Using Rotary Steerable System Drilling Tool Based on Dogleg Severity

Abstract

Various implementations directed to using a rotary steerable system (RSS) drilling tool based on dogleg severity are provided. In one implementation, a method may include receiving a predetermined dogleg severity for a portion of a wellbore to be drilled using the RSS drilling tool. The method may also include determining a first displacement of actuators of the RSS drilling tool from a housing of the RSS drilling tool based on the predetermined dogleg severity. The method may further include activating the actuators based on the first displacement. The method may additionally include receiving displacement data from position sensors disposed in the RSS drilling tool during drilling of the portion of the wellbore, where the displacement data corresponds to a second displacement of the actuators from the housing. The method may also include activating the actuators based on the displacement data.

Description

BACKGROUND

This section is intended to provide background information to facilitate a better understanding of various technologies described herein. As the section's title implies, this is a discussion of related art. That such art is related in no way implies that it is prior art. The related art may or may not be prior art. It should therefore be understood that the statements in this section are to be read in this light, and not as admissions of prior art.

Directional drilling for the exploration and development of oil and gas fields advantageously provides the capability of generating boreholes which deviate significantly relative to the vertical direction (that is, perpendicular to the Earth's surface) by various angles and extents but generally follow predetermined profiles. In certain circumstances, directional drilling is used to provide a borehole which avoids faults or other subterranean structures (e.g., salt dome structures). Directional drilling is also used to extend the yield of previously-drilled wells by milling through the side of the previously-drilled well and reentering the formation, and drilling a new borehole directed so as to follow the hydrocarbon-producing formation. Directional drilling can also be used to provide numerous boreholes beginning from a common region, each with a shallow vertical portion, an angled portion extending away from the common region, and a termination portion which can be vertical. This use of directional drilling is especially useful for offshore drilling, where the boreholes are drilled from the common region of a centrally positioned drilling platform.

Directional drilling is also used in the context of substantially horizontal directional drilling (“HDD”) in which a pathway is drilled for utility lines for water, electricity, gas, telephone, and cable conduits. Exemplary HDD systems are described by Alft et al. in U.S. Pat. Nos. 6,315,062 and 6,484,818. HDD is also used in oilfield and gasfield exploration and development drilling.

A rotary steerable system (RSS) drilling tool is a type of directional drilling tool which allows for directional drilling of boreholes while allowing or maintaining rotation of the drill string. This technique can provide improved directional control, improved hole cleaning, and improved borehole quality, and may generally minimize drilling problems as compared to earlier technologies. Such tools may include steering mechanisms enabling controlled changes in borehole direction.

In some scenarios, the dogleg for one or more sections of the wellbore drilled by the RSS drilling tool may need to be monitored. A dogleg is a section in a wellbore in which the trajectory of the wellbore changes. The severity of such trajectory changes (i.e., dogleg severity) can be expressed in terms of degrees per unit length (e.g., per 100 feet) or alternatively in terms of the radius of curvature. Maintaining the curvature or dogleg severity as close to a well plan as possible may help to maximize the amount of usable wellbore and may improve completion and production of the final wellbore.

SUMMARY

Described herein are implementations of various technologies relating to using a rotary steerable system (RSS) drilling tool based on dogleg severity. In one implementation, a method for controlling dogleg severity for a portion of a wellbore using a RSS drilling tool disposed in the wellbore may include receiving a predetermined dogleg severity for the portion of wellbore to be drilled using the RSS drilling tool. The method may also include determining at least a first displacement of one or more actuators of the RSS drilling tool from a housing of the RSS drilling tool based on the predetermined dogleg severity. The method may further include activating the one or more actuators based on at least the first displacement. The method may additionally include receiving displacement data from one or more position sensors disposed in the RSS drilling tool during drilling of the portion of the wellbore, where the displacement data corresponds to at least a second displacement of the one or more actuators from the housing. The method may also include activating the one or more actuators based on the displacement data.

In another implementation, a method for controlling dogleg severity for a portion of a wellbore using a RSS drilling tool disposed in the wellbore may include receiving a predetermined dogleg severity for the portion of wellbore to be drilled using the RSS drilling tool. The method may also include determining at least a first displacement of a shaft of the RSS drilling tool from a housing of the RSS drilling tool based on the predetermined dogleg severity. The method may further include activating one or more actuators of the RSS drilling tool based on at least the first displacement. The method may additionally include receiving displacement data from one or more position sensors disposed in the RSS drilling tool during drilling of the wellbore, where the displacement data corresponds to at least a second displacement of the shaft from the housing. The method may also include activating the one or more actuators of the RSS drilling tool based on the displacement data.

In yet another implementation, a system may include a RSS drilling tool disposed in a wellbore, where the RSS drilling tool includes one or more actuators and one or more position sensors disposed in a housing of the RSS drilling tool. The system may also include a processor and a memory, where the memory may include a plurality of program instructions which, when executed by the processor, cause the processor to receive a predetermined dogleg severity for a portion of the wellbore to be drilled using the RSS drilling tool. The memory may also include a plurality of program instructions which, when executed by the processor, cause the processor to determine at least a first displacement of the one or more actuators of the RSS drilling tool from the housing based on the predetermined dogleg severity. The memory may further include a plurality of program instructions which, when executed by the processor, cause the processor to activate the one or more actuators based on at least the first displacement. The memory may additionally include a plurality of program instructions which, when executed by the processor, cause the processor to receive displacement data from the one or more position sensors during drilling of the portion of the wellbore, where the displacement data corresponds to at least a second displacement of the one or more actuators from the housing. The memory may also include a plurality of program instructions which, when executed by the processor, cause the processor to activate the one or more actuators based on the displacement data.

The above referenced summary section is provided to introduce a selection of concepts in a simplified form that are further described below in the detailed description section. The summary is not intended to identify key features or essential features of the claimed subject matter, nor is it intended to be used to limit the scope of the claimed subject matter. Furthermore, the claimed subject matter is not limited to implementations that solve any or all disadvantages noted in any part of this disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

Implementations of various techniques will hereafter be described with reference to the accompanying drawings. It should be understood, however, that the accompanying drawings illustrate only the various implementations described herein and are not meant to limit the scope of various techniques described herein.

FIG. 1 illustrates a cross-sectional schematic diagram of a rotary steerable system (RSS) drilling tool configured to be disposed in a wellbore in accordance with implementations of various techniques described herein.

FIG. 2 illustrates a close-up, cross-sectional schematic diagram of the steering subsystem of the tool in accordance with implementations of various techniques described herein.

FIG. 3 illustrates a close-up, cross-sectional schematic diagram of the section of the drilling tool in accordance with implementations of various techniques described herein.

FIG. 4 illustrates a schematic diagram of a drill string disposed within a wellbore in accordance with implementations of various techniques described herein.

FIG. 5 illustrates a cross-sectional schematic diagram of the RSS drilling tool configured to be disposed in the wellbore in accordance with implementations of various techniques described herein.

