US20150101863A1 - Downhole tool for sidetracking - Google Patents

Downhole tool for sidetracking Download PDF

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Publication number
US20150101863A1
US20150101863A1 US14/507,891 US201414507891A US2015101863A1 US 20150101863 A1 US20150101863 A1 US 20150101863A1 US 201414507891 A US201414507891 A US 201414507891A US 2015101863 A1 US2015101863 A1 US 2015101863A1
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Prior art keywords
downhole tool
body
orientation
magnetometer
wellbore
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Abandoned
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US14/507,891
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Benjamin P. Jeffryes
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Smith International Inc
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Smith International Inc
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Application filed by Smith International Inc filed Critical Smith International Inc
Priority to US14/507,891 priority patent/US20150101863A1/en
Assigned to SMITH INTERNATIONAL, INC. reassignment SMITH INTERNATIONAL, INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: JEFFRYES, BENJAMIN P.
Publication of US20150101863A1 publication Critical patent/US20150101863A1/en
Application status is Abandoned legal-status Critical

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    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B7/00Special methods or apparatus for drilling
    • E21B7/04Directional drilling
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00Survey of boreholes or wells
    • E21B47/02Determining slope or direction
    • E21B47/022Determining slope or direction of the borehole, e.g. using geomagnetism
    • E21B47/02216Determining slope or direction of the borehole, e.g. using geomagnetism using at least one source of electromagnetic energy and at least one detector therefor
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B3/00Rotary drilling
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00Survey of boreholes or wells
    • E21B47/01Devices for supporting measuring instruments on a drill pipe, rod or wireline ; Protecting measuring instruments in boreholes against heat, shock, pressure or the like
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B7/00Special methods or apparatus for drilling
    • E21B7/04Directional drilling
    • E21B7/06Deflecting the direction of boreholes
    • E21B7/061Deflecting the direction of boreholes the tool shaft advancing relative to a guide, e.g. a curved tube or a whipstock

Abstract

A downhole tool for drilling a sidetracked borehole. The downhole tool includes a body having an axial bore formed at least partially therethrough. At least one magnetometer is within the body. The magnetometer is configured to measure a magnetic field. A processor may be in communication with the at least one magnetometer. The processor may be configured to receive measurements from the at least one magnetometer, determine an orientation of the downhole tool based upon the received measurements, and selectively maintain the orientation of the downhole tool or change the orientation of the downhole tool based upon the determined orientation.

Description

    CROSS-REFERENCE TO RELATED APPLICATIONS
  • This application claims the benefit of, and priority to, U.S. Patent Application Ser. No. 61/889,890 filed Oct. 11, 2013 and titled “Downhole Tool for Sidetracking,” which application is expressly incorporated herein by this reference in its entirety.
  • BACKGROUND
  • Wellbores used for the production of hydrocarbon fluids, such as oil and gas, oftentimes include a metal (e.g., steel) casing therein. When an operator desires to exit the cased wellbore to “kick off” and drill a “sidetracked” borehole, a whipstock is positioned in the casing, and subsequently a downhole tool with a window mill is run into the wellbore. The whipstock includes an inclined surface that causes the window mill to deflect from the longitudinal axis of the cased wellbore at an angle causing the window mill to contact the metal casing and cut a window or opening therein. After the window has been formed, the downhole tool is pulled out of the wellbore, and a downhole tool with a drill bit is run back into the wellbore and through the window. The drill bit may then be used to drill through the formation and extend the sidetracked borehole.
  • SUMMARY
  • Embodiments described herein generally relate to devices, system, and methods for directional drilling. More particularly, some embodiments described herein generally relate to devices, systems, and methods for measuring the orientation of a downhole tool during the drilling of a sidetracked borehole.
  • A downhole tool for drilling a sidetracked borehole is disclosed. The downhole tool may include a body having an axial bore formed at least partially therethrough. A magnetometer may be coupled to the body and configured to measure a magnetic field. A processor may be in communication with the magnetometer and configured to receive measurements from the magnetometer. The processor may also determine an orientation of the downhole tool based upon the received measurements, and maintain the orientation of the downhole tool or change the orientation of the downhole tool based upon the determined orientation of the downhole tool.
  • A method for drilling is also disclosed. The method may include running a downhole tool into a wellbore. The downhole tool may include a body with a bore extending fully or partially therein. First and second may be located within the bore, and a processor may be within the body and in communication with the sensors. The first sensor may have limited accuracy while in the wellbore, and the second sensor may be susceptible to interference from casing of the wellbore. A borehole diverting from the wellbore may be drilled, and location or orientation data may be obtained using the sensors. The orientation of the downhole tool may be determined using the processor based upon location or orientation data obtained by the second sensor while within the wellbore. The downhole tool may be steered based upon the determined orientation of the downhole tool.
  • In another embodiment, an illustrative method may include forming an opening in a metal casing within a wellbore. A sidetracked borehole diverging from the wellbore at the opening may be drilled using a downhole tool. The downhole tool may include a body. A magnetometer, processor, and drill bit may be coupled to the body. The processor may also be in communication with the magnetometer. A magnetic field generated by a magnet within the casing may be measured using the magnetometer. The magnet may be coupled to a whipstock in the wellbore. An orientation of the downhole tool may be determined by the processor based on measurements from the magnetometer. The downhole tool may be steered based upon the determined orientation of the downhole tool.
  • This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
  • BRIEF DESCRIPTION OF THE DRAWINGS
  • So that the recited features may be understood in detail, a more particular description, briefly summarized above, may be had by reference to one or more embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings are illustrative embodiments, and are, therefore, not to be considered limiting of its scope.
  • FIG. 1 is a schematic cross-sectional view of an illustrative downhole tool cutting a window or opening in a casing, according to one or more embodiments of the present disclosure.
  • FIG. 2 is a schematic cross-sectional view of a downhole tool drilling a lateral or sidetracked borehole, according to one or more embodiments of the present disclosure.
  • FIG. 3 is a schematic cross-sectional view of wellbore casing and the downhole tool taken along line 3-3 in FIG. 2, according to one or more embodiments of the present disclosure.
  • FIG. 4 is the view shown in FIG. 3 after the downhole tool has rotated 90°, according to one or more embodiments of the present disclosure.
  • FIG. 5 is the view shown in FIG. 3 after the downhole tool has rotated 180°, according to one or more embodiments of the present disclosure.
  • FIG. 6 is the view shown in FIG. 3 after the downhole tool has rotated 270°, according to one or more embodiments of the present disclosure.
  • FIG. 7 schematically illustrates an example computing system for use a downhole tool, according to one or more embodiments of the present disclosure.
  • DETAILED DESCRIPTION
  • Some embodiments described herein generally relate to devices, systems, and methods for directional drilling. More particularly, some embodiments described herein generally relate to devices, systems, and methods for measuring the orientation of a downhole tool during the drilling of a lateral or sidetracked borehole.
