Apparatus, system and method for downhole survey

Abstract

A drilling system may include a steerable tool configured to engage with a wellbore wall to guide an orientation of a tool face, the steerable tool rotatable about an axis of rotation. A drilling system may include an orientation sensor pack, the orientation sensor package includes at least one of a multi-axis gyroscope orientation sensor rotatable about the axis of rotation of the steering tool, a multi-axis magnetic orientation sensor rotatable about the axis of rotation of the steering tool, or an accelerometer orientation sensor rotatable about the axis of rotation of the steering tool.

Description

[0001] Cross - Reference to Related Applications

[0002] This application claims the benefit and priority of U.S. Provisional Patent Application No. 63 / 378,282, filed on October 4, 2022, entitled DEVICES, SYSTEMS, AND METHODS FOR DOWNHOLE SURVEYING, which is hereby incorporated by reference in its entirety. Background Art

[0003] Modern drilling operations can change the trajectory of a wellbore through a directional drilling process. During drilling, it may be necessary to determine the position and / or the drilling trajectory. Surveying instruments located on downhole tools can be used to measure azimuth, inclination, and other surveying information. The surveying instruments can include multi - axis gyro sensors (such as MEMS (Micro - Electro - Mechanical System) gyroscopes), multi - axis magnetic sensors, or accelerometer sensors. Using the survey data, the downhole tool can determine direction information, including the azimuth and / or inclination of the downhole tool.

[0004] In conventional drilling and measurement - while - drilling (MWD) operations, the wellbore inclination and the wellbore azimuth are determined at multiple discrete longitudinal points along the axis of the wellbore. These discrete measurements can be combined into a survey of the well and used to calculate a three - dimensional well path (e.g., using the minimum curvature or other curvature assumptions). The wellbore inclination is typically derived (calculated) from tri - axial accelerometer measurements of the Earth's gravity field. The wellbore azimuth (usually also referred to as the magnetic azimuth) is typically derived from a combination of tri - axial accelerometer and tri - axial magnetometer measurements of the Earth's gravity field and magnetic field.

[0005] Static survey measurements are typically taken when drilling is temporarily stopped (e.g., when adding a new drill pipe section to the drill string) and the drill bit is lifted off the bottom. Such static measurements are typically taken at measurement depth intervals in the range of about 30 feet to about 90 feet. While these static survey measurements may be sufficient in some operations to obtain a well path with appropriate accuracy, such static survey measurements are very time - consuming because they require temporarily stopping drilling and lifting the drill string off the bottom of the wellbore.

[0006] Although the use of dynamic survey measurements is well - known, such measurements tend to be error - prone due to, for example, magnetic interferences such as vortex - induced magnetic fields and uncompensated magnetometer biases. Summary of the Invention

[0007] In some aspects, the techniques described herein relate to a rotary steerable system for drilling a subterranean wellbore. The rotary steerable system includes a roll-stabilized housing deployed within a drill collar. The drill collar is configured to rotate with the drill string, and the roll-stabilized housing is configured to rotate independently of the drill collar during drilling. An azimuth sensor package includes a multi-axis gyroscopic azimuth sensor rotatable about the axis of rotation of the roll-stabilized housing. The azimuth sensor package includes at least one of: a rotation rate sensor configured to measure the rotation rate of the drill collar; a set of three-axis accelerometers; and a set of three-axis magnetometers deployed within the roll-stabilized housing.

[0008] In some aspects, the techniques described herein relate to a method for drilling a subterranean wellbore. The method includes rotating a bottom hole assembly (BHA) within the subterranean wellbore to drill the wellbore. The BHA includes a roll-stabilized housing deployed within a drill collar and is configured to rotate relative to the drill collar. The BHA also includes a set of three-axis accelerometers, a set of three-axis magnetometers, and a gyroscopic azimuth sensor deployed within the roll-stabilized housing. A steerable drilling system uses the gyroscopic azimuth sensor to collect azimuth measurements. Using the set of three-axis accelerometers and the set of three-axis magnetometers, the steerable drilling system makes corresponding three-axis accelerometer measurements and three-axis magnetometer measurements while the BHA rotates. The steerable drilling system measures the rotation rate of the drill collar while the BHA rotates. The steerable drilling system uses the azimuth measurements to generate a tool face of the BHA. The steerable drilling system uses the tool face of the BHA, the three-axis magnetometer measurements, and the rotation rate to generate an azimuth of the BHA.

[0009] The present invention content is provided to introduce a series of concepts further described in the detailed description. The present invention content is not intended to identify the key or essential features of the claimed subject matter, nor is it intended to be used to help limit the scope of the claimed subject matter. Additional features and aspects of the embodiments of the present disclosure will be set forth herein and will be partially apparent from the description, or may be learned by practicing such embodiments. BRIEF DESCRIPTION OF THE DRAWINGS

[0010] To describe the manner in which the above and other features of the present disclosure can be obtained, a more particular description will be presented by reference to specific embodiments illustrated in the drawings of the present disclosure. For better understanding, throughout the various drawings, the same elements have been denoted by the same reference numerals. Although some of the drawings may be schematic diagrams or exaggerated representations of concepts, at least some of the drawings may be drawn to scale. It should be understood that the drawings depict some example embodiments and that the embodiments will be described and explained more specifically and in detail by using the drawings, in which:

[0011] Figure 1is a schematic diagram of a drilling system for drilling a surface formation to form a wellbore according to at least one embodiment of the present disclosure;

[0012] Figure 2 is a schematic perspective view of a downhole tool including an azimuthal survey package according to at least one embodiment of the present disclosure;

[0013] Figure 3 is a schematic perspective view of a downhole tool including an azimuthal survey package according to at least one embodiment of the present disclosure;

[0014] Figure 4 is a representation of an azimuthal survey package according to at least one embodiment of the present disclosure;

[0015] Figure 5 is a flowchart of a method for performing a downhole survey according to at least one embodiment of the present disclosure;

[0016] Figure 6 is a flowchart of a method for performing a downhole survey according to at least one embodiment of the present disclosure;

[0017] Figure 7 depicts a rig that can utilize the disclosed embodiments according to at least one embodiment of the present disclosure;

[0018] Figure 8 depicts Figure 7 the lower BHA portion of the drill string shown;

[0019] Figure 9A and Figure 9B (collectively referred to as FIG. 9) show a schematic representation of a rolling stabilizer housing deployed in a downhole tool according to at least one embodiment of the present disclosure;

[0020] Figure 10 depicts a plurality of coordinate systems and their interrelationships according to at least one embodiment of the present disclosure;

[0021] Figure 11 depicts a cross-section of an exemplary rotary steerable tool including a schematic magnetic field vector according to at least one embodiment of the present disclosure;

[0022] Figure 12A and Figure 12B (collectively referred to as FIG. 12) depict a flowchart of an exemplary method for drilling a subterranean wellbore according to at least one embodiment of the present disclosure;

[0023] Figure 13A and Figure 13B(collectively referred to as FIG. 13) depicts a flowchart of an example method for drilling a subterranean wellbore in accordance with at least one embodiment of the present disclosure;

[0024] Figure 14 depicts a cross - section of an example drill collar including a schematic magnetic field vector in accordance with at least one embodiment of the present disclosure;

[0025] Figure 15A and Figure 15B (collectively referred to as FIG. 15) depicts a flowchart of an example method for drilling a subterranean wellbore in accordance with at least one embodiment of the present disclosure; and

[0026] Figure 16 depicts a graph of sensor housing tool face, drill collar rotation rate, and wellbore azimuth over time for a synthetic example implementation of the method depicted in FIG. 15. DETAILED DESCRIPTION

[0027] The present disclosure generally relates to devices, systems, and methods for downhole surveying. A downhole drilling system can include a bottom hole assembly (“BHA”). The BHA can include a steering tool and an azimuth sensor package. The azimuth sensor package can determine the tool face azimuth. The azimuth sensor package can include one or more sensors. For example, the azimuth sensor package can include one or more of a multi - axis gyroscopic azimuth sensor, a multi - axis magnetic azimuth sensor, or an accelerometer azimuth sensor. The sensors of the azimuth sensor package can rotate about the axis of rotation of the steering tool. Including an azimuth sensor package on the BHA can enable the downhole drilling system to prepare more accurate and / or more representative azimuth measurements of the tool face. In this way, a drilling operator can adjust the trajectory of the BHA based on the azimuth measurements to more closely follow a target trajectory and / or respond more quickly to sensed downhole conditions.