FIG. 6 illustrates a geometric diagram of a portion of the RSS drilling tool in accordance with implementations of various techniques described herein.

FIG. 7 illustrates a geometric diagram of a portion of the RSS drilling tool in accordance with implementations of various techniques described herein.

FIG. 8 illustrates a flow diagram of a method for controlling the dogleg severity of a wellbore using a RSS drilling tool in accordance with implementations of various techniques described herein.

FIG. 9 illustrates a schematic diagram of a computing system in which the various technologies described herein may be incorporated and practiced.

DETAILED DESCRIPTION

Various implementations directed to using a rotary steerable system (RSS) drilling tool based on dogleg severity will now be described in the following paragraphs with reference to FIGS. 1-9.

As noted above, a rotary steerable system (RSS) drilling tool is a type of directional drilling tool which allows for directional drilling of wellbores while allowing for the, or the maintaining of the, rotation of the drill string. In particular, as is known in the art, the RSS drilling tool may approximate the path of a wellbore by pointing or pushing the drill bit in a desired direction. Such a tool may be able to drill a curve or maintain a straight path for the wellbore.

While drilling, it may be important to estimate a current trajectory of the wellbore for comparison against a planned trajectory of the wellbore. In particular, it may be desirable to maintain the current wellbore trajectory contained within specified limits of the planned trajectory, such as limits on inclination angle or distance from the planned trajectory.

The trajectory parameters of the wellbore drilled by a RSS drilling tool that may be monitored and controlled include the wellbore dogleg. As noted above, a dogleg is a section in a wellbore in which the trajectory of the wellbore changes. The severity of such trajectory changes (i.e., dogleg severity) can be expressed in terms of degrees per unit length (e.g., per 100 feet) or alternatively in terms of the radius of curvature. Severe doglegs may lead to casing insertion difficulty, increased friction, increased casing wear, and/or an increased likelihood of bottomhole component trapping. As such, maintaining the curvature or dogleg severity as close to a planned wellbore trajectory as possible may help to maximize the amount of usable wellbore, and may improve completion and production of the final wellbore.

For some implementations, an RSS drilling tool may use inclination and azimuth to steer, while depth may be unknown. Without knowledge of depth while drilling, it may typically be difficult to monitor and control dogleg severity of the drilled wellbore. Accordingly, in various implementations further described below, a RSS drilling tool disposed in a wellbore may use one or more position sensors to maintain and/or control the dogleg severity of the wellbore during drilling.

RSS Drilling Tool

FIG. 1 illustrates a cross-sectional schematic diagram of a rotary steerable system (RSS) drilling tool 100 configured to be disposed in a wellbore in accordance with implementations of various techniques described herein. The RSS drilling tool 100 may include a rotatable shaft 102 extending through a non-rotating housing 104.

In one implementation, the design parameters of the shaft 102 (e.g., the diameter and/or length) may be selected based on a variety of factors, including the torque the shaft 102 is expected to undergo, weight on bit, stresses induced on the shaft 102 during bending (e.g., during steering), dynamic loading considerations, the strength of the selected shaft 102 material, tool 100 geometry, the strength of the other components of the tool 100, and/or the like. Moreover, the shaft diameter, length, selected material, and/or the like may be chosen such that the shaft 102 bends elastically by a sufficient amount to enable effective steering, allowing the tool 102 to achieve a sufficient turn rate and turn magnitude. In a further implementation, the shaft 102 may be an annular, metallic cylinder. Although other materials can be used, in one implementation, the shaft 102 may be formed of ductile, non-magnetic, corrosion resistant, high strength steel. The shaft 102 can also be adapted to conduct drilling fluid along its length, from a most uphole end to the a most downhole end, for eventual delivery to the wellbore through a drill bit structure 108. Additionally, in some implementations, a sleeve may encase the shaft or a portion thereof.

In another implementation, the housing 104 may be an annular, metal (e.g., ductile, non-magnetic, corrosion resistant, high strength steel) cylinder, and may include one or more sensors, electronics, bearings, and/or the like, as further described below. As noted above, the tool 100 may also include the drill bit structure 108 coupled to an end of the shaft 102 disposed most downhole relative to the rest of the shaft 102. The drill bit structure 108 may include one or more cutting or crushing elements, and can be configured to rotate during drilling so as to drill through the Earth and extend the wellbore. In another implementation, the drill bit structure 108 may include fixed cutter or roller cone style drill bits. Further, the drill bit structure 108 or portions thereof may be constructed from various high strength materials. For example, the cutting or crushing structure can be made from Polycrystalline Diamond Compact (PDC), tungsten carbide, or high strength steel in certain cases, among other types of materials. The body of the drill bit structure 108 can be made from tungsten carbide matrix or high strength steel.

The drill bit structure 108 may be operatively coupled to the shaft 102 through a first stabilizer 140. The tool 100 may also include a second stabilizer 142. The tool 100 may be formed as part of a drill string extending to the surface, and the remainder of the drill string may include one or more pipe segments 144 coupled to the tool 100 via the second stabilizer 142. The tool 100 may also include one or more anti-rotation devices configured to inhibit rotation of the non-rotating housing 104 with respect to the wellbore. For example, as shown, the one or more anti-rotation devices 110 can include a plurality of springs configured to contact the inner surface of the wellbore during use. In other implementations, the anti-rotation device 110 can include a plurality of spring boxes.

The tool 100 may also include a steering subsystem 112, which may include one or more bearings, one or more actuators, and a non-rotating cantilever. The steering subsystem 112 may be configured to angulate the shaft 102 by exerting force through the one or more bearings using one or more actuators, as further described below.

FIG. 2 illustrates a close-up, cross-sectional schematic diagram of the steering subsystem 112 of the tool 100 in accordance with implementations of various techniques described herein. The steering subsystem 112 may include one or more actuators 120, a non-rotating cantilever 122, one or more linear position sensors 124, one or more radial bearings 114, one or more thrust bearings 116, and one or more non-rotating spherical bearings 118. As shown in FIG. 2, the one or more radial bearings 114 and/or the one or more thrust bearings 116 are configured to separate the shaft 102 from the non-rotating cantilever 122 and/or the one or more non-rotating spherical bearings 118.

In one implementation, the one or more radial bearings 114 and the one or more thrust bearings 116 may each form an annular cylinder having an interior surface which rotates with respect to an outer surface. In a further implementation, the radial bearings 114 and the one or more thrust bearings 116 may each may have an interior surface in contact with a sleeve (not shown) encasing the rotating shaft 102 or a portion thereof, and may have an exterior surface in contact with the inner surface of the non-rotating cantilever 122 and/or the non-rotating spherical bearing 118.

The steering subsystem 112 may be configured to angulate the shaft 102 by exerting force through the one or more radial bearings 114 and/or the one or more thrust bearings 116 using the one or more actuators 120. In particular, the one or more actuators 120 may be configured to apply forces through the one or more radial bearings 114 and/or the one or more thrust bearings 116 to deflect the shaft 102 in a predetermined plane, such as to steer the drilling tool 100 in a desired direction and/or with a desired curvature.