  • As generally shown in FIG. 1, for example, a downhole tool 100 is illustrated. The illustrated downhole tool 100 may be used for a variety of functions within a primary wellbore, a lateral borehole, or other downhole environment. In one embodiment, for instance, the downhole tool 100 may be used for drilling a sidetracked borehole 106 (FIG. 2).
  • As shown in FIG. 1, the downhole tool 100 may, in some embodiments, include a body 137 having a bore 138 formed and extending axially at least partially therethrough. At least one magnetometer 150 may be within the bore 138 of the body 137, or in the body 137 around the bore 138. The magnetometer 150 may, in some embodiments, be arranged, designed, or otherwise configured to measure a magnetic field. A processor (e.g., processor 702 of FIG. 7) may be within the bore 138 and/or the body 137. In some embodiments, the processor may be in communication with the at least one magnetometer 150. Such a processor may be arranged, designed, or otherwise configured to receive measurements from the at least one magnetometer 150. Such measurements may be used by the processor or a component coupled thereto to determine an orientation of the downhole tool 100 based upon the received measurements, to provide instructions or control signals to maintain the orientation of the downhole tool 100, to change the orientation of the downhole tool 100 based upon the determined orientation, or for other purposes.
  • FIG. 1 is a schematic cross-sectional view of the illustrative downhole tool 100 as it may be used to, among other things, mill or otherwise cut a window or opening 110 in a casing 108, according to one or more embodiments. The downhole tool 100 may be in a wellbore 104, which may be formed in a subterranean formation 102. The wellbore 104 may have a casing 108 therein. The casing 108 may be made from any suitable material, such as metal or a metal alloy (e.g., steel), and may be production casing, production liner, intermediate casing, surface casing, conductor casing, or the like.
  • In some embodiments, a deflection member, such as a whipstock 120 may be positioned at a desired location within the wellbore 104. The location of the whipstock 120 may be measured based on a depth within the subterranean formation 102. In other embodiments, a distance from an opening or other characteristic of the wellbore 104 or subterranean formation 102 may be used to determine the location of the whipstock 120.
  • The whipstock 120 may include a surface 122 that is arcuate and/or inclined with respect to a longitudinal axis of the wellbore 104 and/or the casing 108. For example, the surface 122 of the whipstock 120 may be oriented at an angle 124 with respect to the longitudinal axis of the wellbore 104 and/or the casing 108. The angle 124 may vary along a length of the surface 122 and/or in different embodiments of the whipstock 120. For instance, the angle 124 may range from 1° to 45° or more. More particularly, the angle 124 may be within a range that includes lower and upper limits that include any of 1°, 2°, 3°, 4°, 5°, 7.5°, 10°, 12.5°, 15°, 20°, 30°, 45°, or values therebetween. In some embodiments, the angle 124 may range from 1° to 5°, from 5° to 10°, from 10° to 15°, from 15° to 20°, from 20° to 30°, or from 30° to 45°. In other embodiments, the angle 124 may be less than 1° or more than 45°.
  • The downhole tool 100 may include one or more tooling components. Example tooling components may include a mill 130 (e.g., a lead mill, window mill, taper mill, etc.), a rotary steerable tool (“RST”) or system (“RSS”) 140, a measurement while drilling (“MWD”) tool 160, a logging while drilling (“LWD”) tool, a stabilizer, a reamer, a section mill, or other components, or some combination of the foregoing. The term “downhole tool” should thus be broadly interpreted to include a variety of tools and may also encompass even a single component of a tool or system. For instance, the term “downhole tool,” when applied to a rotary steerable system, may include the entire system, a single component of the system, or any combination of one or more components of the system (e.g., the mill 130, the MWD tool 160, the rotary steerable tool 140, a control unit, a bend in a point-the-bit system, one or more pads in a push-the-bit system, or another component, or some combination of the foregoing).
  • The mill 130 may be or include a tool arranged, designed, or otherwise configured to grind metal (e.g., the casing 108). When the downhole tool 100 is lowered in the wellbore 104, the mill 130 may contact the whipstock 120, and the whipstock 120 may guide or direct the mill 130 radially-outward in a predetermined direction toward the inner surface of the casing 108. The mill 130 may include one or more cutting elements or surfaces that cut a window or opening 110 in the casing 108. The cutting elements or surfaces may be made from a superhard or superabrasive material such as a carbide (e.g., tungsten carbide).
  • The size of the opening 110 may vary based on a variety of factors, including the size of the wellbore 104 and the casing 108, the size of the mill 130, the angle 124 of the whipstock 120, and the like. In some embodiments, a height of the opening 110 may range from 5 cm to 30 m. For instance, the opening 110 may have a height within a range including lower and upper limits that include any of 5 cm, 10 cm, 20 cm, 30 cm, 50 cm, 1 m, 2 m, 3 m, 5 m, 6 m, 8 m, 10 m, 20 m, 30 m, and any value therebetween. More particularly, the height of the opening 110 may ranging from 5 cm to 10 cm, from 10 cm to 20 cm, from 20 cm to 30 cm, from 30 cm to 50 cm, from 50 cm to 75 cm, 75 cm to 1 m, from 1 m to 1.5 m, from 1.5 m to 3 m, from 3 m to 6 m, from 6 m to 8 m, from 8 m to 10 m, from 10 m to 20 m, or from 20 m to 30 m. In other embodiments, the height of the opening 110 may be less than 5 cm or more than 30 m. The opening 110 may have a width extending circumferentially around a portion of the circumference of the casing 108. In some embodiments, the maximum or average width of the opening 110 may be between 1% and 100% of the circumference of the casing 108. For instance, the opening 110 may extend around a portion of the circumference of the casing 108, with the maximum or average width ranging from 1% to 5%, from 5% to 10%, from 10% to 20%, from 20% to 30%, from 30% to 50%, from 50% to 75%, or from 75% to 100% of the circumference of the casing 108.
  • FIG. 2 is a schematic cross-sectional view of the downhole tool 100 of FIG. 1 as used to drill or otherwise form a borehole extending from the wellbore 104. The borehole that is formed may be referred to as a lateral, deviated, or sidetracked borehole 106, according to one or more embodiments of the present disclosure.
  • After the opening 110 is formed in the casing 108, the downhole tool 100 may be pulled out of the wellbore 104, and the mill 130 may be replaced with a drill bit 132. If the mill 130 is replaced with a drill bit 132, the mill 130 may be removed from the downhole tool and replaced by the drill bit 132, or the entire downhole tool carrying the mill 130 may be replaced by a tool including the drill bit 132. The drill bit 132 may be arranged, designed, or otherwise configured to drill a second or sidetracked borehole 106 that “kicks off” from the first or “original” or “primary” wellbore 104. In at least one embodiment, a single cutting tool (e.g., a mill, a bit, or a combination thereof) may be used to cut the opening 110 in the casing 108 and drill the sidetracked borehole 106 through the formation 102, such that downhole tool 100 is not tripped or pulled out of the wellbore 104 after the opening 110 is formed in the casing 108.