[0028] Figure 1 Shows an example of a downhole drilling system 100 for drilling into a surface formation 101 to form a wellbore 102. The downhole drilling system 100 includes a rig 103 for rotating a drilling tool assembly 104 that extends downward into the wellbore 102. The drilling tool assembly 104 can include a drill string 105, a BHA 106, and a drill bit 110 attached to the lower end of the drill string 105.

[0029] The drill string 105 may include a number of joints of drill pipe 108 end - to - end connected by tool joints 109. The drill string 105 transmits drilling fluid through a central bore and transmits rotational power from the rig 103 to the BHA 106. In some embodiments, the drill string 105 may also include additional components such as subs, pup joints, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid is pumped from the surface. The drilling fluid is discharged through nozzles, ports, or other orifices of selected sizes in the drill bit 110 for cooling the drill bit 110 and the cutting structures thereon and for lifting cuttings out of the wellbore as the wellbore 102 is drilled.

[0030] The BHA 106 may include a drill bit 110 or other components. Example BHA 106 may include additional or other components (e.g., coupled between the drill string 105 and the drill bit 110). Examples of additional BHA components include drill collars, stabilizers, measurement - while - drilling (“MWD”) tools, logging - while - drilling (“LWD”) tools, downhole motors, underreamers, section mills, hydraulic breakers, jars, vibration or shock - absorbing tools, other components, or combinations of the foregoing. The BHA 106 may also include a steering tool. The steering tool may engage the wellbore wall to direct the orientation of the tool face of the drill bit. The steering tool may engage the wellbore wall in any manner. For example, the steering tool may engage the wellbore wall in a particular orientation while rotating, such as for a rotary steerable system (“RSS”). In some examples, the steering tool may engage the wellbore wall by sliding along the wellbore wall during slide steering. In some embodiments, the steering tool may engage the wellbore wall in any manner.

[0031] According to embodiments of the present disclosure, the BHA 106 may include an azimuth sensor package that includes one or more azimuth sensors. The azimuth sensor package may be used to determine the azimuth and / or inclination of a downhole tool. Azimuth may be the orientation direction of the downhole tool relative to north. In some embodiments, azimuth may be the orientation direction of the downhole tool relative to magnetic north or true north. In some embodiments, azimuth may be the orientation direction of the downhole tool relative to true north. True north may be the location on the Earth corresponding to the position where the Earth's axis of rotation extends through its outer surface. In some embodiments, true north may be aligned with the Earth's axis of rotation. Using true north as a basis for azimuth may render the azimuth unaffected by variations in the Earth's magnetic field.

[0032] According to at least one embodiment of the present disclosure, an azimuth sensor package may be located on or at the BHA 106. Including the azimuth sensor package on the BHA 106 may allow the azimuth sensor package to collect azimuth measurements closer to the bit 110. The closer the azimuth measurements are taken to the bit 110, the more representative the azimuth measurements are of the conditions at the bit 110. Thus, by placing the azimuth sensor package on the BHA 106, the azimuth sensor package may collect azimuth measurements representative of the conditions at the bit 110. In some embodiments, the sensor distance from the azimuth sensor package to the bit 110 may be within a range having an upper limit value, a lower limit value, or both an upper limit value and a lower limit value, the upper limit value and the lower limit value including any one of immediately behind the bit, 1 m, 2 m, 3 m, 4 m, 5 m, 6 m, 7 m, 8 m, 9 m, 10 m, 15 m, 20 m, or any value therebetween. For example, the sensor distance may be greater than immediately behind the bit 110. In another example, the sensor distance may be less than 20 m. In still other examples, the sensor distance may be any value within the range between immediately behind the bit and 20 m. In some embodiments, it may be critical that the sensor distance is less than 10 m to generate azimuth measurements representative of the conditions at the bit 110.

[0033] During a drilling operation, the BHA 106 may be subject to vibrations, oscillations, impacts, shocks, and other movements. These movements may cause the instruments on the BHA 106 to similarly experience vibrations, oscillations, impacts, shocks, and other movements. This may cause the instruments on the BHA 106 to become uncalibrated.

[0034] The azimuth sensor package may include one or more multi-axis magnetic azimuth sensors (as used herein, magnetic azimuth sensors). Magnetic azimuth sensors may be rugged and consistently collect direction measurements under the harsh vibration conditions of the BHA 106. However, magnetic azimuth sensors collect azimuth measurements based on the Earth's magnetic field. Magnetic azimuth sensors may experience interference from magnetic materials in the BHA 106 when collecting measurements. For example, drill pipes, subs, mud motors, electrical systems, other sensors, any other magnetic interference elements, and combinations thereof may interfere with the magnetic survey measurements. This may reduce the accuracy and / or precision of the magnetic survey.

[0035] In some cases, the magnetic azimuth sensors may collect magnetic azimuth measurements to determine the orientation of the tool face relative to magnetic north. The magnetic azimuth measurements may be based on the Earth's magnetic field. Based on the Earth's magnetic field, the magnetic azimuth measurements may result in inaccurate and / or imprecise tool face orientations determined based on the magnetic azimuth sensors in a zone of exclusion. The zone of exclusion may be a zone where magnetic azimuth measurements are routinely unreliable. The zone of exclusion may be caused by electromagnetic noise, such as electromagnetic noise from inside or outside the BHA.

[0036] In some embodiments, the exclusion zone may be the result of an orientation that is difficult to measure based on the orientation of the magnetic field. For example, the exclusion zone may include an orientation parallel or substantially parallel to magnetic north. In some embodiments, relative to magnetic north, the exclusion zone may be within a range having an upper limit value, a lower limit value, or both an upper limit value and a lower limit value, the upper limit value and the lower limit value including any one of 0.5°, 1°, 2°, 3°, 4°, 5°, 10° or any value therebetween. For example, the exclusion zone may be greater than 0.5°. In another example, the exclusion zone may be less than 10°. In yet other examples, the exclusion zone may be any value within the range between 0.5° and 10°.

[0037] In addition, many downhole tools are formed of magnetic materials, which may introduce uncertainties in measurements using magnetic sensors. Orienting with respect to true north can reduce the uncertainties caused by magnetic interference of magnetic compasses and other magnetic sensors.

[0038] The azimuth sensor package may include a multi-axis gyroscopic azimuth sensor (as used herein, gyroscopic azimuth sensor). The gyroscopic azimuth sensor may include one or more gyroscopes oriented about different axes (and / or rotating about different axes). Measurements from the gyroscopes may be used to determine the orientation of the tool face relative to true north or relative to the Earth's axis of rotation. The gyro north measurement may be accurate and precise.

[0039] In some cases, the movement of the BHA 106 may cause one or more of the gyroscopes to become uncalibrated. For example, the movement of the BHA 106 may introduce a bias into one or more of the gyroscopes of the gyroscopic azimuth sensor.

[0040] The azimuth sensor package may include an accelerometer azimuth sensor. The accelerometer azimuth sensor may include one or more accelerometers. The accelerometers may measure accelerometer azimuth measurement results. The accelerometer azimuth measurement results may include measurements based on changes in the forces applied to the BHA 106 (e.g., changes in acceleration on the BHA 106). The accelerometer azimuth measurement results may be used to determine changes in the position of the tool face. In some cases, the accelerometer azimuth measurement results may be used to determine the inclination of the tool face. In some cases, the accelerometer azimuth measurement results may be used to help correct for biases in the gyroscopic azimuth sensor.

[0041] According to at least one embodiment of the present disclosure, the BHA 106 may include an azimuth sensor package that includes one or more of a magnetic azimuth sensor, a gyroscopic azimuth sensor, or an accelerometer azimuth sensor. For example, the BHA 106 may include an azimuth sensor package that includes only a magnetic azimuth sensor. In some examples, the BHA 106 may include an azimuth sensor package that includes only a gyroscopic azimuth sensor. In some examples, the BHA 106 may include an azimuth sensor package that includes only an accelerometer azimuth sensor.

[0042] In some embodiments, the BHA 106 may include an azimuth sensor package that includes a magnetic azimuth sensor and a gyroscopic azimuth sensor. In some embodiments, the BHA 106 may include an azimuth sensor package that includes a magnetic azimuth sensor and an accelerometer azimuth sensor. In some embodiments, the BHA 106 may include an azimuth sensor package that includes a gyroscopic azimuth sensor and an accelerometer azimuth sensor. In some embodiments, the BHA 106 may include an azimuth sensor package that includes each of a magnetic azimuth sensor, a gyroscopic azimuth sensor, and an accelerometer azimuth sensor.