In some implementations, the actuators 120 may include pressurized, hydraulic actuators. In another implementation, four actuators 120 may be disposed around a cantilever 122, which in turn is disposed around the circumference of the shaft 102. In particular, the cantilever 122 may be mechanically coupled to the shaft 102 via a radial bearing 114. In a further implementation, the actuators 120 may be hydraulically expandable against the housing 104 so as to apply a force to the one or more radial bearings 114 via the cantilever 122.

The bearings 114 may be responsive to the forces from the actuators 120, and may exert corresponding forces on the shaft 102. This may lead to an actuation, or bending moment, of the shaft 102. In turn, the bending moment may cause a change in the shaft angulation, and a corresponding change in the drilling direction and/or wellbore curvature using the tool 100. In one implementation, the one or more actuators 120 may be selectively activated in order to steer the tool 100 in any general direction and/or to create any particular wellbore curvature using the tool.

Further, the one or more radial bearings 114 and/or the one or more thrust bearings 116 may be configured to pivot about axes that are generally perpendicular to the shaft 102 during angulation. In particular, during angulation, the one or more radial bearings 114 and/or the one or more thrust bearings 116 can be configured to pivot about the non-rotating spherical bearing 118. In one implementation, the one or more radial bearings 114 or the one or more thrust bearings 116 may be configured to pivot about an axis when one or more of the actuators 120 are expanded. As further referred to herein, the non-rotating spherical bearing 118 may represent a first internal pivot point of the tool 100.

As noted above, the tool 100 may also include one or more position sensors 124 disposed within the housing 104. In one implementation, the position sensors 124 may be configured to measure the displacement of one or more actuators 120 from the housing 104, such as during angulation of the shaft 102. This displacement may be equal to the displacement of the cantilever 122 and/or the shaft 102 with respect to the housing 104. Any position sensor known to those skilled in the art that is capable of measuring such displacements may be used. In another implementation, the one or more position sensors 124 may be positioned proximate to the one or more actuators 120 of the steering subsystem 112. However, the position sensors 124 may be positioned at any location in the housing 104 where they may be capable of measuring the displacement of the one or more actuators 120 and/or the shaft 102 from the housing 104. In one implementation, the tool 100 may include one or more force sensors configured to measure one or more forces experienced by the one or more actuators 120. The use of the force sensors is discussed in further detail in a later section.

FIG. 3 illustrates a close-up, cross-sectional schematic diagram of the section 130 of the drilling tool 100 in accordance with implementations of various techniques described herein. As shown in FIG. 3, the tool 100 may include one or more radial bearings 132, one or more thrust bearings 134, and one or more non-rotating spherical bearings 136 within the housing 104. The bearings 132, 134, and 136 may be disposed at a position that is more uphole relative to the one or more radial bearings 114, one or more thrust bearings 116, and one or more non-rotating spherical bearings 118. In one implementation, the one or more radial bearings 132, one or more thrust bearings 134, and one or more non-rotating spherical bearings 136 may be positioned uphole relative to the anti-rotation devices 110.

The one or more radial bearings 132 and/or the one or more thrust bearings 134 may be configured to pivot about axes that are generally perpendicular to the shaft 102 during angulation. In particular, during angulation, the one or more radial bearings 132 and/or the one or more thrust bearings 134 can be configured to pivot about the non-rotating spherical bearing 136. In one implementation, the one or more radial bearings 132 or the one or more thrust bearings 134 may be configured to pivot about an axis to allow the shaft 102 to further angulate as the tool 100 drills the wellbore. As further referred to herein, the non-rotating spherical bearing 136 may represent a second internal pivot point of the tool 100.

The RSS drilling tool 100 may further include one or more directional sensors 150. In one implementation, the directional sensors 150 may include one or more gyroscopic sensors configured to measure one or more components of the Earth's rotation rate about one or more orthogonal axes ((e.g., x-axis, y-axis, and/or z-axis) of the survey tool. These measurements from the gyroscopic sensors may then be used in combination with measurements of tool inclination and tool face angle to compute an azimuth of the survey tool, and, hence, an azimuth of the wellbore at the location of the survey tool within the wellbore. For example, the one or more gyroscopic sensors can comprise one or more gyroscopes selected from the group consisting of: spinning wheel gyroscopes, optical gyroscopes, and Coriolis vibratory sensors (e.g., MEMS vibratory sensors). Example gyroscopic sensors compatible with embodiments described herein are described more fully in “Survey Accuracy is Improved by a New, Small OD Gyro,” G. W. Uttecht, J. P. deWardt, World Oil, Mar. 1983; U.S. Pat. Nos. 5,657,547, 5,821,414, and 5,806,195. These references are incorporated in their entireties by reference herein. Other examples of gyroscopic sensors are described by U.S. Pat. Nos. 6,347,282, 6,957,580, 7,117,605, 7,225,550, 7,234,539, 7,350,410, and 7,669,656 each of which is incorporated in its entirety by reference herein. The one or more gyroscopic sensors can be used in either a gyrocompass mode while the drilling tool 100 is relatively stationary, or a gyrosteering mode while drilling is progressing.

In a further implementation, the directional sensors 150 may include one or more acceleration sensors (e.g., single-axis or multiple-axis accelerometers). The one or more acceleration sensors may include two or more single-axis accelerometers, one or more two-axis accelerometers, and/or one or more three-axis accelerometers configured to provide measurements of one or more of the orthogonal components (g_x, g_y, g_z) of the Earth's gravitation vector with respect to the x, y, and z axes of the survey tool. Various types of accelerometers may be used, such as quartz flexure accelerometers, MEMS accelerometer devices, and/or any other type of accelerometers known to those skilled in the art. The measurements from the accelerometers may be used for the determination of the inclination, the high-side tool face angle, or both of the tool 100.

In another implementation, the directional sensors 150 may include one or more magnetometers. The magnetometers may be used to measure the direction and magnitude of the local magnetic field vectors in order to measure the azimuth and/or the inclination at various survey stations along the wellbore, as is known to those skilled in the art. In particular, the magnetometers may be configured to measure one or more orthogonal and/or non-orthogonal components of the Earth's magnetic field. For example, the tool 100 may include three magnetometers configured to measure the orthogonal components (b_x, b_y, b_z) of the Earth's magnetic field with respect to the x-axis, the y-axis, and the z-axis of the tool 100. The one or more magnetometers may include any magnetometer known to those skilled in the art, including flux gate sensors, solid state devices, and/or the like.

In certain implementations, the directional sensors 150 may form part of an instrumentation pack, such as a measurement-while-drilling (MWD) or logging-while-drilling (LWD) instrumentation pack. In yet another implementation, the one or more directional sensors 150 can also be located on another portion of the drill string, such as on a section 144 of drill string above the drilling tool 100. For example, FIG. 4 illustrates a schematic diagram of a drill string 160 disposed within a wellbore 170 in accordance with implementations of various techniques described herein. The drill sting 160 may include the drilling tool 100 with directional sensors 150 and one or more pipe segments 144 extending to the surface 170. In some implementations, the remainder of the one or more pipe segments 144 may extend to the Earth's surface in a daisy-chained configuration.