  • Referring now to FIGS. 1 and 2, a rotary steerable tool 140 may be coupled to and positioned above the mill 130 and/or the drill bit 132 in some embodiments of the present disclosure. The rotary steerable tool 140 may include a generally cylindrical body 142 having an axial bore 144 formed at least partially therethrough. The rotary steerable tool 140 may be arranged, designed, or otherwise configured to turn, direct, move, or “steer” the downhole tool 100 as the drill bit 132 drills the sidetracked borehole 106. In at least one embodiment, the body 142 may rotate as the drill bit 132 rotates and drills the sidetracked borehole 106. In such an embodiment, the body 142 may rotate at about the same speed as the drill bit 132, or at a different speed relative to the drill bit 132. In another embodiment, the body 142, or a portion thereof, may not rotate as the drill bit 132 drills the sidetracked borehole 106. For instance, the downhole tool 100 may include a downhole motor (e.g., a mud motor, turbine driven motor, etc.) which may rotate the drill bit 132 independent of the body 142.
  • According to some embodiments of the present disclosure, the rotary steerable tool 140 may include a “push the bit” tool, a “point the bit” tool, or a hybrid of “push the bit” and “point the bit” tools. A “push the bit” rotary steerable tool 140 may include one or more pads (not shown) on an outer surface of the body 142. For example, a plurality of pads may be circumferentially and/or axially offset from one another on the outer surface of the body 142. The pads may be arranged, designed, or otherwise configured to selectively move radially-outward to contact the subterranean formation 102 to push against the subterranean formation 102 and to “push the bit” in the desired direction.
  • A “point the bit” rotary steerable tool 140 may include a shaft (not shown) within the body 142. The shaft may be arranged, designed, or otherwise configured to bend within the body 142, which may thereby also cause the body 142 to bend. The bending of the body 142 may tilt or “point the bit” in the desired direction.
  • In at least some embodiments, a MWD tool 160 may be coupled to and positioned above the rotary steerable tool 140 and/or the drill bit 132 (or the mill 130). The MWD tool 160 may include a generally cylindrical body 162 having an axial bore 164 formed at least partially therethrough. The body 162 of the MWD tool 160 and the body 142 of the rotary steerable tool 140 may collectively form at least a portion of the body 137 of the downhole tool 100. Similarly, the axial bore 164 of the MWD tool 160 and the axial bore 144 of the rotary steerable tool 140 may collectively form a full or partial length of the bore 138 of the downhole tool 100.
  • The MWD tool 160 may operate by taking one or more measurements while the downhole tool 100 is positioned in the wellbore 104 and/or the sidetracked borehole 106. The measurements may include, but are not limited to, direction (e.g., inclination and/or azimuth), pressure, temperature, vibration (e.g., axial, lateral, or torsional), axial and/or rotational speed, torque, weight on bit, other measurements, or any combination of the foregoing. The measurements may be stored in the MWD tool 160, transmitted to the rotary steerable tool 140, transmitted to an operator or controller (e.g., to the surface using mud pulse telemetry, wired drill pipe, electromagnetic frequency transmissions, etc.), transmitted to another downhole component, or otherwise stored or transmitted.
  • One or more gyroscopes 146 may be coupled to the rotary steerable tool 140 and/or the MWD tool 160 in some embodiments of the present disclosure. For example, the gyroscope 146 may be within the body 142 of the rotary steerable tool 140 and/or within the body 162 of the MWD tool 160. The gyroscope 146 may measure the rate of rotation of a corresponding tool or component of the downhole tool 100. For instance, the gyroscope 146 may measure the rate of rotation of the rotary steerable tool 140, the drill bit 132, the MWD tool 160, other component, or some combination of the foregoing, during drilling operations.
  • One or more sensors, such as accelerometers 148, may also be coupled to the rotary steerable tool 140 and/or the MWD tool 160. For example, the accelerometers 148 may be on or within the body 142 of the rotary steerable tool 140 and/or on or within the body 162 of the MWD tool 160. Any number of accelerometers 148 may be used. Thus, although three accelerometers 148 are shown in FIG. 2, it should be appreciated by a person having ordinary skill in the art in view of the present disclosure that the number of accelerometers 148 may vary, and in some embodiments may range from 1 to 100 or more. For instance, the number of accelerometers may be from 1 to 5, from 5 to 10, from 10 to 15, from 15 to 20, from 20 to 50, from 50 to 100, or may be more than 100. The accelerometers 148 may be axially and/or circumferentially offset from one another. In FIG. 2, for instance, each accelerometer 148 is shown as being axially offset from each other accelerometer. The axial offset in such an embodiment may range from 0.05 m to 20 m or more. For instance, the axial distance between accelerometers 148 may be within a range having lower and upper limits that include any of 0.05 m, 0.1 m, 0.2 m, 0.3 m, 0.4 m, 0.5 m, 0.8 m, 1 m, 2 m, 3 m, 4 m, 5 m, 10 m, 15 m, 20 m, or values therebetween. As another example, the distance between the accelerometers 148 may be from 0.05 m to 0.25 m, from 0.25 m to 0.5 m, from 0.5 m to 1 m, from 1 m to 2 m, from 2 m to 10 m, or from 5 m to 20 m. In other embodiments, the axial distance between the accelerometers 148 may be less than 0.05 m or more than 20 m. The axial and/or circumferential separation between adjacent accelerometers 148 may be about the same as, or different from other adjacent accelerometers 148.
  • The accelerometers 148 may measure the acceleration of the downhole tool 100, which can include the acceleration the downhole tool 100 experiences relative to freefall. The measurements from the accelerometers 148 may be used to determine the orientation (e.g., drilling direction) of the downhole tool 100 and/or the drill bit 132 when the drill bit 132 is drilling the sidetracked borehole 106 in the subterranean formation 102. In some embodiments, the accelerometers 148 of FIG. 2 may have limited accuracy and/or reliability when an angle between the longitudinal axis of the downhole tool 100 and vertical is less than a predetermined value (e.g., when the downhole tool 100 is substantially vertical). For example, the accelerometers 148 may not obtain accurate or reliable measurements when the angular offset of the longitudinal axis of the downhole tool 100 and vertical is less than 2°, less than 5°, less than 10°, less than 20°, less than 30°, or less than 45°.