[0043] Including multiple azimuth sensors in the azimuth sensor package on the BHA 106 may help generate more accurate and / or more representative azimuth measurements of the actual conditions at the tool face or the drill bit 110. For example, multiple azimuth sensors on the BHA 106 may allow for comparison between azimuth measurements. In this way, the generated azimuth of the tool face may be based on multiple measurements, thereby improving its accuracy and / or representation of the conditions at the tool face.

[0044] In some embodiments, multiple azimuth sensors on the BHA 106 may be used to provide correction and / or calibration for each other. For example, magnetic sensor measurements may be used to correct biases introduced into the gyroscopes of the gyroscopic azimuth sensors, such as biases introduced during vibration of the BHA 106 during operation. In this way, the magnetic azimuth sensor may be used to maintain the operating state of the gyroscopic azimuth sensor. This may allow the gyroscopic azimuth sensor to collect gyroscopic azimuth measurements to generate the azimuth of the tool face relative to true north.

[0045] In some embodiments, the gyroscopic azimuth sensor may be used to calibrate the magnetic azimuth sensor. As discussed herein, the magnetic azimuth sensor may be subject to magnetic interference based on magnetic materials and / or electromagnetic fields on the BHA 106 and / or other parts of the downhole drilling system. Additionally, magnetic north may be offset from true north by 10° or more based on the location on the earth and / or variations in the earth's magnetic field. The azimuth determined using magnetic azimuth measurements may be corrected based on the offset and / or magnetic interference. This correction may be used to correct the magnetic azimuth to true north. In some cases, a table based on known magnetic interference and / or known location of the tool face may be used to apply the correction.

[0046] According to at least one embodiment of the present disclosure, gyroscopic azimuth measurement results can be used to determine the correction from magnetic azimuth to true north azimuth. For example, a magnetic azimuth sensor can collect magnetic azimuth measurement results, and a gyroscopic azimuth sensor can collect gyroscopic azimuth measurement results. The gyroscopic azimuth measurement results can be used to determine the true north azimuth, and the magnetic azimuth measurement results can be used to determine the magnetic azimuth. The difference between the true north azimuth and the magnetic azimuth may be the correction. This correction can then be applied to subsequent magnetic azimuths determined using the magnetic azimuth measurement results. In this way, the magnetic azimuth generated by the magnetic azimuth sensor can be more accurate and / or more representative of the true north azimuth of the tool face.

[0047] The azimuth sensor package can be used with any type of downhole drilling system 100. For example, the azimuth sensor package can be used with the top drive downhole drilling system 100 shown. In some examples, the azimuth sensor package can be used with other drilling systems, such as a cable drilling system or any other drilling system.

[0048] In some embodiments, the azimuth sensor package can be located on the RSS. For example, the azimuth sensor package can be located on the rolling stabilization platform of the RSS. The rolling stabilization platform can include an inner housing that can rotate independently of the outer housing, where the outer housing can be rotated by the top drive. In the rolling stabilization platform, the inner housing can be independently rotatable such that the inner housing can have any rotational rate relative to an absolute reference frame (such as gravity). In some embodiments, when the outer housing rotates relative to the absolute reference frame, the inner housing may not rotate relative to the absolute reference frame. In some embodiments, the inner housing can rotate at any rotational rate relative to the outer housing and / or the absolute reference frame.

[0049] In some embodiments, the azimuth sensor package can be located on the inner housing of the rolling stabilization platform. In other words, the gyroscopic azimuth sensor, the magnetic azimuth sensor, the accelerometer azimuth sensor, and combinations thereof can be located on the inner housing of the rolling stabilization platform. In some embodiments, the azimuth sensor package can collect measurement results on the rolling stabilization platform when the inner housing rotates independently of the outer housing. For example, the gyroscopic sensor tool can collect gyroscopic azimuth measurement results when the inner housing rotates independently of the outer housing. In some examples, the gyroscopic sensor tool can collect gyroscopic azimuth measurement results when the inner housing does not rotate and the outer housing rotates. In some examples, the gyroscopic sensor tool can collect gyroscopic azimuth measurement results when the inner housing rotates at a different rotational rate than the outer housing.

[0050] In some embodiments, a magnetic azimuth sensor may collect magnetic azimuth measurements while the inner housing rotates independently of the outer housing. In some examples, a magnetic sensor tool may collect magnetic azimuth measurements while the inner housing does not rotate and the outer housing rotates. In some examples, a magnetic sensor tool may collect magnetic azimuth measurements while the inner housing rotates at a different rotational rate than the outer housing.

[0051] In some embodiments, an accelerometer azimuth sensor may collect accelerometer azimuth measurements while the inner housing rotates independently of the outer housing. In some examples, an accelerometer sensor tool may collect accelerometer azimuth measurements while the inner housing does not rotate and the outer housing rotates. In some examples, an accelerometer sensor tool may collect accelerometer azimuth measurements while the inner housing rotates at a different rotational rate than the outer housing.

[0052] In some embodiments, an azimuth sensor package may collect two or more of gyroscopic azimuth measurements, magnetic azimuth measurements, or accelerometer azimuth measurements while the inner housing rotates at a different rotational rate than the outer housing. For example, an azimuth sensor package may collect gyroscopic azimuth measurements and magnetic azimuth measurements while the inner housing rotates at a different rotational rate than the outer housing. In some examples, an azimuth sensor package may collect gyroscopic azimuth measurements and accelerometer azimuth measurements while the inner housing rotates at a different rotational rate than the outer housing. In some examples, an azimuth sensor package may collect magnetic azimuth measurements and accelerometer azimuth measurements while the inner housing rotates at a different rotational rate than the outer housing. In some examples, an azimuth sensor package may collect each of gyroscopic azimuth measurements, magnetic azimuth measurements, and accelerometer azimuth measurements while the inner housing rotates at a different rotational rate than the outer housing.

[0053] According to at least one embodiment of the present disclosure, collecting azimuth measurements while the inner housing rotates at a different rotational rate than the outer housing may help improve the accuracy and / or precision of the generated azimuth. For example, this may allow an azimuth sensor package to collect azimuth measurements during a drilling operation. In some examples, this may allow an azimuth sensor package to collect azimuth measurements while the inner housing rotates slowly. Collecting measurements while the inner housing rotates may help the sensors of the azimuth sensor package account for biases and / or misalignments in their measurements, thereby improving the azimuth generated using the azimuth measurements.

[0054] In some embodiments, the azimuth sensor package may be rotatably fixed to the BHA 106 and / or the drill bit 110. For example, the steering system for steering the drill bit 110 may be a bent housing steering system, a sliding steering system, or other fixed housing steering systems. The azimuth sensor package may be rotatably fixed to the fixed housing steering system. In some embodiments, the azimuth sensor package may collect azimuth measurements while the fixed housing steering system rotates during the drilling operation. In some embodiments, the azimuth sensor package may collect azimuth measurements when the fixed housing steering system is not rotating. For example, the azimuth sensor package may collect azimuth measurements during riser or drill pipe changes.

[0055] In some embodiments, the downhole drilling system 100 may include an inertial position manager that may determine the tool face and / or the inertial position of the drill bit 110. The inertial position manager may use azimuth measurements to generate the inertial position of the tool face. For example, combined gyroscope azimuth measurements, magnetic azimuth measurements, and accelerometer azimuth measurements may be used to generate the inertial position of the tool face. The inertial position may be a dead reckoning position or a position determined based on the orientation of the tool face in combination with the change in the position of the tool face. The inertial position may enable the downhole drilling system 100 to more accurately know the three-dimensional position of the tool face. This may help the downhole drilling system 100 to guide the tool face to maintain the trajectory, avoid certain geological features (such as formations or offset wellbores), and engage other geological features.

[0056] Generally, the downhole drilling system 100 may include other drilling components and accessories, such as special valves (e.g., kelly cocks, blowout preventers, and safety valves). The additional components included in the downhole drilling system 100 may be considered part of the drilling tool assembly 104, the drill string 105, or the BHA 106, depending on their position in the downhole drilling system 100.