As shown in FIG. 4, a computing system (e.g., a controller) 190 may be included in the drill string 160, and may be configured to control and/or monitor the operation of the drill string 160 or portions thereof. The computing system 190 can be configured to perform a variety of functions. For example, the computing system 190 can be adapted to determine the current orientation or the trajectory of the drilling tool 100 within the borehole 170. The computing system 190 can further include a memory subsystem adapted to store appropriate information, such as orientation data, data obtained from one or more sensors located on the drill string 160, and/or the like. The computing system 190 can include hardware, software, or a combination of both hardware and software. For example, the computing system 190 can include one or more microprocessors, or a standard personal computer. Various implementations of the computing system 190 are also discussed further below in another section.

In some implementations, the computing system 190 may provide a real-time processing analysis of the signals or data obtained from various sensors within the tool 100. In particular, data obtained from the various sensors of the tool 100 may be analyzed while the tool 100 travels within the wellbore 170. In some implementations, at least a portion of the data obtained from the various sensors is saved in memory for analysis by the computing system 190. The computing system 190 may include sufficient data processing and data storage capacity to perform the real-time analysis.

As noted above, the steering subsystem 112 can be configured, as drilling proceeds, to angulate the shaft 102 so as to change or maintain a current wellbore course. The current wellbore course can be defined in terms of an inclination and an azimuth of the wellbore, toolface angle of the tool 100, and/or by the dogleg severity of the wellbore. In one implementation, the steering subsystem 112 may be configured to change or maintain the current wellbore course in accordance with a preprogrammed course or directional commands. For example, an operator may input a preprogrammed course into a terminal, such as a computer terminal located above ground (e.g., a terminal coupled to the computing system 190 or to an on-board computing system of the tool 100), prior to deployment of the tool 100. In another implementation, the operator can input directional commands into the terminal during drilling. In some implementations, a combination of a preprogrammed course and real-time directional commands can be used to steer the tool 100.

In another implementation, the drill string 160 can include one or more additional controllers instead of, or in addition to, the computing system 190. For example, an additional computing system may be located at or above the Earth's surface 180, and one or more additional computing systems may be located within a downhole portion of the drill string 160. In a further implementation, the drilling tool 100 may include an on-board computing system (not pictured).

In yet another implementation, the computing system 190 may be located at or above the Earth's surface 180, and may be communicatively coupled to the on-board computing system. As an example, the downhole portion of the drill string 160 may be part of a borehole drilling system capable of measurement while drilling (MWD) or logging while drilling (LWD). Signals from the downhole portion may be transmitted by mud pulse telemetry or electromagnetic (EM) telemetry to the computing system 190. In some implementations where at least a portion of the computing system 190 is located at or above the Earth's surface, the computing system 190 may be coupled to the downhole portion (e.g., to the on-board computing system, to the sensors located within the downhole portion, and/or the like) within the wellbore 170 by a wire or cable extending along the drill string 160. In another implementation, the drill string 160 may include signal conduits through which signals are transmitted from the downhole portion of the drill string 160 (e.g., from the on-board computing system or from sensors located within the downhole portion) to the computing system 190. In such an implementation, the drill string 160 may be adapted to transmit control signals from the computing system to the downhole portion of the drill string 160.

The on board computing system of the tool 210 can also store information related to the drilling tool 100, operation of the drilling tool 100, and the like. For example, the computing system can store information related to the target drilling course, current drilling course, tool configuration, tool components, and the like. The on-board computing system and/or one or more directional sensors 150 can be within a nominally non-rotating section of the drilling tool 100 (e.g., within the housing 104). In some implementations, the computing system and/or one or more directional sensors 150 can be located elsewhere, such as within a rotating section of the tool 100, or at some other location within the wellbore 170 (e.g., on some other portion of the drill string 160). In other implementations, a measurement-while-drilling (MWD) (not shown) instrumentation pack, including one or more directional sensors 150, may be mounted on the downhole portion of the drill string 160 at some location above the drilling tool 100.

While various implementations of the RSS drilling tool 100 are discussed above with respect to FIGS. 1-4, those skilled in the art know that other implementations of RSS drilling tools may be used as well. For example, the various implementations of RSS drilling tools discussed in commonly-assigned U.S. Pat. No. 8,579,044, which is incorporated by reference in its entirety, may be used as well.

Determining Dogleg Severity

As is known in the art, the curvature of the wellbore drilled by a RSS drilling tool can be determined based on a known three-point geometry of the tool. In particular, the three-point geometry may be defined by upper and lower stabilizer touch points and the drill bit. The angle of deviation of the drill bit axis, along with a finite distance between the drill bit and lower stabilizer, may result in the non-collinear condition required for a curve to be generated for the wellbore.

As shown in FIGS. 1 and 5, the three point geometry of the tool 100 may be defined by the first stabilizer 140, the second stabilizer 142, and the drill bit structure 108. FIG. 5 illustrates a cross-sectional schematic diagram of the RSS drilling tool 100 configured to be disposed in the wellbore 170 in accordance with implementations of various techniques described herein.

The distance between a midpoint of the first stabilizer 140 (“P1”) and a midpoint of the second stabilizer 142 (“P2”) may be defined as distance “a”. The distance between a midpoint of the first stabilizer 140 (“P2”) and a midpoint of the drill bit structure 108 (“P3”) may be defined as distance “b”. P1, P2, and P3 may be referred to as the points of contact for the tool 100. Both distances “a” and “b” may be known values, and they may be stored by one or more computing systems associated with the tool 100 discussed above.

The deviation of the longitudinal axis of the drill bit structure 108 from the longitudinal axis of the housing 104 may be defined as angle “c”. As such, the three point geometry of the tool 100 may be defined by the values of “a”, “b”, and “c”. This three point geometry, in turn, can be used to determine the curvature of the wellbore 170 drilled by the tool 100.

The angle “c” can be derived using the displacement data acquired by the one or more position sensors 124 discussed above. The displacement data may correspond to the measured displacement of one or more actuators 120 from the housing 104, or may correspond to the measured displacement of the shaft from the housing 104. Any method known to those skilled in the art for deriving the angle c using such displacement data may be used. For example, in one implementation, the angle c may be determined using the non-rotating spherical bearing 118 (i.e., the first internal pivot point of the tool 100) discussed above. In particular, as shown in FIG. 6, known geometric values of the tool 100 may be used to derive the angle “c”.

FIG. 6 illustrates a geometric diagram 600 of a portion of the RSS drilling tool 100 in accordance with implementations of various techniques described herein. In particular, line 610 may represent the distance between the first internal pivot point 118 to a point 602 on the drill bit structure 108, where the line 610 may be parallel to the longitudinal axis of the housing 104. Line 620 may represent the measured displacement of an actuator 120 from the housing 104, obtained using a position sensor 124. Using the distances of 610 and 620, along with known geometric and trigonometric principles, the angle “c” may be derived.