  • In some embodiments, one or more second sensors, such as magnetometers 150, may also be coupled to the rotary steerable tool 140 and/or the MWD tool 160. For example, the magnetometers 150 may be on or within the body 142 of the rotary steerable tool 140 and/or on or within the body 162 of the MWD tool 160. Although three magnetometers 150 are shown in FIG. 2, it should be appreciated in view of the disclosure herein that the number of magnetometers 150 may vary. In some embodiments, the number of magnetometers 150 may be about equal to the number of accelerometers 148, or the numbers may be different. In some embodiments, the number of magnetometers 150 may range from 1 to 100 or more. For instance, the number of magnetometers 150 may be from 1 to 5, from 5 to 10, from 10 to 15, from 15 to 20, from 20 to 50, from 50 to 100, or may be more than 100. The magnetometers 150 may also be circumferentially and/or axially offset from one another. Example distances of axial offset may range from 0.05 m to 20 m, or more. For instance, the axial distance between any magnetometers 150 may be within a range having lower and upper limits that include any of 0.05 m, 0.1 m, 0.2 m, 0.3 m, 0.4 m, 0.5 m, 0.8 m, 1 m, 2 m, 3 m, 4 m, 5 m, 10 m, 15 m, 20 m, or values therebetween. As another example, the distance between the magnetometers 150 may be from 0.05 m to 0.25 m, from 0.25 m to 0.5 m, from 0.5 m to 1 m, from 1 m to 2 m, from 2 m to 10 m, or from 5 m to 20 m. In other embodiments, the axial distance between the magnetometers 150 may be less than 0.05 m or more than 20 m. The axial and/or circumferential separation between adjacent magnetometers 150 may be about the same as, or different from other adjacent magnetometers 150.
  • In some embodiments, the magnetometers 150 may measure the strength and/or direction of one or more magnetic fields. The measurements from the magnetometers 150 may be used to determine the orientation (e.g., drilling direction) of the downhole tool 100 and/or the drill bit 132 when the drill bit 132 is drilling the sidetracked borehole 106 in the subterranean formation 102. For example, the magnetometers 150 may be used when the accelerometers 148 are unable to obtain accurate or reliable measurements.
  • According to some embodiments, when the magnetometers 150 are positioned within the casing 108, the casing 108 may interfere with the magnetometers 150 measuring of the Earth's magnetic field. More particularly, in some embodiments, the whipstock 120 may initially direct the downhole tool 100 in the desired direction while drilling through the subterranean formation 102. As drilling progresses, the downhole tool 100 may begin to deviate from the desired direction as a result of subterranean conditions, such as hole curvature and angle. The rotary steerable tool 140 may be used to steer the downhole tool 100 using measurements from the accelerometers 148 to attempt to correct the direction. If the sidetracked borehole 106 is sufficiently vertical, however, the accelerometers 148 may not obtain accurate or reliable orientation measurements. Instead, the magnetometers 150 coupled to the downhole tool 100 may be used to measure the orientation of the downhole tool 100 with respect to the Earth's magnetic field. The rotary steerable tool 140 may then be used to steer the downhole tool 100 with respect to this measured orientation.
  • When inside the wellbore 104, however, the casing 108 may interfere with the measurements taken by the magnetometers 150 until the magnetometers 150 are a sufficient distance away from the casing 108. In some embodiments, this sufficient distance may be equal to or greater than the diameter of the casing (e.g., 0.2 m, 0.35 m, 0.5 m, etc.). Further, as the magnetometers 150 may be positioned above/behind the drill bit 132 (e.g., 1 m, 2 m, 5 m, etc.), the drill bit 132 may drill a substantial distance before the magnetometers 150 are in a position to measure the orientation of the downhole tool 100, and the rotary steerable tool 140 is able to steer the downhole tool 100 in the desired direction in response to this measured orientation. As such, the downhole tool 100 may become deviated from the desired direction during this period of “blind” drilling.
  • To overcome the period of blind drilling, some embodiments of the present disclosure contemplate positioning one or more magnets 126 within the casing 108 to orient or otherwise be used by the magnetometers 150, and to overcome the interference by the casing 108. The magnets 126 may, in some embodiments, be permanent magnets made of one or more ferromagnetic or ferrimagnetic materials, such as iron, nickel, cobalt, alloys thereof, and the like. The magnets 126 may be located in the casing 108, in the whipstock 120, in some other component, or in a combination of the foregoing. In general, the magnets 126 may be powerful enough to be identified by the magnetometers 150 through residual magnetism of the casing 108. Optionally, one or more components of the casing 108 (e.g., the last one or more casing joints and/or shoes) may be made of a non-magnetic material. Although three magnets 126 are shown, it should be appreciated in view of the disclosure herein that the number of magnets 126 may vary, and in some embodiments there may be from 1 to 100 or more magnets 126. For instance, the number of magnets 126 may vary from 1 to 5, from 5 to 10, from 10 to 15, from 15 to 20, from 20 to 50, or from 50 to 100 or more.
  • The magnets 126 may be substantially stationary in the casing 108 during a drilling or milling operation. For example, the magnets 126 may be embedded in or otherwise coupled to the casing 108 and/or the whipstock 120. The magnets 126 may be axially, radially, circumferentially, or otherwise offset from one another. In some embodiments, a distance of axial offset may range from 0.05 m to 30 m. For instance, the distance of axial offset may be within a range having lower and/or upper limits that include any of 0.05 m, 0.1 m, 0.2 m, 0.3 m, 0.4 m, or 0.5 m to 0.8 m, 1 m, 2 m, 3 m, 4 m, 5 m, 7.5 m, 10 m, 20 m, 30 m, or values therebetween. For example, the axial distance between the magnets 126 may be from 0.05 m to 0.25 m, from 0.25 m to 0.5 m, from 0.5 m to 1 m, from 1 m to 2 m, from 2 m to 5 m, from 5 m to 15 m, or from 10 m to 30 m. In some embodiments, the magnets 126 and/or the magnetometers 150 may be spaced apart such that each magnetometer 150 senses one magnet 126 (or vice versa) at a time (or primarily one magnet 126 at a time). In at least some embodiments, the magnetometers 150 may sense the magnets 126 in a single rotational position of the body 137 (e.g., when the magnetometers 150 are rotated to be directly facing the magnets 126). In other embodiments, however, the magnetometers 150 may sense the magnets 126 regardless of the particular rotational position of the body 137, or in multiple rotational positions of the body 137.
  • The magnets 126 may be oriented so that each magnet 126 has a magnetic field component 128 (see FIGS. 3-6) at a predetermined angle with respect to a longitudinal axis of the wellbore 104 and/or the casing 108. For example, potentially each magnet 126 may have the magnetic field component 128 in a plane that is about perpendicular to the longitudinal axis of the wellbore 104 and/or the casing 108. In other embodiments, some magnetic field components 128 may be in planes that are otherwise oriented (or even parallel to) the longitudinal axis of the wellbore 104.