[0057] The drill bit 110 in the BHA 106 may be any type of drill bit suitable for breaking downhole materials. For example, the drill bit 110 may be a drill bit suitable for drilling the surface formation 101. Example types of drill bits for drilling the surface formation are fixed cutter or drag bits. In other embodiments, the drill bit 110 may be a mill shoe for removing metal, composite materials, elastomers, other downhole materials, or combinations thereof. For example, the drill bit 110 may be used with a whipstock to mill into the casing 107 that is sleeved on the wellbore 102. The drill bit 110 may also be a flat mill shoe for milling away tools, plugs, cement, other materials, or combinations thereof within the wellbore 102. The chips or other drill cuttings formed by using the mill shoe may be lifted to the surface or may be allowed to fall downhole.

[0058] Figure 2Is a representation of a steerable drilling system 212 including an azimuth survey package 214 according to at least one embodiment of the present disclosure. The steerable drilling system 212 includes an outer housing 216. The outer housing 216 is rotatably connected to a drill bit (e.g., Figure 1 drill bit 110) and / or a drill string (e.g., Figure 1 drill string 105). In other words, the outer housing 216 can rotate at the same rotational rate as the drill bit and / or the drill string. In some cases, the outer housing 216 can rotate about the tool rotation axis 217 at a high rotational rate such as 50 RPM, 100 RPM, 200 RPM, 500 RPM, 1,000 RPM, 2,000 RPM or higher. In some embodiments, the azimuth survey package 214 is coupled to the drill bit or drill string by being part of or coupled to a directional drilling tool 229, such as a rotary steerable tool having a movable pad 231 that bears against the borehole as part of a push-the-bit drilling system. In other embodiments, the directional drilling tool 229 can include a motor with a bent housing, a point-the-bit configuration, other directional drilling tools, or a combination of the foregoing.

[0059] The azimuth survey package 214 can be located inside the outer housing 216. In some embodiments, the azimuth survey package 214 can be located on an independently rotatable member 215 (e.g., an inner housing). In some embodiments, the independently rotatable member 215 can be coaxial with the outer housing 216 and can rotate about the tool rotation axis 217. The independently rotatable member 215 (and thus the azimuth survey package 214) can be rotationally stable relative to the outer housing 216. In other words, the azimuth survey package 214 can rotate independently relative to the outer housing 216. The independently rotatable member 215 can be connected to the outer housing 216 by one or more stabilizers 218, which can include one or more bearings for varying the rotational rate relative to the outer housing 216.

[0060] In some embodiments, a counter-torque can be applied to the independently rotatable member 215 such that it rotates at a different rate than the outer housing 216. In some embodiments, the azimuth survey package 214 can rotate at a lower rate than the outer housing 216. In some embodiments, the azimuth survey package 214 can remain stationary relative to an external reference such as gravity.

[0061] The azimuth survey package 214 may include one or more survey instruments. For example, the illustrated azimuth survey package 214 includes a multi-axis gyroscopic azimuth sensor 220, a multi-axis magnetic azimuth sensor 221, and a multi-axis accelerometer azimuth sensor 223. As can be seen, each sensor of the azimuth survey package 214 may be located on the independently rotatable member 215. The multi-axis gyroscopic azimuth sensor 220, the multi-axis magnetic azimuth sensor 221, and the multi-axis accelerometer azimuth sensor 223 may collect measurements along and / or relative to multiple axes. In the illustrated embodiment, the x-axis 222 may be parallel to the tool rotation axis 217, the z-axis 226 may be perpendicular to the x-axis 222 in the direction of gravity, and the y-axis 224 may be perpendicular to both the x-axis 222 and the z-axis 226.

[0062] The multi-axis gyroscopic azimuth sensor 220 may include one or more gyroscopes, such as multi-axis gyroscopes. The multi-axis gyroscopes may collect gyroscopic measurements along one or more axes. In some embodiments, the multi-axis gyroscopes may collect x-axis 222 gyroscopic measurements, y-axis 224 gyroscopic measurements, and z-axis 226 gyroscopic measurements. In some embodiments, the multi-axis accelerometer azimuth sensor 223 may collect x-axis 222 accelerometer measurements, y-axis 224 accelerometer measurements, and z-axis 226 accelerometer measurements. In some embodiments, the multi-axis magnetic azimuth sensor 221 may collect magnetic measurements along one or more axes. For example, the multi-axis magnetic azimuth sensor 221 may collect x-axis 222 magnetic measurements, y-axis 224 magnetic measurements, and z-axis 226 magnetic measurements. In this way, the gyroscopic azimuth measurements, the accelerometer azimuth measurements, and the magnetic azimuth measurements may be made close to each other, thereby improving the correlation between two measurements.

[0063] In some embodiments, the azimuth survey package 214 may further include an indexing gyroscope 228. The indexing gyroscope 228 may be oriented along the tool rotation axis 217. The indexing gyroscope 228 may collect measurements in a first direction and a second direction along the indexing axis. Flipping the indexing gyroscope 228 along the indexing axis may help compensate for and / or remove any bias in the gyroscopic measurements due to misalignment of the indexing gyroscope 228. In some embodiments, any gyroscope on the azimuth survey package 214 may be indexed to compensate for and / or remove any bias in the gyroscope. For example, the multi-axis gyroscopic azimuth sensor 220 may include one, two, three, four, five, six, or more gyroscopes, each of which may be flipped to compensate for and / or remove any bias that may occur.

[0064] The steerable drilling system 212 has a tool face angle 232, which can be the angle between the z-axis 226 and a vertical axis 233 perpendicular to the tool rotation axis 217. As further discussed herein, the tool face angle 232 can be a reference angle for determining the tool orientation of the steerable drilling system 212. The steerable drilling system 212 can also have an inclination angle 234, which can be defined by the angle between the vertical axis 233 and the tool rotation axis 217. The inclination angle 234 can assist in determining the tool orientation of the steerable drilling system 212. Accelerometer orientation measurements can be used to determine the inclination angle 234. In some embodiments, accelerometer orientation measurements, gyroscope orientation measurements, and magnetic orientation measurements can be used to determine the inclination angle 234.

[0065] As discussed herein, the orientation survey package 214 can be used to generate orientation measurements. The orientation measurements can be used to generate the tool face angle 232 and / or the inclination angle 234 of the steerable drilling system 212. In some embodiments, collecting the orientation measurements on the independently rotatable member 215 can help improve the generated tool face angle 232.

[0066] In some embodiments, the orientation survey package 214 can include a downhole processor. The orientation survey package 214 can be used to receive orientation measurements from the multi-axis gyroscope orientation sensor 220, the multi-axis magnetic orientation sensor 221, and the multi-axis accelerometer orientation sensor 223. In some embodiments, using the orientation measurements, the orientation survey package 214 can generate the tool face angle 232 downhole.

[0067] In some embodiments, the BHA can receive information from the orientation survey package 214. In some embodiments, the BHA transmits the orientation measurements to the surface uphole. In some embodiments, the BHA can transmit the raw orientation measurements. In some embodiments, the BHA can transmit the tool face angle 232 to the surface uphole. This can help reduce the amount of information transmitted uphole, thus saving limited transmission bandwidth.

[0068] In some embodiments, the BHA may utilize the tool face angle 232 to prepare a correction to the trajectory of the steerable drilling system 212. For example, the BHA may compare the tool face angle 232 to a target tool face angle. If the tool face angle 232 is different from the target tool face angle, the BHA may prepare a correction to the trajectory of the steerable drilling system 212. For example, the BHA may send a signal to the steering tool to adjust the trajectory of the steerable drilling system 212, including azimuth and / or inclination. In this manner, the azimuth survey package 214 may establish a feedback loop with the steerable drilling system 212. The BHA may instruct the steering tool to adjust the azimuth of the steerable drilling system 212. After drilling for a period of time or a certain distance, the azimuth survey package 214 may collect another set of azimuth measurements and generate another tool face angle 232. The new tool face angle 232 may be compared to the target azimuth, and the BHA may prepare a correction to the steering tool as appropriate. In this manner, the steerable drilling system 212 may be autonomous or semi-autonomous. This may help the steerable drilling system 212 stay on the target trajectory and / or reduce the amount of information transmitted to the surface from downhole.