Once the values of “a”, “b”, and “c” have been determined, this three point geometry can be used to determine the curvature of the wellbore 170 drilled by the tool 100. In turn, this curvature may be used to determine the dogleg severity of the wellbore 170. FIG. 7 illustrates a geometric diagram 700 of a portion of the RSS drilling tool 100 in accordance with implementations of various techniques described herein. Given the points of contact (P1, P2, and P3) and the known three point geometry (values of “a”, “b”, and “c”) of the tool 100, a radius of a circle passing through the points of contact can be determined.

In particular, using the general equation of a circle (X²+Y²=R²) and the other mathematical formulas shown in FIG. 7, the radius R of the circle passing through the points of contact can be derived. This radius R can then be used to determine the dogleg severity of the wellbore, given that the dogleg severity of the wellbore is inversely proportional to the radius R. As noted above, the dogleg severity can be expressed in terms of degrees per unit length, such as degrees per 100 feet.

In one implementation, one or more computing systems discussed above may create and/or store a lookup table that associates values of the three point geometry (values of “a”, “b”, and “c”) with particular measured displacement values and/or dogleg severity values. In a further implementation, one or more computing systems discussed above may create and/or store a lookup table that associates particular measured displacement values with dogleg severity values.

The use of the three point geometry to calculate the dogleg severity of the wellbore may require the assumption of relatively perfect contact between the points of contact (P1, P2, and P3) along the tool 100 and the wellbore. Further, these calculations may also require an assumption that an unstratified formation is being drilled by the tool 100. For scenarios in which there may be imperfect contact between the points of contact (P1, P2, and P3) along the tool 100 and the wellbore, a caliper may be used to measure the gauge of the wellbore, which may be used to determine the relationship between the stabilizers 140, 142 and the wellbore, which in turn may be used to determine the three point geometry discussed above. For scenarios in which there may be formation striations, effects from the formation may be measured and compensated for using the one or more force sensors discussed above. In particular, the force sensors may be used to measure a force experienced by the one or more actuators 120 of the tool 100, and this actual force may be compared to an expected force needed to achieve the angle “c” discussed above. If the actual force is not the same as the expected force, then angle “c” calculated above may be adjusted for the three point geometry of the tool.

Method

Using the displacement data acquired using one or more position sensors, and the relationship between measured displacements and dogleg severity discussed above, a RSS drilling tool may be able to maintain and/or control the dogleg severity of a wellbore during drilling.

FIG. 8 illustrates a flow diagram of a method 800 for controlling the dogleg severity of a wellbore using a RSS drilling tool in accordance with implementations of various techniques described herein. In one implementation, method 800 may be at least partially performed by a computing system, such as the computing system 190 discussed above. In another implementation, the RSS drilling tool may be similar to those discussed above with respect to FIGS. 1-7, such as drilling tool 100. It should be understood that while method 800 indicates a particular order of execution of operations, in some implementations, certain portions of the operations might be executed in a different order. Further, in some implementations, additional operations or steps may be added to the method 800. Likewise, some operations or steps may be omitted.

At block 810, the computing system may receive a target dogleg severity for a planned trajectory of at least a portion of the wellbore to be drilled using the RSS drilling tool. The target dogleg severity may be predetermined. In one implementation, the target dogleg severity may be received by the computing system 190, which may be part of the drill string 160 discussed above. As also discussed above, the target dogleg severity may be expressed in terms of degrees per 100 feet. In another implementation, the target dogleg severity may be preprogrammed into memory by the computing system.

At block 820, the computing system may receive a target inclination and azimuth for the planned trajectory of at least the portion of the wellbore to be drilled using the RSS drilling tool. In one implementation, the target inclination and azimuth may be preprogrammed into memory by the computing system.

At block 830, the computing system may determine a toolface angle for the RSS drilling tool based on the target inclination and azimuth. Those skilled in the art are familiar with the various equations and methods that may be used to derive the toolface angle using inclination and azimuth.

At block 840, the computing system may determine at least a first displacement for one or more actuators of the RSS drilling tool relative to a housing of the tool based on the target dogleg severity and the toolface angle. In one implementation, the computing system may determine a different displacement for each of the one or more actuators.

Using the relationship between dogleg severity, the three point geometry of the tool, and displacement of one or more actuators of a RSS drilling tool, as discussed above with respect to FIGS. 5-7, a first displacement of the one or more actuators can be determined. In particular, the first displacement may be a value at which a shaft of the RSS drilling tool can be sufficiently angulated in order to drill the wellbore trajectory at the target dogleg severity. In some implementations, the first displacement may represent a maximum displacement of the one or more actuators.

In one implementation, the computing system may calculate the first displacement using the equations and geometric relationships described with respect to FIGS. 5-7. In another implementation, the computing system may use a lookup table to determine the first displacement based on the target dogleg severity.

Further, the computing system may also determine the first displacement based on the toolface angle, such that the shaft of the RSS drilling tool can be sufficiently angulated in order to drill the wellbore trajectory at the toolface angle. In one implementation, the computing system may determine at least a first displacement for the shaft of the RSS drilling tool relative to the housing of the tool based on the target dogleg severity and the toolface angle.

At block 850, the computing system may activate the one or more actuators based on at least the first displacement. In particular, the computing system may provide motor signals to the one or more actuators in order to selectively activate the actuators based on at least the first displacement.

At block 860, the computing system may receive displacement data from one or more position sensors disposed in the drilling tool. The position sensors may be similar to the position sensors 124 discussed above with respect to FIGS. 1-4. The computing system may receive displacement data in any periodic interval known to those skilled in the art. For example, the computing system may receive the displacement data every estimated 100 feet as the RSS drilling tool operates to drill the wellbore. The displacement data may correspond to an updated displacement (hereinafter referred to as the second displacement) of at least one of the actuators of the tool relative to the housing of the tool as measured by the one or more position sensors.

At block 870, the computing system may activate the one or more actuators based on the displacement data. In one implementation, the computing system may compare the second displacement to the first displacement. If the second displacement is different than the first displacement, or deviates from the first displacement beyond an acceptable amount, then the computing system may activate the one or more actuators in order to position the one or more actuators at a first displacement amount from the housing.

In another implementation, the computing system may determine an updated dogleg severity for the second displacement, such as through the computations or the lookup table discussed above. The computing system may then compare the updated dogleg severity to the target dogleg severity. If the updated dogleg severity is different than the target dogleg severity, or deviates from the target dogleg severity beyond an acceptable amount, then the computing system may activate the one or more actuators in order to angulate the shaft so that the tool may drill the wellbore trajectory at the target dogleg severity.

At block 880, the computing system may receive survey data corresponding to one or more measurements of the Earth's gravitation vector from one or more accelerometers of the drilling tool. As noted above, the accelerometers may be part of the directional sensors of the tool. The tool may also receive this survey data periodically, such as when the tool is stationary and is able to enter gyrocompassing mode. The computing system may receive such survey data in any periodic interval known to those skilled in the art.