  • A computing system may also be coupled to the rotary steerable tool 140 and/or the MWD tool 160. Such a computing system may be on or within the body 142 of the rotary steerable tool 140 and/or on or within the body 162 of the MWD tool 160, in some embodiments of the present disclosure. The computing system may receive the measurements from the gyroscope 146, the accelerometers 148, the magnetometers 150, other sensors, or combinations of the foregoing, and determine the orientation of the downhole tool 100 and/or the drill bit 132 while the drill bit 132 is drilling the sidetracked borehole 106 in the subterranean formation 102. An example computing system suitable for such use includes computing system 700 which is shown and described in more detail with reference to FIG. 7.
  • FIGS. 3-6 are example schematic cross-sectional views of the casing 108 and the downhole tool 100 taken along line 3-3 in FIG. 2. The magnetometers 150 may be positioned within the downhole tool 100 such that a longitudinal centerline or axis of the downhole tool 100 may extend through a center or other portion of at least some of the magnetometers 150. Although not shown, in another embodiment, the magnetometers 150 may be offset (i.e., positioned radially-outward) from the longitudinal axis of the downhole tool 100.
  • The magnetometers 150 may take measurements along a single axis, two axes, or three axes. For example, the magnetometers 150 may be tri-axial magnetometers having three axes. A first or “X” axis 152 may be perpendicular to the longitudinal axis of the downhole tool 100. A second or “Y” axis 154 may be perpendicular to the longitudinal axis of the downhole tool 100 and perpendicular to the X axis 152. A third or “Z” axis may be parallel and/or co-axial with the longitudinal axis of the downhole tool 100, and perpendicular to the X and Y axes 152, 154 (i.e., extending into, or out of, the page in FIG. 3).
  • Referring back to FIG. 2, in at least one embodiment, at least a portion of the rotary steerable tool 140 and/or the MWD tool 160 may not rotate as the drill bit 132 drills the sidetracked borehole 106. As such, the magnetometers 150 may not rotate as the drill bit 132 drills the sidetracked borehole 106. In such an embodiment, the magnetometers 150 may be considered to be geostationary.
  • In another embodiment, the rotary steerable tool 140 and/or the MWD tool 160 may rotate as the drill bit 132 drills the sidetracked borehole 106. When the rotary steerable tool 140 and/or the MWD tool 160 rotate, the magnetometers 150 may or may not be geostationary. For example, the magnetometers 150 may be geostationary if within or coupled to a gyroscopic device such that the magnetometers 150 do not rotate with respect to the surrounding formation 102 during drilling operations.
  • In another embodiment, when the rotary steerable tool 140 and/or the MWD tool 160 rotate, the magnetometers 150 may rotate therewith. When the magnetometers 150 rotate, the measurements of the magnetic field component 128 of the magnets 126 may vary along the X and Y axes 152, 154 of FIG. 3, while in some embodiments the measurements may remain constant along the Z axis.
  • The measurements taken by the magnetometers 150 along one or more of the X axis 152, the Y axis 154, or the Z axis may be used to determine the orientation of the downhole tool 100 and/or the drill bit 132 when the drill bit 132 is drilling the sidetracked borehole 106 in the subterranean formation 102 (see FIG. 2). For example, the measurements taken by the magnetometers 150 may be represented by the illustrative equation M=X cos(0)+Y sin(0), where M is the total magnitude of the magnetic field component 128, X is the magnitude of the magnetic field component 128 along the X axis 152, Y is the magnitude of the magnetic field component 128 along the Y axis 154, and 0 is the degree of rotation of the downhole tool 100 with respect to the magnets 126. In this embodiment, Z may be omitted from the equation as Z may be constant. Additionally, as discussed herein, the magnets 126 may be stationary in some embodiments.
  • With continued reference to FIG. 3, a first illustrative measurement may be taken when the downhole tool 100 is oriented at an initial angle (e.g., θ=0°) with respect to the magnets 126 or the magnetic field components 128 thereof. When θ=0° (e.g., when the Y axis 154 is parallel to the plane of the magnetic field component 128), the total magnitude of the magnetic field M measured by the magnetometers 150 may be X.
  • FIG. 4 depicts the view shown in FIG. 3 after the downhole tool 100 has rotated 90°, according to one or more embodiments. A second illustrative measurement may be taken after the downhole tool 100 has rotated 90° (i.e., θ=90°). When θ=90°, the total magnitude of the magnetic field M measured by the magnetometers 150 may be Y as the X axis 152 may be parallel to the plane of the magnetic field component 128.
  • FIG. 5 depicts the view shown in FIG. 3 after the downhole tool 100 has rotated 180°, according to one or more embodiments. A third illustrative measurement may be taken after the downhole tool 100 has rotated 180° (i.e., θ=180°). When θ=180°, the total magnitude of the magnetic field M measured by the magnetometers 150 may be −X.
  • FIG. 6 depicts the view shown in FIG. 3 after the downhole tool 100 has rotated 270°, according to one or more embodiments. A fourth illustrative measurement may be taken after the downhole tool 100 has rotated 270° (i.e., θ=270°). When θ=270°, the total magnitude of the magnetic field M measured by the magnetometers 150 may be −Y. Of course, the embodiments illustrated in FIGS. 3-6 are merely illustrative, and other or additional measurements may be taken. Indeed, at other rotations (e.g., when θ=30°, 45°, 60°, etc.), the magnitude of the magnetic field M measured by the magnetometers 150 may be based on X and Y components.
  • A computing system (e.g., computing system 700 of FIG. 7) may receive the measurements and use the measurements to determine the orientation of the downhole tool 100 with respect to the known position of the magnets 126 and/or the magnetic field component 128. Although four measurements are shown and described with respect to a single revolution of the downhole tool 100 in FIGS. 3-6, it should be appreciated that a measurement may be taken each time the downhole tool 100 rotates from 0.01° to 90°. In more particular embodiments, measurements may be taken each time the downhole tool 100 rotates an amount within a range that includes a lower and/or upper limit that includes any of 0.01°, 0.05°, 0.1°, 0.5°, 1°, 5°, 10°, 20°, 30°, 45°, 60°, 90°, or values therebetween. Thus, the number of measurements taken by the magnetometers 150 per revolution of the downhole tool 100 may vary. For instance, the number of measurements per revolution may be from 1 (i.e., one measurement every 360°) to 36,000 (i.e., one measurement every 0.1°). More particularly, the number of measurements per revolution may be from 1 to 4, from 4 to 10, from 10 to 20, from 20 to 30, from 30 to 45, from 45 to 90, from 90 to 180, from 180 to 360, from 360 to 720, from 720 to 3,600, from 3,600 to 7,200, or from 7,200 to 36,000 or more. In at least one embodiment, the measurements may be taken continuously or substantially continuously. As should be appreciated in view of the disclosure herein, in other embodiments, less than one measurement per revolution may be made, or more than 36,000 measurements per full revolution may be made.
