is typically small, such as approximately ⅝ inch. By extending the pad 110 to engage with a wellbore wall, the build rate of the variable build motor tool 100 may be increased. When the pad 110 is retracted, the build rate may be decreased. By changing the build rate, the rate of change of the curvature of the wellbore being drilled may be correspondingly changed.
In one embodiment, pressure pulses in the drilling fluid may be used to send a command to the variable build motor tool 100 to change the position of the pad 110, causing an increase or decrease in the build rate of the variable build motor tool 100. Any desired pressure change or series of pressure changes may be used, preferably one that would not occur during ordinary operation while drilling. A pressure sensor (not illustrated in the Figures) may be used to detect the pressure pulses by the variable build motor tool 100's onboard electrical system.
Alternately, or in combination with the pressure pulses, a change in rotation or a sequence of changes in rotation may be used as an indication of a command. For example, in one embodiment to cause the pad 110 to extend outwardly, the drill string may be rotated at a static rotational speed, such as 30 rpm. An example command may comprise causing rotation to be stopped for 5 seconds, then rotation to be restarted at 10 rpm. In such an embodiment, an accelerometer or other device for detecting rotation or changes in rotation may be included in the onboard electrical control system. As with use of pressure changes as a command signal, the rotational changes used to command extension of the pad 110 preferably are a sequence of rotation changes not likely to occur in normal operational drilling practice.
In one embodiment, while the pad 110 is being extended, pumping drilling fluid through the well bore may be stopped or reduced, to reduce the amount of force needed for electric motor 215 to adjust a valve 205 in order to energize the pistons 115. The pistons 115 are energized based off of the differential pressure between bore-side and annulus-side, created by the pressure drop across the motor 215. After the pad 110 has extended, pumping of drilling fluid may be restarted or brought back to the normal pressure. The balance pistons 105, also known as an energizing piston, is used to balance pressure on the uphole and downhole side of the balance piston 105 to accommodate the change in volume of drilling fluid being pumped downhole.
As illustrated in
The sealing piston 205 is positioned by electric motor 215. When piston is in the position illustrated in
Ball screw assembly 210 may be driven by an electric motor 215, typically a brushless direct current motor or a stepper motor, although other types of motors may be used. The use of a ball screw assembly is illustrative and by way of example only, and any other type of piston mechanism may be driven by the electric motor 215. Other means of moving sealing piston 205, such as a solenoid may be used in place of an electric motor 215. A sealed bulkhead 220 may be provided to allow wires to carry power and control signals from the battery pack 130 and other electronics which are disposed behind the bulkhead 220, with wires (omitted from the drawing for clarity) traversing the bulkhead 220. A bulkhead carrier 230 may be used for mounting the bulkhead in place. The bulkhead 220 prevents electronics and batteries from being exposed to pressure.
Flow diverter 240 is provided to allow drilling fluid to traverse the bore 160. The flow diverter 240 is configured to provide a designed pressure drop in the bore 160. Inlets 140 are formed in the uphole end of flow diverter 240 (sometimes referred to as a driveshaft cap, since it is used for driving driveshaft 170). Fluid flows through opening 250 into bore 160 as constrained by the size of the opening 250. The flow diverter 240 may be slotted with slot 270 to ensure pressure transmission to the balance piston(s) 105.
A mud motor 235 may be provided to support radial and thrust weight of a further downhole drill bit onto the outer housing. As mud motors are well known in the art, no further description of the mud motor 235 should be required for the person of ordinary skill in the art. A flow restrictor 225 may be used to limit mud flow through the bearings of the mud motor 235 and to ensure there is enough pressure available to actuate pad pistons 115.
Also illustrated in
Motor electronics may detect the movement stoppage, such as detecting an increase in current draw by the motor, and stop the motor from trying to extend or retract the ball screw assembly 210 further. This allows a simple mechanism for limiting how far the ball screw assembly 210 extends, without the need for the motor electronics to know the current position of the ball screw assembly 210, since the motor may simply be run until the stop is hit.
Action of the pad 110 according to one embodiment is also illustrated in
Turning now to
The use of two slots 520 on opposite sides of the electric motor 215 allows easier engagement by the anti-rotation pin 510, since a maximum of 180° rotation would be required to align one of the slots 520 with the anti-rotation pin 510. However, other embodiments could use only a single slot 520. Other techniques for positioning and holding the electric motor 215 in place can be used. Pad 110, piston sleeve 310, and piston 115B are visible in this cross section taken at G-G.
By providing a movable pad 110 that can be activated downhole upon command, the variable build motor tool 100 allows a drilling operator to vary the build rate when desired, without tripping the drill string, with all of the costs, delays, and risks that are involved in that process, just to replace a sub with a different sub having a different amount of build rate.
While certain exemplary embodiments have been described in detail and shown in the accompanying drawings, such embodiments are merely illustrative of and not devised without departing from the basic scope thereof, which is determined by the claims that follow.