At block 890, the computing system may activate the one or more actuators based on the survey data. In one implementation, the computing system may determine an updated toolface angle based on the survey data using methods known to those skilled in the art. The computing system may compare the updated toolface angle to the toolface angle derived at block 830. If the updated toolface angle is different than the toolface angle derived at block 830, or deviates from tit beyond an acceptable amount, then the computing system may activate the one or more actuators in order to sufficiently angulated to shaft in order to drill the wellbore trajectory at the appropriate toolface angle.

As such, as the RSS drilling tool drills the wellbore until it reaches its target inclination and azimuth, the computing system will maintain and control the dogleg severity of the wellbore such that the dogleg severity is at least within an acceptable limit of the target dogleg severity. The RSS drilling tool may also be configured to similarly maintain a specified toolface angle in order to reach its target inclination and azimuth.

In sum, implementations relating to a RSS drilling tool, as discussed above, may be used to maintain and control the dogleg severity of a wellbore during drilling. Maintaining the dogleg severity as close to a planned wellbore trajectory (e.g., a target dogleg severity) as possible may help to maximize the amount of usable wellbore and may improve completion and production of the final wellbore. Using one or more positions sensors, the RSS drilling tool may be able maintain and/or control the dogleg severity of the wellbore during drilling without the need for real-time inclination, azimuth, or depth measurements of the tool. In particular, the RSS drilling tool may be able to maintain a dogleg severity of the wellbore using less frequently acquired surveys and measurements than is conventionally performed in the art. Such a tool may also be able to use stationary North-seeking gyroscopic or magnetic orientation sensors, and placing the orientation sensors with the rotating part of the tool may allow for smaller sized RSS drilling tools. Further, the implementations for the RSS drilling tool discussed above may be utilized in areas of magnetic interference, such as for twinned wells or casing-while-drilling applications.

Computing System

Various implementations of the previously-discussed computing systems are further discussed below. Implementations of various technologies described herein may be operational with numerous general purpose or special purpose computing system environments or configurations. Examples of well known computing systems, environments, and/or configurations that may be suitable for use with the various technologies described herein include, but are not limited to, personal computers, server computers, hand-held or laptop devices, multiprocessor systems, microprocessor-based systems, set top boxes, programmable consumer electronics, network PCs, minicomputers, mainframe computers, smart phones, smart watches, personal wearable computing systems networked with other computing systems, tablet computers, and distributed computing environments that include any of the above systems or devices, and the like.

The various technologies described herein may be implemented in the general context of computer-executable instructions, such as program modules, being executed by a computer. Generally, program modules include routines, programs, objects, components, data structures, etc. that performs particular tasks or implement particular abstract data types. While program modules may execute on a single computing system, it should be appreciated that, in some implementations, program modules may be implemented on separate computing systems or devices adapted to communicate with one another. A program module may also be some combination of hardware and software where particular tasks performed by the program module may be done either through hardware, software, or both.

The various technologies described herein may also be implemented in distributed computing environments where tasks are performed by remote processing devices that are linked through a communications network, e.g., by hardwired links, wireless links, or combinations thereof. The distributed computing environments may span multiple continents and multiple vessels, ships or boats. In a distributed computing environment, program modules may be located in both local and remote computer storage media including memory storage devices.

FIG. 9 illustrates a schematic diagram of a computing system 900 in which the various technologies described herein may be incorporated and practiced. Although the computing system 900 may be a conventional desktop or a server computer, as described above, other computer system configurations may be used.

The computing system 900 may include a central processing unit (CPU) 930, a system memory 926, a graphics processing unit (GPU) 931 and a system bus 928 that couples various system components including the system memory 926 to the CPU 930. Although one CPU is illustrated in FIG. 9, it should be understood that in some implementations the computing system 900 may include more than one CPU. The GPU 931 may be a microprocessor specifically designed to manipulate and implement computer graphics. The CPU 930 may offload work to the GPU 931. The GPU 931 may have its own graphics memory, and/or may have access to a portion of the system memory 926. As with the CPU 930, the GPU 931 may include one or more processing units, and the processing units may include one or more cores. The system bus 928 may be any of several types of bus structures, including a memory bus or memory controller, a peripheral bus, and a local bus using any of a variety of bus architectures. By way of example, and not limitation, such architectures include Industry Standard Architecture (ISA) bus, Micro Channel Architecture (MCA) bus, Enhanced ISA (EISA) bus, Video Electronics Standards Association (VESA) local bus, and Peripheral Component Interconnect (PCI) bus also known as Mezzanine bus. The system memory 926 may include a read-only memory (ROM) 912 and a random access memory (RAM) 946. A basic input/output system (BIOS) 914, containing the basic routines that help transfer information between elements within the computing system 900, such as during start-up, may be stored in the ROM 912.

The computing system 900 may further include a hard disk drive 990 for reading from and writing to a hard disk, a magnetic disk drive 952 for reading from and writing to a removable magnetic disk 956, and an optical disk drive 954 for reading from and writing to a removable optical disk 958, such as a CD ROM or other optical media. The hard disk drive 950, the magnetic disk drive 952, and the optical disk drive 954 may be connected to the system bus 928 by a hard disk drive interface 956, a magnetic disk drive interface 958, and an optical drive interface 950, respectively. The drives and their associated computer-readable media may provide nonvolatile storage of computer-readable instructions, data structures, program modules and other data for the computing system 900.

Although the computing system 900 is described herein as having a hard disk, a removable magnetic disk 956 and a removable optical disk 958, it should be appreciated by those skilled in the art that the computing system 900 may also include other types of computer-readable media that may be accessed by a computer. For example, such computer-readable media may include computer storage media and communication media. Computer storage media may include volatile and non-volatile, and removable and non-removable media implemented in any method or technology for storage of information, such as computer-readable instructions, data structures, program modules or other data. Computer storage media may further include RAM, ROM, erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM), flash memory or other solid state memory technology, CD-ROM, digital versatile disks (DVD), or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other medium which can be used to store the desired information and which can be accessed by the computing system 900. Communication media may embody computer readable instructions, data structures, program modules or other data in a modulated data signal, such as a carrier wave or other transport mechanism and may include any information delivery media. The term “modulated data signal” may mean a signal that has one or more of its characteristics set or changed in such a manner as to encode information in the signal. By way of example, and not limitation, communication media may include wired media such as a wired network or direct-wired connection, and wireless media such as acoustic, RF, infrared and other wireless media. The computing system 900 may also include a host adapter 933 that connects to a storage device 935 via a small computer system interface (SCSI) bus, a Fiber Channel bus, an eSATA bus, or using any other applicable computer bus interface. Combinations of any of the above may also be included within the scope of computer readable media.

A number of program modules may be stored on the hard disk 950, magnetic disk 956, optical disk 958, ROM 912 or RAM 916, including an operating system 918, one or more application programs 920, program data 924, and a database system 948. The application programs 920 may include various mobile applications (“apps”) and other applications configured to perform various methods and techniques described herein. The operating system 918 may be any suitable operating system that may control the operation of a networked personal or server computer, such as Windows® XP, Mac OS® X, Unix-variants (e.g., Linux® and BSD®), and the like.