  • FIG. 7 is a schematic view of a computing system 700 that may be coupled to, and optionally located within, the downhole tool 100, according to one or more embodiments. The computing system 700 may be within the rotary steerable tool 140, within the MWD tool 160, or within the drilling bit 132 (see FIG. 2), or within another downhole component. The computing system 700 may also be distributed among multiple components. In at least some embodiments, the computing system 700 may be fully or partially located at the surface, at one or more remote surface locations, or at one or more remote downhole locations.
  • The computing system 700 may include one or more processors, microprocessors, or central processing units (“CPU”) 702, input devices such as keyboards 704 and/or display devices or monitors 706. The display devices or monitors 706 may be used as output devices in the same or other embodiments. The computing system 700 may also include data storage 720 such as memory, hard drives, solid state storage, and the like, to store data, software, firmware, or program information. The computing system 700 may also include additional input and/or output devices. For instance, the computing system 700 may include additional input devices such as a mouse 710 or a microphone 712. Other example input devices may include track balls, biometric readers, touch sensitive components, cameras, motion sensors, and the like. Example output devices of the computing system 700 may include a speaker 714. Components may also be used as both input and output devices. For instance, the monitor 706 may be touch-sensitive to operate as an input device as well as an output or display device. Moreover, various components (e.g., the microphone 712 and speaker 714) may be integrated together or may be used for universal access and voice recognition or commanding. As should be appreciated, in at least one embodiment, if the computing system 700 is fully or partially within the downhole tool 100, one or more of the aforementioned components (e.g., the mouse 710, microphone 712, speaker 714, monitor 706) may be omitted or located elsewhere (e.g., at the surface).
  • The computing system 700 may interface with, or include, a database 716, a processor 718, or a communication network (e.g., the Internet, a LAN, a WAN, an Intranet, etc.) via an interface 720. It should also be understood that the database 716 and the processor 718 are not limited to interfacing with computing system 700 using the network interface 720 and can interface with the computing system 700 in any manner sufficient to create a communication path between the computing system 700 and the database 716 and/or the processor 718. For example, in an illustrative embodiment, the database 716 may interface with the computing system 700 via a USB or other serial or parallel communication interface, while the processor 718 may interface via another high-speed data bus without using the network interface 720. The database 716 or processor 718 may also be included within the computing system 700.
  • The computing system 700 may be coupled to and/or receive signals from the gyroscope 146, the accelerometers 148, the magnetometers 150, other sensors (e.g., RFID tags, material sensors, etc.). The signals may communicate the measurements taken by the gyroscope 146, the accelerometers 148, the magnetometers 150, other measurement or logging tools, or some combination of the foregoing. The processor 702 of the computing system 700 may be configured to execute a computer program or instructions stored a computer readable medium. Computer readable media may embody two distinct types of media, namely computer readable storage media, and computer readable transmission media. Computer readable media that store computer-executable instructions are computer readable storage media. Computer readable media that carry computer-executable instructions are computer readable transmission media.
  • Computer readable storage media includes RAM, ROM, EEPROM, CD-ROM or other optical disk storage, magnetic disk storage or other magnetic storage devices, solid state memory devices, or any other physical medium which can be used to store desired program code or instructions in the form of computer-executable code/instructions or data structures and which can be accessed by a general purpose or special purpose computing system.
  • Computer readable transmission media typically 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 include any information-delivery media. By way of example, and not limitation, computer readable transmission media includes wired media, such as wired networks and direct-wired connections, and wireless media such as acoustic, radio, infrared, and other wireless media. When information is transferred or provided over a network or another communications connection (either hardwired, wireless, or a combination of hardwired or wireless) to or within a computing system, the computing system properly views the connection as a computer readable transmission medium. Communication channels and network and/or data links which can be used to carry or transmit desired program code in the form of computer-executable instructions and/or data structures which can be received or accessed by a general purpose or special purpose computer are also examples of computer readable transmission media.
  • Combinations of computer readable storage media and computer readable transmission media should also be included within the scope of computer readable media. Further, upon reaching various computing system components, program code in the form of computer-executable instructions or data structures can be transferred automatically from computer readable transmission media to computer readable storage media (or vice versa). For example, computer-executable instructions or data structures received over a network or data link can be buffered in RAM within a network interface module, and then eventually transferred to computing system RAM and/or to less volatile computer readable storage media at a computing system. Thus, it should be understood that computer readable storage media can be included in computing system components that also (or possibly primarily) make use of computer readable transmission media.
  • When executed by the processor 702, the computer program may determine the orientation of a downhole tool and/or drill bit (e.g., downhole tool 100 and drill bit 132 of FIG. 2) based on the measurements from gyroscopes, accelerometers, magnetometers, other sensors, or any combination of the foregoing (e.g., the measurements M). In response to the determined orientation, the computing system 700 may provide instructions or control signals that may be used to cause a rotary steerable tool or other directional drilling device to either maintain the current orientation of the downhole tool as the drill bit drills the sidetracked borehole or to cause the rotary steerable tool to change (i.e., turn) the orientation of the downhole tool as the drill bit drills the sidetracked borehole.
  • It should be understood that even though the computing system 700 is shown as a platform on which the illustrative methods described may be performed, the methods described may be performed on a number of computer or microprocessor based platforms. For example, the various illustrative embodiments described herein may be used or implemented on any device that has computing/processing capability. These devices may include, but are not limited to: supercomputers; arrayed server networks; arrayed memory networks; arrayed computer networks; distributed server networks; distributed memory networks; distributed computer networks; desktop personal computers (PCs); tablet PCs; hand held PCs; laptops; netbooks; cellular phones; smart phones; hand held media players; or any other device or system having computing capabilities.
  • In operation, and with reference to FIGS. 2 and 7, the whipstock 120 may be positioned and/or anchored in the casing 108 at the desired location and orientation. The location may be the initiation point for the sidetracked borehole 106. Once the whipstock 120 is secured in place, the downhole tool 100 may be lowered into the casing 108 until the mill 130 contacts the whipstock 120. In another embodiment, the whipstock and mill 130 may be part of a single-trip system and the mill 130 may be released from the whipstock 120 rather than tripped separately into the wellbore 104. In either embodiment, the inclined surface 122 of the whipstock 120 may guide or direct the mill 130 radially-outward in a predetermined direction toward the inner surface of the casing 108 as the mill 130 moves axially downhole. The mill 130 may rotate and may cut the opening 110 in the casing 108 when deflected radially into the casing 108.
  • The downhole tool 100 may be pulled out of the casing 108, and the mill 130 may be removed and replaced by the drill bit 132. Once the drill bit 132 is secured to the downhole tool 100, the downhole tool 100 may be lowered into the casing 108, and the inclined surface 122 of the whipstock 120 may direct or guide the drill bit 132 through the opening 110 and into contact with the subterranean formation 102. The drill bit 132 may then begin drilling the sidetracked borehole 106. In another embodiment, the mill 130 may be a mill-and-drill bit, and may thus include the drill bit 132 such that drilling of the sidetracked borehole 106 may be performed in a same trip during which the opening 110 is formed.