[0069] In some embodiments, as discussed herein, the azimuth survey package 214 may generate azimuth measurements that may be used to prepare the inertial position of the steerable drilling system 212. For example, the azimuth survey package 214 may use the tool face angle 232 and accelerometer measurements to determine how far the steerable drilling system 212 has traveled. In some embodiments, the BHA may transmit inertial positioning information to the surface, and the inertial position may be determined or generated at the surface. In some embodiments, the azimuth survey package 214 may prepare or generate the inertial position downhole at the azimuth survey package 214. The BHA may use the inertial position in autonomous or semi-autonomous drilling. For example, the BHA may use the inertial position to determine the position of the steerable drilling system 212 relative to downhole features such as geological features, offset wellbores, etc. Using the inertial position of the steerable drilling system 212 relative to downhole features, the BHA may prepare a correction to the steering tool to avoid or head towards downhole features.

[0070] Figure 3 is a representation of a steerable drilling system 312 including an azimuth survey package 314 in accordance with at least one embodiment of the present disclosure. The steerable drilling system 312x includes a housing 336. The housing 336 may be rotatably connected to a drill bit (e.g., Figure 1 drill bit 110) and / or a drill string (e.g., Figure 1 drill string 105). In other words, the housing 336 may rotate at the same rotational rate as the drill bit and / or the drill string. In some cases, the housing 336 may rotate about the tool rotation axis 317 at a high rotational rate such as 50 RPM, 100 RPM, 200 RPM, 500 RPM, 1,000 RPM, 2,000 RPM, or higher.

[0071] The azimuth survey package 314 can be rotatably fixed to the housing 336 and can include one or more survey instruments. For example, the illustrated azimuth survey package 314 includes a multi-axis gyroscopic azimuth sensor 320, a multi-axis magnetic azimuth sensor 321, and a multi-axis accelerometer azimuth sensor 323. As can be seen, each sensor of the azimuth survey package 314 can be located on the housing 336. The multi-axis gyroscopic azimuth sensor 320, the multi-axis magnetic azimuth sensor 321, and the multi-axis accelerometer azimuth sensor 323 can collect measurements along or relative to multiple axes. In the illustrated embodiment, the x-axis 322 can be parallel to the tool rotation axis 317, the z-axis 326 can be perpendicular to the x-axis 322 in the direction of gravity, and the y-axis 324 can be perpendicular to the x-axis 322 and the z-axis 326.

[0072] As discussed herein, the multi-axis gyroscopic azimuth sensor 320 can collect gyroscopic azimuth measurements along the x-axis 322, the z-axis 326, and the y-axis 324. The multi-axis magnetic azimuth sensor 321 can collect magnetic azimuth measurements along the x-axis 322, the z-axis 326, and the y-axis 324. The multi-axis accelerometer azimuth sensor 323 can collect accelerometer azimuth measurements along the x-axis 322, the z-axis 326, and the y-axis 324.

[0073] The azimuth measurements can be used to determine the tool face trajectory, including the tool face azimuth, the tool face angle 332, and / or the inclination angle 334 measured relative to the vertical axis 333. By collecting azimuth measurements along multiple axes on the housing 336, the azimuth survey package 314 can generate a tool face angle 332 that is more accurate and / or more representative of the actual tool face angle 332 of the steerable drilling system 212.

[0074] As discussed herein, the azimuth measurements, the tool face angle 332, the inclination angle 334, and combinations thereof can be transmitted to the surface downhole. At the surface, the drilling operator can use the azimuth measurements and / or the tool face angle 332 to prepare adjustments and / or corrections to the steering tool. In some embodiments, the azimuth survey package 314 can prepare or generate the tool face angle 332 downhole. Using the tool face angle 332, the BHA can prepare corrections to the steering during autonomous or semi-autonomous drilling operations to adjust the trajectory of the steerable drilling system 312.

[0075] As discussed herein, the azimuth measurements, the tool face angle 332, the inclination angle 334, and combinations thereof can be used to generate the inertial position of the steerable drilling system 312. In some embodiments, the BHA can use the inertial position of the steerable drilling system 312 alone or in combination with the tool face angle 332 during autonomous or semi-autonomous drilling operations to prepare corrections to the trajectory of the steerable drilling system 312. This can help improve the steering of the steerable drilling system 312.

[0076] Figure 4 is a representation of the azimuth survey package 414 according to at least one embodiment of the present disclosure. Each component of the azimuth survey package 414 may include software, hardware, or both. For example, the component may include one or more instructions stored on a computer-readable storage medium and executable by a processor of one or more computing devices. In some embodiments, the computing device may be located downhole, such as on a BHA (e.g., Figure 1 of the BHA 106). In some embodiments, the computing device may be located on the surface, such as a client device or a server device. When executed by one or more processors, the computer-executable instructions of the azimuth survey package 414 may cause the computing device to perform the methods described herein. Alternatively, the component may include hardware, such as a dedicated processing device for performing a certain function or group of functions. Alternatively, the components of the azimuth survey package 414 may include a combination of computer-executable instructions and hardware.

[0077] In addition, the components of the azimuth survey package 414 may be implemented, for example, downhole as one or more operating systems, one or more stand-alone applications, one or more modules of an application, one or more plug-in programs, one or more library functions, or functions callable by other applications. In some examples, the components of the azimuth survey package 414 may be implemented at a surface location, including as a cloud computing model.

[0078] The azimuth survey package 414 may include a survey sensor 438. The survey sensor 438 may include a multi-axis gyroscope azimuth sensor 420, a multi-axis magnetic azimuth sensor 421, and a multi-axis accelerometer azimuth sensor 423.

[0079] The azimuth manager 440 may collect azimuth measurement results from the survey sensor 438. For example, the azimuth manager 440 may collect gyroscope azimuth measurement results from the multi-axis gyroscope azimuth sensor 420, magnetic azimuth measurement results from the multi-axis magnetic azimuth sensor 421, and accelerometer azimuth measurement results from the multi-axis accelerometer azimuth sensor 423.

[0080] The orientation manager 440 may periodically and / or occasionally collect orientation measurements. For example, the orientation manager 440 may collect orientation measurements at periodic times, such as every second, every minute, every five minutes, every 30 minutes, every hour, etc. In some examples, the orientation manager 440 may collect orientation measurements at periodic distances. For example, the orientation manager 440 may collect orientation measurements every 1m, every 5m, every 10m, every 15m, every 20m, every 25m, every 30m, every 35m, every 40m, every 45m, every 50m, etc. In some examples, the orientation manager 440 may collect orientation measurements when the orientation survey package 414 receives an instruction. For example, the orientation manager 440 may collect orientation measurements when the orientation survey package 414 receives an instruction from a surface location, a BHA, an MWD tool, an LWD tool, any other location, and combinations thereof.

[0081] The orientation survey package 414 includes a tool face angle generator 444. Using the orientation measurements from the survey sensor 438 and received by the orientation manager 440, the tool face angle generator 444 may generate the orientation and / or tool face angle of the downhole tool. As discussed herein, the tool face angle generator 444 may be located at a surface location. The tool face angle generator 444 may receive the orientation measurements from the orientation manager 440 at the surface and generate the orientation of the tool face at the surface. In some embodiments, the tool face angle generator 444 may be located downhole. For example, the tool face angle generator 444 may be located on the orientation survey package 414, at the BHA, at the MWD, at the LWD, at any other downhole location, and combinations thereof.

[0082] The orientation survey package 414 may include an autonomous drilling manager 446. The autonomous drilling manager 446 may utilize the tool face orientation generated by the tool face angle generator 444 to prepare an adjustment to the trajectory of the downhole tool. For example, the autonomous drilling manager 446 may prepare a correction to a steering tool to adjust the trajectory of the downhole tool.

[0083] In some embodiments, the autonomous drilling manager 446 may not receive input from a drilling operator. The autonomous drilling manager 446 may include a model that, when applied to the tool face orientation, may determine whether the measured tool face orientation is different from a target orientation based on the target trajectory of the wellbore. In some embodiments, the autonomous drilling manager 446 may compare the measured tool face orientation to the target trajectory in real time. The real-time trajectory comparison may enable the autonomous drilling manager 446 to respond more quickly to changing drilling conditions. In this manner, the autonomous drilling manager 446 may help the wellbore maintain its position along the target wellbore trajectory.

[0084] In some embodiments, the autonomous drilling manager 446 may receive input from a drilling operator. For example, the autonomous drilling manager 446 may transmit a proposed change to the trajectory of a downhole tool. Upon receiving operator approval, the autonomous drilling manager 446 may implement the trajectory. In this manner, the autonomous drilling manager 446 can be a semi-autonomous drilling manager.