A user may enter commands and information into the computing system 900 through input devices such as a keyboard 962 and pointing device 960. Other input devices may include a microphone, joystick, game pad, satellite dish, scanner, or the like. These and other input devices may be connected to the CPU 930 through a serial port interface 942 coupled to system bus 928, but may be connected by other interfaces, such as a parallel port, game port or a universal serial bus (USB). A monitor 934 or other type of display device may also be connected to system bus 928 via an interface, such as a video adapter 932. In addition to the monitor 934, the computing system 900 may further include other peripheral output devices such as speakers and printers.

Further, the computing system 900 may operate in a networked environment using logical connections to one or more remote computers 974. The logical connections may be any connection that is commonplace in offices, enterprise-wide computer networks, intranets, and the Internet, such as local area network (LAN) 956 and a wide area network (WAN) 966. The remote computers 974 may be another a computer, a server computer, a router, a network PC, a peer device or other common network node, and may include many of the elements describes above relative to the computing system 900. The remote computers 974 may also each include application programs 970 similar to that of the computer action function.

When using a LAN networking environment, the computing system 900 may be connected to the local network 976 through a network interface or adapter 944. When used in a WAN networking environment, the computing system 900 may include a router 964, wireless router or other means for establishing communication over a wide area network 966, such as the Internet. The router 964, which may be internal or external, may be connected to the system bus 928 via the serial port interface 952. In a networked environment, program modules depicted relative to the computing system 900, or portions thereof, may be stored in a remote memory storage device 972. It will be appreciated that the network connections shown are merely examples and other means of establishing a communications link between the computers may be used.

The network interface 944 may also utilize remote access technologies (e.g., Remote Access Service (RAS), Virtual Private Networking (VPN), Secure Socket Layer (SSL), Layer 2 Tunneling (L2T), or any other suitable protocol). These remote access technologies may be implemented in connection with the remote computers 974.

It should be understood that the various technologies described herein may be implemented in connection with hardware, software or a combination of both. Thus, various technologies, or certain aspects or portions thereof, may take the form of program code (i.e., instructions) embodied in tangible media, such as floppy diskettes, CD-ROMs, hard drives, or any other machine-readable storage medium wherein, when the program code is loaded into and executed by a machine, such as a computer, the machine becomes an apparatus for practicing the various technologies. In the case of program code execution on programmable computers, the computing device may include a processor, a storage medium readable by the processor (including volatile and non-volatile memory and/or storage elements), at least one input device, and at least one output device. One or more programs that may implement or utilize the various technologies described herein may use an application programming interface (API), reusable controls, and the like. Such programs may be implemented in a high level procedural or object oriented programming language to communicate with a computer system. However, the program(s) may be implemented in assembly or machine language, if desired. In any case, the language may be a compiled or interpreted language, and combined with hardware implementations. Also, the program code may execute entirely on a user's computing device, on the user's computing device, as a stand-alone software package, on the user's computer and on a remote computer or entirely on the remote computer or a server computer.

The system computer 900 may be located at a data center remote from the survey region. The system computer 900 may be in communication with the receivers (either directly or via a recording unit, not shown), to receive signals indicative of the reflected seismic energy. These signals, after conventional formatting and other initial processing, may be stored by the system computer 900 as digital data in the disk storage for subsequent retrieval and processing in the manner described above. In one implementation, these signals and data may be sent to the system computer 900 directly from sensors, such as geophones, hydrophones and the like. When receiving data directly from the sensors, the system computer 900 may be described as part of an in-field data processing system. In another implementation, the system computer 900 may process seismic data already stored in the disk storage. When processing data stored in the disk storage, the system computer 900 may be described as part of a remote data processing center, separate from data acquisition. The system computer 900 may be configured to process data as part of the in-field data processing system, the remote data processing system or a combination thereof.

Those with skill in the art will appreciate that any of the listed architectures, features or standards discussed above with respect to the example computing system 900 may be omitted for use with a computing system used in accordance with the various embodiments disclosed herein because technology and standards continue to evolve over time.

While the foregoing is directed to implementations of various technologies described herein, other and further implementations may be devised without departing from the basic scope thereof. Although the subject matter has been described in language specific to structural features and/or methodological acts, it is to be understood that the subject matter defined in the appended claims is not limited to the specific features or acts described above. Rather, the specific features and acts described above are disclosed as example forms of implementing the claims.

Conditional language used herein, such as, among others, “can,” “could,” “might,” “may,” “e.g.,” and the like, unless specifically stated otherwise, or otherwise understood within the context as used, is generally intended to convey that certain embodiments include, while other embodiments do not include, certain features, elements and/or states. Thus, such conditional language is not generally intended to imply that features, elements and/or states are in any way required for one or more embodiments or that one or more embodiments necessarily include logic for deciding, with or without author input or prompting, whether these features, elements and/or states are included or are to be performed in any particular embodiment.

Depending on the embodiment, certain acts, events, or functions of any of the methods described herein can be performed in a different sequence, can be added, merged, or left out completely (e.g., not all described acts or events are necessary for the practice of the method). Moreover, in certain embodiments, acts or events can be performed concurrently, e.g., through multi-threaded processing, interrupt processing, or multiple processors or processor cores, rather than sequentially.

The various illustrative logical blocks, modules, circuits, and algorithm steps described in connection with the embodiments disclosed herein can be implemented as electronic hardware, computer software, or combinations of both. To clearly illustrate this interchangeability of hardware and software, various illustrative components, blocks, modules, circuits, and steps have been described above generally in terms of their functionality. Whether such functionality is implemented as hardware or software depends upon the particular application and design constraints imposed on the overall system. The described functionality can be implemented in varying ways for each particular application, but such implementation decisions should not be interpreted as causing a departure from the scope of the disclosure.

The various illustrative logical blocks, modules, and circuits described in connection with the embodiments disclosed herein can be implemented or performed with a general purpose processor, a digital signal processor (DSP), an application specific integrated circuit (ASIC), a field programmable gate array (FPGA) or other programmable logic device, discrete gate or transistor logic, discrete hardware components, or any combination thereof designed to perform the functions described herein. A general purpose processor can be a microprocessor, but in the alternative, the processor can be any conventional processor, controller, microcontroller, or state machine. A processor can also be implemented as a combination of computing devices, e.g., a combination of a DSP and a microprocessor, a plurality of microprocessors, one or more microprocessors in conjunction with a DSP core, or any other such configuration.

The blocks of the methods and algorithms described in connection with the embodiments disclosed herein can be embodied directly in hardware, in a software module executed by a processor, or in a combination of the two. A software module can reside in RAM memory, flash memory, ROM memory, EPROM memory, EEPROM memory, registers, a hard disk, a removable disk, a CD-ROM, or any other form of computer-readable storage medium known in the art. An exemplary tangible, computer-readable storage medium is coupled to a processor such that the processor can read information from, and write information to, the storage medium. In the alternative, the storage medium can be integral to the processor. The processor and the storage medium can reside in an ASIC. The ASIC can reside in a user terminal. In the alternative, the processor and the storage medium can reside as discrete components in a user terminal.