  • The memory 708 of the computing system 700 may have a predetermined drill path for the sidetracked borehole 106 stored thereon, or accessible thereto, before the downhole tool 100 is run into the wellbore 104 and/or the sidetracked borehole 106. In another embodiment, a predetermined drill path may be communicated to the memory 708 and/or processor 702 of the computing system 700 from the surface while the downhole tool 100 is in the wellbore 104 and/or the sidetracked borehole 106. In some embodiments, the drill path may be dynamically determined at the surface and communicated to the memory 708 and/or processor 702 of the computing system 700 while the downhole tool 100 is in the wellbore 104 and/or the sidetracked borehole 106.
  • As the drill bit 132 drills the sidetracked borehole 106, the computing system 700 may receive intermittent or continuous measurements from the gyroscope 146, the accelerometers 148, the magnetometers 150, other sensors, or some combination thereof. In one embodiment, for instance, the gyroscope 146, accelerometers 148, and magnetometers 150 may begin functioning once in a wellbore or borehole, and can immediately begin sending continuous measurements to the computing system 700. In other embodiments, the measurements may be sent at predetermined or other time or distance intervals (e.g., once per 0.5 second, once per second, once every 5 seconds, once every 10 feet, once every 50 feet, etc.). In still other embodiments, the gyroscope 146, accelerometers 148, magnetometers 150, other tools, or some combination thereof may operate for a portion of a trip within a wellbore or borehole. As an illustration, the various devices may begin operation during the last 50 m to 200 m of a trip, and can transmit measurements continuously or intermittently during that period of time. Of course, the devices could also selectively operate during other times as well. For instance, there may be a zone within a wellbore or borehole in which the drill bit 132 has drilled a sufficient length of the sidetracked borehole 106 that the magnetometers 150 may be unable to obtain a significant reading from the magnets 126, yet close enough to the casing 108 to be affected by magnetic interference from the casing 108. In such a zone, particularly if there is low enough inclination and the accelerometers 148 do not present accurate or reliable results, some embodiments contemplate using the gyroscope(s) 146 to obtain measurements used for steering and orientation. Once the accelerometers 148 are sufficiently far from the casing 108, or sufficient inclination has built, the accelerometers 148 may be again used for steering and orientation.
  • The computing system 700 may use measurements to determine the orientation of the downhole tool 100. For example, the computing system 700 may determine the orientation of the downhole tool 100 with respect to the known position of the magnets 126. As discussed herein, in some embodiments, the magnets 126 may be stationary within the wellbore 104.
  • The orientation of the downhole tool 100 may be compared to the drill path stored in the memory 708 of the computing system 700, or otherwise accessible thereto. If the orientation places the downhole tool 100 substantially along the drill path, then the computing system 700 may cause the rotary steerable tool 140 to maintain the current orientation of the downhole tool 100 as the drill bit 132 drills the sidetracked borehole 106. If, however, the orientation does not place the downhole tool 100 substantially along the predetermined or otherwise determined drill path, the computing system 700 may cause the rotary steerable tool 140 to change (i.e., turn) the orientation of the downhole tool 100 to line up with the predetermined drill path as the drill bit 132 drills the sidetracked borehole 106. As used herein, “substantially along the predetermined drill path” may mean that the actual drill path is within 20 m, 10 m, 5 m, 1 m, 0.5 m, or 0.25 m, or less, of a predetermined determined drill path.
  • Using embodiments of the present disclosure, the orientation of the downhole tool 100 may be wholly or partially determined downhole, as opposed to fully at the surface. This may save the time it takes to transmit the measurements from the downhole tool 100 up to the surface and the time it takes to then transmit the determined orientation from the surface back down to the downhole tool 100. In addition, the controlling of the rotary steerable tool 140 may also take place downhole, as opposed to at the surface, thereby saving additional time.
  • Further different sensors or other components may be used at different times or locations, depending on the orientation, location, position, or other characteristic of the downhole tool. For instance, while within the wellbore 104, the downhole tool 100 may optionally be oriented about parallel to the longitudinal axis of the wellbore 104, and the accelerometers 148 may have reduced accuracy. In such an embodiment, the magnetometers 150 (potentially in combination with the magnets 126) may be used to direct and orient the downhole tool 100. As the downhole tool 100 is deflected and angularly offset from the longitudinal axis of the wellbore 104, the accelerometers 148 may have increased accuracy, and the accelerometers 148 may be partially, or even primarily, used to produce measurements used by a computing device to determine orientation.
  • While embodiments of the disclosure herein specifically describe the use of magnets 126, magnetometers 150, and accelerometers 148, other embodiments are also contemplated as within the scope of the present disclosure which may use additional or other devices. For instance, magnets 126 and/or magnetometers 150 may include RFID tags (e.g., passive or active RFID tags) and RFID readers. Thus, rather than detecting a magnetic field, an RFID reader may pick up direct proximity to an RFID tag to determine orientation and/or location. Material properties may also be used. For instance, magnets 126 may be replaced by, or supplemented with, different materials, and sensors for detecting different materials may be used to determine proximity to specific, different locations of the magnets 126. Other proximity, orientation, material, or other properties may also be detected and used in accordance with embodiments of the present disclosure.
  • In the description herein, various relational terms are provided to facilitate an understanding of various aspects of some embodiments of the present disclosure. Relational terms such as “bottom,” “below,” “top,” “above,” “back,” “front,” “left,” “right,” “rear,” “forward,” “up,” “down,” “horizontal,” “vertical,” “clockwise,” “counterclockwise,” “upper,” “lower,” “uphole,” “downhole,” and the like, may be used to describe various components, including their operation and/or illustrated position relative to one or more other components. Relational terms do not indicate a particular orientation for each embodiment within the scope of the description or claims. For example, a component of a bottomhole assembly that is described as “below” another component may be further from the surface while within a vertical wellbore, but may have a different orientation during assembly, when removed from the wellbore, or in a deviated or other lateral or sidetracked borehole. Accordingly, relational descriptions are intended solely for convenience in facilitating reference to various components, but such relational aspects may be reversed, flipped, rotated, moved in space, placed in a diagonal orientation or position, placed horizontally or vertically, or similarly modified. Certain descriptions or designations of components as “first,” “second,” “third,” and the like may also be used to differentiate between identical components or between components which are similar in use, structure, or operation. Such language is not intended to limit a component to a singular designation. As such, a component referenced in the specification as the “first” component may be the same or different than a component that is referenced in the claims as a “first” component.