[0085] The azimuth survey package 414 may also include an inertial position manager 448. The inertial position manager 448 may use the azimuth measurements from the azimuth manager 440 to prepare the inertial position of the downhole tool. As discussed herein, the inertial position manager 448 may use the toolface azimuth and inertial information to determine the inertial position of the downhole tool. In some embodiments, the autonomous drilling manager 446 may use the inertial position of the downhole tool to make drilling decisions. For example, the autonomous drilling manager 446 may prepare a trajectory correction based on the inertial position and how close or far the downhole tool is from a downhole feature.

[0086] According to at least one embodiment of the present disclosure, the azimuth survey package 414 may include a calibration manager 450. The calibration manager 450 may use the azimuth measurements received from the azimuth manager 440 to calibrate the survey sensor 438. For example, the calibration manager 450 may use the gyro azimuth measurement to calibrate the multi-axis magnetic azimuth sensor 421. The toolface azimuth generated by the toolface angle generator 444 using the gyro azimuth measurement may be used to prepare a correction to the magnetic azimuth generated using the magnetic azimuth measurement. In this manner, the calibration manager 450 may assist in calibrating the multi-axis magnetic azimuth sensor 421, thereby improving the accuracy and / or representativeness of the magnetic azimuth generated by the toolface angle generator 444 using the magnetic azimuth measurement.

[0087] In some examples, the calibration manager 450 may use the magnetic azimuth measurement to calibrate the multi-axis gyro azimuth sensor 420 and / or remove its bias. For example, the calibration manager 450 may use the magnetic azimuth generated by the toolface angle generator 444 to correct the bias drift of the multi-axis gyro azimuth sensor 420. This may help improve the accuracy and / or representativeness of the gyro azimuth generated by the toolface angle generator 444 using the gyro azimuth measurement. In some embodiments, the calibration manager 450 may use the azimuth measurements to periodically calibrate the survey sensor 438. This may help improve the accuracy and / or representativeness of the toolface azimuth generated by the toolface angle generator 444.

[0088] Figures 5 to 6 The corresponding text and examples provide various different methods, systems, devices, and computer-readable media for downhole survey systems. In addition to the foregoing, one or more embodiments may also be described according to a flowchart including actions for achieving a specific result, such as Figures 5 to 6as shown Figures 5 to 6 It can be performed with more or fewer actions. Additionally, the actions can be performed in a different order. Additionally, the actions described herein can be performed repeatedly or in parallel with each other, or in parallel with different instances of the same or similar actions.

[0089] As mentioned, Figure 5 is a flowchart of a method 552 of a series of actions performed on a downhole assembly according to at least one embodiment of the present disclosure. Although Figure 5 shows actions according to one embodiment, alternative embodiments can omit, add, reorder, and / or modify Figure 5 any of the actions shown. Figure 5 The actions of can be performed as part of a method. Alternatively, a computer-readable medium can include instructions that, when executed by one or more processors, cause a computing device to perform Figure 5 the actions of. In some embodiments, the system can perform Figure 5 the actions of.

[0090] Method 552 can include orienting the tool face in a downhole drilling system at 554. The orienting tool can engage the wellbore wall. The orienting tool can be any type of orienting tool. For example, the orienting tool can be an RSS, a bent housing tool, a sliding orienting tool, or any other orienting tool. In some examples, the orienting tool can be a push-bit type orienting tool, a point-bit type orienting tool, a hybrid push / point-bit type orienting tool, and combinations thereof. In some embodiments, the downhole drilling system can include a drill bit drilling tool that engages and breaks the formation. In some embodiments, the downhole drilling system can include a plasma drilling tool and / or a jet drilling tool. At 556, the downhole survey system can collect azimuth measurements at the orienting tool. An azimuth sensor package can be used to collect the azimuth measurements. The azimuth measurements can include at least one of gyroscopic azimuth measurements, magnetic azimuth measurements, or accelerometer measurements. Using the azimuth measurements, at 558, the downhole survey system can generate the azimuth of the tool face. In some embodiments, the azimuth of the tool face can be generated in an exclusion zone or generally parallel to magnetic north.

[0091] In some embodiments, collecting the azimuth measurements can include collecting any combination of two azimuth measurements, including gyroscopic azimuth measurements and magnetic azimuth measurements, gyroscopic azimuth measurements and accelerometer azimuth measurements, and magnetic azimuth measurements and accelerometer azimuth measurements. In some embodiments, collecting the azimuth measurements can include collecting each of the azimuth measurements.

[0092] In some embodiments, the method may include adjusting the orientation of the tool face based on the orientation of the steering tool. For example, as discussed herein, a downhole survey system may include an autonomous drilling manager. The autonomous drilling manager may make drilling decisions based on the tool face orientation and / or inertial position of downhole tools.

[0093] In some embodiments, the method may include collecting orientation measurements while rotating the steering tool. In some embodiments, the method may include independently rotating an orientation survey package while rotating the steering tool. In some embodiments, the orientation survey package may be held in a rolling stable position while collecting orientation measurements.

[0094] In some embodiments, a downhole survey system may include using orientation measurements to generate an inertial position of the tool face. The inertial position may be used during autonomous drilling to correct the trajectory of downhole tools based on the position of downhole features.

[0095] As mentioned, Figure 6 is a flowchart of method 660 of a series of actions performed on a bottomhole assembly according to at least one embodiment of the present disclosure. Although Figure 6 shows actions according to one embodiment, alternative embodiments may omit, add, reorder, and / or modify Figure 6 any of the actions shown. Figure 6 The actions of may be performed as part of the method. Alternatively, a computer-readable medium may include instructions that, when executed by one or more processors, cause a computing device to perform Figure 6 the actions of. In some embodiments, the system may perform Figure 6 the actions of.

[0096] Method 660 may include orienting the tool face in a downhole drilling system at 662. The steering tool may engage the wellbore wall. The steering tool can be any type of steering tool. For example, the steering tool can be an RSS, a bent housing tool, a sliding steering tool, or any other steering tool. At 664, the downhole survey system may collect orientation measurements at the steering tool. An orientation sensor package may be used to collect the orientation measurements. The orientation measurements may include at least one of gyroscopic orientation measurements, magnetic orientation measurements, or accelerometer measurements.

[0097] Using the orientation measurements, at 666, the downhole survey system may calibrate the trajectory sensor package. For example, the downhole survey system may use the gyroscopic orientation generated using gyroscopic orientation measurements to prepare for correcting the magnetic orientation generated using magnetic orientation measurements. In some examples, the downhole survey system may use the magnetic orientation generated using magnetic orientation measurements to correct the bias introduced into the gyroscopic orientation sensor.

[0098] In accordance with some aspects of the present disclosure, a solid-state or mechanical gyroscope package is placed within a steerable drilling tool, such as an RSS. In the case where the drilling tool is an RSS, for the purpose of performing an azimuth survey, the tool can be strap-down (rotating with the bit / casing) or rolling stabilized (ground stationary, where the rotation is independent of the bit / casing). For the purpose of performing an azimuth survey, a solid-state or mechanical gyroscope can be placed within an MWD or LWD tool. For the purpose of performing an azimuth survey, a solid-state or mechanical gyroscope can be placed within an auxiliary drilling device in the BHA or drill string such that it is capable of communicating (communicating to and / or from) at least one steerable drilling tool, such as an RSS or MWD. In some embodiments, the solid-state gyroscope can operate with three or fewer axes. In some embodiments, the solid-state gyroscope can flip about any of its axes to provide bias correction. In at least some embodiments, the gyroscope package includes one, two, three, or more accelerometers. In at least some embodiments, the gyroscope package is connected to a battery or other power source having sufficient power to operate the gyroscope package. In at least some embodiments, the gyroscope package is connected to one or more processors capable of performing azimuth orientation calculations. Optionally, data (e.g., survey data) can also be used in a fusion model in combination with a fluxgate or other type of magnetometer and / or accelerometer (e.g., MCM) to improve survey accuracy. In some embodiments, the generated data (e.g., survey data) can be transmitted to a surface location via mud pulse, direct connection, electromagnetic methods (e.g., EM pulse, short-hop), or wired drill pipe and / or transmitted between tools in the BHA. In some embodiments, the collected data (e.g., survey data) is used as part of a closed-loop automation process for controlling the drilling trajectory. In some embodiments, gyroscopic surveys are used to perform bias compensation on one or more magnetometers during dynamic drilling surveys (e.g., while drilling and / or rotating).