While the above detailed description has shown, described, and pointed out novel features as applied to various embodiments, it will be understood that various omissions, substitutions, and changes in the form and details of the devices or algorithms illustrated can be made without departing from the spirit of the disclosure. As will be recognized, certain embodiments described herein can be embodied within a form that does not provide all of the features and benefits set forth herein, as some features can be used or practiced separately from others. The scope of certain inventions disclosed herein is indicated by the appended claims rather than by the foregoing description. All changes which come within the meaning and range of equivalency of the claims are to be embraced within their scope.

Claims

1. A method for controlling dogleg severity for a portion of a wellbore using a rotary steerable system (RSS) drilling tool disposed in the wellbore, comprising:

receiving a predetermined dogleg severity for the portion of the wellbore to be drilled using the RSS drilling tool;

determining at least a first displacement of one or more actuators of the RSS drilling tool from a housing of the RSS drilling tool based on the predetermined dogleg severity;

activating the one or more actuators based on at least the first displacement;

receiving displacement data from one or more position sensors disposed in the RSS drilling tool during drilling of the portion of the wellbore, wherein the displacement data corresponds to at least a second displacement of the one or more actuators from the housing;

activating the one or more actuators based on the displacement data.

2. The method of claim 1, wherein determining at least the first displacement of the one or more actuators comprises deriving at least the first displacement based on the three point geometry of the RSS drilling tool.

3. The method of claim 1, wherein determining at least the first displacement of the one or more actuators comprises using a lookup table to determine a displacement value that corresponds to the predetermined dogleg severity.

4. The method of claim 1, wherein a shaft of the RSS drilling tool is sufficiently angulated in order to drill the portion of the wellbore at the predetermined dogleg severity when the one or more actuators are positioned from the housing at a distance equal to the first displacement.

5. The method of claim 1, wherein receiving the displacement data comprises receiving the displacement data at periodic intervals.

6. The method of claim 1, wherein activating the one or more actuators of the RSS drilling tool based on the displacement data comprises:

comparing the second displacement to the first displacement; and

activating the one or more actuators to position the one or more actuators from the housing at a distance equal to the first displacement if the second displacement differs from the first displacement by more than a predetermined limit.

7. The method of claim 1, wherein activating the one or more actuators of the RSS drilling tool based on the displacement data comprises:

determining an updated dogleg severity of the wellbore based on the second displacement;

comparing the updated dogleg severity to the predetermined dogleg severity; and

activating the one or more actuators to position the one or more actuators from the housing at a distance equal to the first displacement if the updated dogleg severity differs from the predetermined dogleg severity by more than a predetermined limit.

8. The method of claim 1, wherein the RSS drilling tool comprises a steering subsystem that includes one or more bearings, the one or more actuators, and a non-rotating cantilever.

9. The method of claim 1, further comprising:

receiving a predetermined inclination and a predetermined azimuth for the portion of the wellbore to be drilled;

determining a first toolface angle for the RSS drilling tool based on the predetermined inclination and predetermined azimuth;

determining at least the first displacement based on the predetermined dogleg severity and the first toolface angle;

activating the one or more actuators based on at least the first displacement;

receiving survey data corresponding to one or more measurements of the Earth's gravitation vector from one or more accelerometers of the RSS drilling tool;

determining a second toolface angle for the RSS drilling tool based on the survey data;

activating the one or more actuators based on the second toolface angle.

10. The method of claim 9, wherein activating the one or more actuators based on the second toolface angle comprises:

comparing the second toolface angle to the first toolface angle; and

activating the one or more actuators if the second toolface angle differs from the first toolface angle by more than a predetermined limit.

11. A method for controlling dogleg severity for a portion of a wellbore using a rotary steerable system (RSS) drilling tool disposed in the wellbore, comprising:

receiving a predetermined dogleg severity for the portion of the wellbore to be drilled using the RSS drilling tool;

determining at least a first displacement of a shaft of the RSS drilling tool from a housing of the RSS drilling tool based on the predetermined dogleg severity;

activating one or more actuators of the RSS drilling tool based on at least the first displacement;

receiving displacement data from one or more position sensors disposed in the RSS drilling tool during drilling of the wellbore, wherein the displacement data corresponds to at least a second displacement of the shaft from the housing;

activating the one or more actuators of the RSS drilling tool based on the displacement data.

12. The method of claim 11, wherein determining at least the first displacement of the one or more actuators comprises deriving at least the first displacement based on the three point geometry of the RSS drilling tool.

13. The method of claim 11, wherein determining at least the first displacement of the one or more actuators comprises using a lookup table to determine a displacement value that corresponds to the predetermined dogleg severity.

14. The method of claim 11, wherein receiving the displacement data comprises receiving the displacement data at periodic intervals.

15. The method of claim 11, wherein activating the one or more actuators of the RSS drilling tool based on the displacement data comprises:

comparing the second displacement to the first displacement; and

activating the one or more actuators to position the one or more actuators from the housing at a distance equal to the first displacement if the second displacement differs from the first displacement by more than a predetermined limit.

16. The method of claim 11, wherein activating the one or more actuators of the RSS drilling tool based on the displacement data comprises:

determining an updated dogleg severity of the wellbore based on the second displacement;

comparing the updated dogleg severity to the predetermined dogleg severity; and

activating the one or more actuators to position the one or more actuators from the housing at a distance equal to the first displacement if the updated dogleg severity differs from the predetermined dogleg severity by more than a predetermined limit.

17. The method of claim 11, wherein the RSS drilling tool comprises a steering subsystem that includes one or more bearings, the one or more actuators, and a non-rotating cantilever.

18. A system, comprising:

a rotary steerable system (RSS) drilling tool disposed in a wellbore, comprising one or more actuators and one or more position sensors disposed in a housing of the RSS drilling tool;

a processor; and

a memory comprising a plurality of program instructions which, when executed by the processor, cause the processor to: receive a predetermined dogleg severity for a portion of the wellbore to be drilled using the RSS drilling tool; determine at least a first displacement of the one or more actuators of the RSS drilling tool from the housing based on the predetermined dogleg severity; activate the one or more actuators based on at least the first displacement; receive displacement data from the one or more position sensors during drilling of the portion of the wellbore, wherein the displacement data corresponds to at least a second displacement of the one or more actuators from the housing; activate the one or more actuators based on the displacement data.

19. The system of claim 18, wherein the plurality of program instructions which, when executed by the processor, cause the processor to determine at least the first displacement of the one or more actuators comprises a plurality of program instructions which, when executed by the processor, cause the processor to derive at least the first displacement based on the three point geometry of the RSS drilling tool.

20. The system of claim 18, wherein the RSS drilling tool further comprises a steering subsystem that includes one or more bearings, the one or more actuators, and a non-rotating cantilever.