  • Furthermore, while the description or claims may refer to “an additional” or “other” element, feature, aspect, component, or the like, it does not preclude there being a single element, or more than one, of the additional or other element. Where the claims or description refer to “a” or “an” element, such reference is not be construed that there is just one of that element, but is instead to be inclusive of other components and understood as “at least one” of the element. It is to be understood that where the specification states that a component, feature, structure, function, or characteristic “may,” “might,” “can,” or “could” be included, that particular component, feature, structure, or characteristic is provided in some embodiments, but is optional for other embodiments of the present disclosure. The terms “couple,” “coupled,” “connect,” “connection,” “connected,” “in connection with,” and “connecting” refer to “in direct connection with,” or “in connection with via one or more intermediate elements or members.” Components that are “integral” or “integrally” formed include components made from the same piece of material, or sets of materials, such as by being commonly molded or cast from the same material, or machined from the same one or more pieces of material stock. Components that are “integral” should also be understood to be “coupled” together.
  • Although various example embodiments have been described in detail herein, those skilled in the art will readily appreciate in view of the present disclosure that many modifications are possible in the example embodiments without materially departing from the present disclosure. Accordingly, any such modifications are intended to be included in the scope of this disclosure. Likewise, while the disclosure herein contains many specifics, these specifics should not be construed as limiting the scope of the disclosure or of any of the appended claims, but merely as providing information pertinent to one or more specific embodiments that may fall within the scope of the disclosure and the appended claims. Any described features from the various embodiments disclosed may be employed in any combination. Features and aspects of methods described herein may be performed in any order.
  • A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function in a different matter. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.
  • While embodiments disclosed herein may be used in oil, gas, or other hydrocarbon exploration or production environments, such environments are merely illustrative. Systems, tools, assemblies, methods, milling systems, drilling systems, and other components of the present disclosure, or which would be appreciated in view of the disclosure herein, may be used in other applications and environments. In other embodiments, milling tools, drilling tools, sidetracking systems, directional drilling systems, methods of milling, methods of drilling, or other embodiments discussed herein, or which would be appreciated in view of the disclosure herein, may be used outside of a downhole environment, including in connection with other systems, including within automotive, aquatic, aerospace, hydroelectric, manufacturing, other industries, or even in other downhole environments. The terms “well,” “wellbore,” “borehole,” and the like are not intended to limit embodiments of the present disclosure to a particular industry. A wellbore or borehole may, for instance, be used for oil and gas production and exploration, water production and exploration, mining, utility line placement, or myriad other applications.
  • Certain embodiments and features may have been described using a set of numerical values that may provide lower and upper limits. It should be appreciated that ranges including the combination of any two values are contemplated unless otherwise indicated, and that a single value may be defined as an upper or as a lower limit. Numbers, percentages, ratios, measurements, or other values stated herein are intended to include the stated value as well as other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least experimental error and variations that would be expected by a person having ordinary skill in the art, as well as the variation to be expected in a suitable manufacturing or production process. A value that is about or approximately the stated value and is therefore encompassed by the stated value may further include values that are within 10%, within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.
  • The Abstract included with this disclosure is provided to allow the reader to quickly ascertain the general nature of some embodiments of the present disclosure. The Abstract is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Claims (20)

What is claimed is:
1. A downhole tool for drilling a sidetracked borehole, comprising:
a body having an axial bore formed at least partially therethrough;
at least one magnetometer coupled to the body, the magnetometer configured to measure a magnetic field; and
a processor in communication with the at least one magnetometer, the processor configured to:
receive measurements from the at least one magnetometer;
determine an orientation of the downhole tool based upon the received measurements; and
maintain the orientation of the downhole tool or change the orientation of the downhole tool based upon the determined orientation of the downhole tool.
2. The downhole tool of claim 1, further comprising:
a drill bit coupled to the body.
3. The downhole tool of claim 2, the at least one magnetometer being configured to rotate with the body or drill bit.
4. The downhole tool of claim 2, the at least one magnetometer being configured to be substantially geostationary as the body or dill bit rotates.
5. The downhole tool of claim 1, the magnetometer being configured to measure a magnetic field generated by at least one magnet within a wellbore.
6. The downhole tool of claim 5, the at least one magnet coupled to a deflection member within a metal casing within the wellbore.
7. The downhole tool of claim 1, the at least one magnetometer including two or more magnetometers that are axially offset from one another by a distance from 0.05 m to 2 m.
8. The downhole tool of claim 1, further comprising:
at least one accelerometer coupled to the body.
9. The downhole tool of claim 8, further comprising:
at least one gyroscope coupled to the body, the gyroscope configured to measure rotation of the body.
10. The downhole tool of claim 1, wherein the body comprises a rotary steerable tool.
11. A method of drilling, comprising:
running a downhole tool into a wellbore having casing therein, the downhole tool including:
a body having an axial bore formed at least partially therethrough;
a plurality of sensors within the axial bore of the body, the plurality of sensors including a first sensor having limited accuracy within the wellbore, and a second sensor being susceptible to interference from the casing; and
a processor coupled to the body and in communication with the plurality of sensors;
drilling a borehole that diverts from the wellbore;
obtaining location or orientation data using the plurality of sensors;
determining an orientation of the downhole tool with the processor based upon location or orientation data obtained by the second sensor while within the wellbore; and
steering the downhole tool based upon the determined orientation of the downhole tool.
12. The method of claim 11, wherein the second sensor includes a magnetometer and obtaining location or orientation data includes obtaining magnetic field data generated by at least one magnet in the wellbore, which at least one magnet overcomes interference from the casing.
13. The method of claim 13, the at least one magnet being coupled to a deflection member within the wellbore.
14. The method of claim 13, the first sensor having limited accuracy while oriented in a substantially vertical direction.
15. A method of drilling, comprising:
forming an opening in a metal casing within a wellbore;
drilling a sidetracked borehole diverting from the wellbore at the opening in the metal casing using a downhole tool including:
a body;
at least one magnetometer coupled to the body;
a processor coupled to the body and in communication with the at least one magnetometer; and
a drill bit coupled to the body;
measuring a magnetic field generated by at least one magnet within the metal casing with the at least one magnetometer, the at least one magnet being coupled to a whipstock within the wellbore;
determining an orientation of the downhole tool with the processor based upon measurements from the at least one magnetometer; and
steering the downhole tool based upon the determined orientation of the downhole tool.
16. The method of claim 15, further comprising rotating the body as the drill bit drills the sidetracked borehole.
17. The method of claim 16, the at least one magnetometer being configured to rotate with the body.
18. The method of claim 16, the at least one magnetometer being substantially geostationary.
19. The method of claim 15, the at least one magnetometer including at least two magnetometers, and the at least one magnet including at least two magnets, a spacing between the at least two magnetometers being about equal to a spacing between the at least two magnets.
20. The method of claim 15, wherein steering the downhole tool further includes:
maintaining the orientation of the downhole tool when the orientation is substantially aligned with a predetermined drill path for the sidetracked borehole; and
turning the downhole tool when the orientation is not substantially aligned with the predetermined drill path.
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