[0099] Methods for drilling a subterranean wellbore are disclosed. Example methods include rotating a BHA in a subterranean wellbore to drill the well, where the BHA includes drill collars, a drill bit, a rolling stabilizer housing deployed within the drill collars and configured to rotate relative to the drill collars, and a triaxial accelerometer package and a triaxial magnetometer package deployed within the rolling stabilizer housing. Triaxial accelerometer and triaxial magnetometer measurements and drill collar rotation rate measurements are made while the BHA is rotating. A wellbore inclination and a gravity tool face of the rolling stabilizer housing are calculated based on the triaxial accelerometer measurements. The calculated inclination, the calculated gravity tool face, the triaxial magnetometer measurements, and the measured rotation rate of the drill collars are processed to calculate the azimuth of the subterranean wellbore, where the effects of eddy currents and magnetometer bias are considered in the calculated azimuth. In certain example embodiments, a Kalman filter is used to process the calculated gravity tool face, the triaxial magnetometer measurements, and the measured rotation rate of the drill collars. In other example embodiments, the measured rotation rate of the drill collars is processed to calculate an eddy current compensation term. In still other example embodiments, multi-station analysis is used to process the triaxial magnetometer measurements to calculate the magnetometer bias.

[0100] The embodiments disclosed herein may provide various technical advantages and improvements over the prior art. For example, improved methods and systems for drilling a subterranean wellbore include making dynamic survey measurements, such as wellbore inclination and wellbore azimuth measurements (e.g., several measurements per minute or several measurements per foot of wellbore depth drilled), substantially in real time while drilling the well. Additionally, the disclosed embodiments may advantageously compensate (account for) eddy currents and / or the effects of eddy currents in the drill collars and / or the rolling stabilizer housing and magnetometer bias in the magnetometer measurements, and thus may provide improved accuracy (particularly dynamic azimuth measurements with improved accuracy). The disclosed embodiments may also calculate updated eddy current compensation terms and magnetometer bias while drilling the well, and thus may advantageously account for changes in the effects of eddy currents and magnetometer bias effects during the drilling operation.

[0101] It should be understood that the disclosed embodiments may also provide a higher density of survey measurements along the wellbore profile than may be obtained via conventional static survey methods, enabling a more accurate wellbore path to be determined. Improving the timeliness and density of wellbore surveys may further advantageously improve the speed and effectiveness of wellbore steering activities, such as wellbore path corrections and anti-collision decisions.

[0102] Figure 7A drilling rig 710 suitable for implementing various method embodiments disclosed herein is depicted. A semi-submersible drilling platform 712 is positioned above an oil or gas formation disposed below a seabed 716. A subsea conduit 718 extends from a deck 720 of the platform 712 to a wellhead 722. The platform may include a derrick and a hoisting device for raising and lowering a drill string 730, which extends into a wellbore 740 and includes a drill bit 732 and a rotary steerable tool 760, as shown. The drill string 730 may also include a downhole drilling motor, a downhole telemetry system, and one or more measurement while drilling (MWD) or logging while drilling (LWD) tools 750, which include various sensors for sensing downhole characteristics of the wellbore and surrounding formations. The disclosed embodiments are not limited in these respects.

[0103] Those of ordinary skill in the art will understand that Figure 7 The deployment shown is only an example. It will be further understood that the disclosed embodiments are not limited to the Figure 7 The disclosed embodiments are also well suited for use with any kind of submersible drilling operation, whether offshore or onshore.

[0104] Figure 8 Drill string 730 ( Figure 7 ), which includes a drill bit 732 and a rotary steerable tool 760. The rotary steerable tool may include substantially any suitable rotary steerable tool, including a roll stable controller (or control unit) deployed in a roll stable housing or otherwise substantially non-rotating or geostationary housing. Roll stable means that the sensor housing does not substantially rotate relative to the wellbore (or may sometimes rotate slowly compared to the drill string).

[0105] Although Figure 8 A rotationally steerable tool 860 is depicted, but it should be understood that the disclosed embodiments are not limited to use with a rotationally steerable tool. In addition, while navigation sensors 865 and 867 (e.g., accelerometers and magnetometers) may be deployed and corresponding sensor measurements (e.g., such as Figure 8 ), but they may also be located in a roll-stable housing positioned substantially anywhere in the drill string. Figure 2 As discussed, the rotationally steerable tool 860 may also include one or more gyroscopes or gyroscopic sensors 866. For example, again referring to Figure 7, the drill string 730 may include a measurement-while-drilling tool 750, which includes corresponding sensors deployed in a rolling-stabilized housing. As is known to those of ordinary skill in the art, such an MWD tool 750 may also include a mud pulse telemetry transmitter or other telemetry system, an alternator for generating electricity, and an electronic controller. Therefore, it should be understood that the disclosed embodiments are not limited to any particular deployment location of the navigation sensors in the drill string.

[0106] The illustrated example rotary steerable tool 760 and / or MWD tool 750 includes a triaxial accelerometer and a triaxial magnetometer navigation sensor set. These navigation sensors may include substantially any suitable available devices. Suitable accelerometers for use in the sensor set may include, for example, conventional Q-flex type accelerometers or microelectromechanical system (MEMS) solid-state accelerometers. Suitable magnetic field sensors for use in the sensor set may include, for example, conventional toroidal core fluxgate magnetometers or magnetoresistive sensors. The navigation sensors may also optionally include gyroscopic sensors, such as rate gyros or MEMS type gyros.

[0107] Continuing to refer Figure 7 and Figure 8 , the rotary steerable tool and / or MWD tool may also include a rotational rate sensor 869 that is configured to measure the rotational rate difference between the rolling-stabilized housing and the drill collar 862 (which is equal to the rotational rate of the drill collar when the rolling-stabilized housing is stationary relative to the earth). Substantially any suitable rotational rate sensor may be utilized, for example, including one sensor (or multiple sensors) deployed in the rolling-stabilized housing and one or more markers (such as magnetic markers) deployed on the drill collar. In an example embodiment, the sensor may send an electrical pulse to the controller each time one of the markers rotates past the sensor, and the rotational rate may be calculated based on the time interval between the pulses. In one example embodiment, the sensor includes a Hall effect sensor and the marker may be a magnetic marker, but the present invention is clearly not limited in this regard.

[0108] Figure 9A and Figure 9B (collectively FIG. 9) depicts a deployment in a rotary steerable tool ( Figure 8) A schematic representation of an example of a rolling stabilization housing 970 (e.g., a sensor housing). It should be understood that this is merely an example, and the disclosed method embodiments are not limited to any particular rolling stabilization mechanism or configuration. In the example described, the rolling stabilization housing is mounted on bearings such that it is rotationally separated from the tool collar (capable of rotating independently of the tool collar). In the depicted embodiment, a first alternator 980 and a second alternator 985 (e.g., of the permanent magnet synchronous motor type) are respectively mounted on opposite axial ends of the rolling stabilization housing 970. The corresponding stator windings 981, 986 are mechanically continuous with the rolling stabilization housing 970 (and thus rotationally coupled to the rolling stabilization housing). The corresponding rotors including permanent magnets 982, 987 are configured to rotate independently of both the rolling stabilization housing 970 and the tool collar 962. The impeller blades 983, 988 are mechanically connected to the corresponding rotors and span the annular gap between the housing 970 and the tool collar 962 such that they rotate in opposite directions as, for example, drilling fluid 945 flows through the tool.

[0109] In the depicted example, the direction of rotation of the housing 970 can be controlled by the combined action of the alternators 980 and 985 in conjunction with the feedback provided by navigation sensors (e.g., accelerometers and / or magnetometers) deployed in the housing. The impellers 983 and 988 configured to rotate in opposite directions apply corresponding opposite torques to the housing 970. The amount of electrical load on the torque generators 980 and 985 can be varied in response to feedback from at least one sensor to vary the applied torque and thereby control the orientation of the housing. When used in a rotary steerable system, the control unit can have an output shaft rigidly connected to a rotary valve. The rotary valve directs the flow of fluid to an actuator in the steering bias unit, which is then used to steer the tool (e.g., by acting on the wellbore wall or by acting on the drill bit shaft). Thus, by controlling the orientation of the control unit, the orientation of the rotary valve is controlled, providing steering control.

[0110] Continuing to refer to Figure 8 and FIG. 9, it should be understood that the rotation of the drill collar or rolling stabilization housing in the Earth's magnetic field can induce an eddy current (or eddy currents) therein (Lorentz forces generated due to the Earth's magnetic field penetrating the rotating member). These eddy currents can generate additional magnetic fields along the radial axis of the BHA and thereby interfere with the magnetic field measurements (performed by the sensor 867). Additionally, the magnitude of the eddy currents and the corresponding interfering magnetic fields can depend on the size and geometry of the drill collar, the rotational rate of the drill collar and / or housing, and the type of drilling fluid utilized in the drilling operation. Methods are needed to compensate for (account for) the interfering magnetic fields generated by the eddy currents (especially since these magnetic fields can change during the drilling operation).

[0111] It should also be understood that magnetometer measurement results may be biased, and the bias may depend on the magnetization of the drill collar and other tool structures near the sensor. Although multi-station analysis (MSA) has been used to remove a constant bias offset, it has been found that the bias offset can change during a drilling operation, and surface data and measurement results are generally not sufficient to model the bias offset that changes over time and the depth while drilling. Methods are also needed to compensate for the offset bias of the magnetometer, especially the offset bias that changes during a drilling operation.

[0112] Figure 10 Depicts multiple coordinate systems and their interrelationships. For simplicity, the global north-east-down (NED) coordinate system is commonly used in the industry (where north and east refer to the north and east directions on the earth's surface and down refers to the direction directly pointing to the center of gravity of the earth). Figure 10 Also shown are multiple commonly used tool coordinate systems, including the PowerDrive (PD) coordinate system, the sensor (S) coordinate system, and the original (O) coordinate system. Figure 10 Also shown are mathematical transformations that can be used to convert measurement results from one coordinate system to another. As used herein, the original O coordinate system is defined as being aligned with the NED coordinate system at zero azimuth, zero tool face, and zero pitch angle (the pitch angle is defined as the inclination angle minus ninety degrees). The relationship between NED and the original (tool) coordinate system can be expressed mathematically, for example, as follows:

[0113]

[0114] where C represents cosine, s represents sine, ψ represents azimuth, φ represents the gravity tool face, and θ represents the pitch angle. For a coordinate system that uses the inclination angle (instead of the pitch angle), the relationship between NED and the original coordinate system can be expressed, for example, as follows:

[0115]

[0116] One aspect of the disclosed embodiments is to enable modeling of triaxial magnetometer measurement results, for example, as follows:

[0117]

[0118] where B x 、B y and B z represent triaxial magnetometer measurement results in the original coordinate system at a survey station (survey location), i, and represent the true magnetic field vector (or represent the true magnetic field measurement results of reality), b x 、b y and b zDenotes the magnetometer bias, γ c and γ s Denotes the rotation of the drill collar γ c and the rotation of the rolling stabilizer sensor housing γ s for the eddy current compensation terms, ω c and ω s Denotes the rotational speed (angular frequency) of the drill collar and the sensor housing, and and Denotes the error terms.

[0119] It should be understood that in some operations or at various times within an operation, the rotational speed of the sensor housing can be zero or close to zero, such that the above equations simplify to the following:

[0120]

[0121] In the NED coordinate system, gravity and magnetic fields can be defined as follows:

[0122]

[0123] Where G represents the total gravity field at that location, B represents the total magnetic flux at that location, and D represents the magnetic dip of the magnetic flux at that location. Assuming the true azimuth, inclination, and tool face are known, the true gravity vector and magnetic field vector in the original coordinate system (e.g., at the tool) can be expressed as follows:

[0124]

[0125] The magnetometer bias can be considered a semi-constant parameter. For example, at survey station i, if the true magnetic field is then the bias offset can be expressed as follows:

[0126]

[0127] Now turning to Figure 11 , as described above, the interfering magnetic field can be caused, for example, by one or more eddy currents in the rotating drill collar and / or sensor housing. The rotation of the drill collar and / or housing in the Earth's magnetic field B 场 can generate eddy currents in the drill collar and / or housing (due to the Lorentz force generated by the Earth's magnetic field penetrating the rotating drill collar and / or housing). The interfering field B 涡流 points in the radial direction, as shown, such that the measured field B 传感器 can deviate from the external field B 场 . In the present disclosure, it is assumed that the magnitude of B 涡流 (the magnetic field induced by eddy currents) is proportional to the strength of the external magnetic field B 场 , the rotational speed of the drill collar ω c and / or the sensor housing ω s and the eddy current coefficient γc and γ s is proportional. It is also assumed that the induced magnetic field B 涡流 is orthogonal to the external magnetic field due to the symmetry of the drill collar and the sensor housing.

[0128] Based on the above assumptions, the induced magnetic field caused by eddy currents in the drill collar and the sensor housing can be expressed, for example, as follows:

[0129]

[0130] In an operation where the sensor housing is substantially stationary with respect to the ground (non-rotating) (or at a time when the sensor housing is substantially stationary with respect to the ground (non-rotating)), the previous equation can be simplified as follows:

[0131]

[0132] As shown above, the eddy current effect can be approximated as a rotation of the misalignment matrix about the tool axis (the x-axis in the original coordinate system). It is necessary to accurately estimate the eddy current compensation terms γ c and γ s , in order to accurately compensate (correct) the magnetic field measurement results for the eddy current effect.

[0133] Figure 12A and Figure 12B (collectively referred to as Figure 12) depict an example method for drilling a subterranean wellbore. The method can include deploying a drill string in the wellbore, including the BHA, for example, as Figure 7 shown. The BHA can include a rotary steerable drilling tool that includes a drill collar and a rolling stabilizer sensor housing, for example, as Figure 8 and Figure 9 shown. At 1202, the BHA is rotated in the wellbore to, for example, drill the well. At 1204, corresponding sensors located in the rolling stabilizer housing are used to make triaxial magnetic field measurements and triaxial accelerometer measurements (gravity field measurements). The rotation rate of the drill collar and / or the sensor housing can also be measured at 1204. At 1206, the triaxial accelerometer measurement results can be evaluated to calculate the wellbore inclination I, the total gravity G, and the gravity tool face GTF of the sensor housing. At 1208, a Kalman filter can be used to process the wellbore inclination, the gravity tool face, the magnetic field measurement results, and the latest deviation offset, eddy current compensation, and total magnetic field to calculate the wellbore azimuth ψ, the derivative of the wellbore azimuth with respect to time the updated magnetometer deviation, the total gravity, and the eddy current compensation value, as indicated at 1209. When drilling continues at 1202, the wellbore inclination and the wellbore azimuth can optionally be used for wellbore position and trajectory control at 1210. For example, the drilling direction at 1202 can be adjusted (e.g., by adjusting the position of the vanes or other actuating components in the rotary steerable tool) in response to the inclination and the azimuth to continue drilling along a predetermined path or some other desired path.

[0134] According to at least one embodiment of the present disclosure, gyroscopic surveys can be used to determine the wellbore azimuth ψ or the tool face. For example, the roll stabilization unit can include one or more gyroscopic survey units. The gyroscopic survey unit can prepare an azimuth survey to determine the azimuth and / or tool face of the steering unit. In some embodiments, the techniques discussed herein with respect to determining magnetic deviation can utilize the wellbore azimuth ψ or tool face determined by a gyroscopic survey tool. Utilizing the surveyed wellbore azimuth can help improve the accuracy and / or precision of magnetic deviation determination. In some embodiments, utilizing the measured wellbore azimuth can allow for accurate survey measurements in exclusion zones or zones where magnetic surveys are unreliable. As discussed herein, such exclusion zones include directions at or near 90° (e.g., east) and 270° (e.g., west).

[0135] An example state model can be defined as follows, for example:

[0136] β k+1 = Gβ k + ω

[0137] In one example:

[0138]

[0139] where ψ represents the wellbore azimuth, represents the derivative of the wellbore azimuth with respect to time, γ represents the eddy current compensation term of the drill collar or sensor housing, B represents the total magnetic field, and b x , b y and b z represent magnetometer biases. The measurement model can be defined as follows, for example:

[0140]

[0141] where H represents the observation model function. The extended Kalman filter can be configured to solve this problem and calculate ψ, γ, B, b x , b y and b z . For this example, the system prediction step can be expressed as follows:

[0142]

[0143] Although embodiments of the present disclosure may discuss calculating the wellbore azimuth ψ, it should be understood that when gyroscopic azimuth measurements are utilized, the extended Kalman filter may not be used to calculate ψ and / or

[0144] The Kalman gain calculation can be given as follows:

[0145]

[0146] The state vector and covariance matrix can be updated with the measurement results as follows:

[0147]

[0148] where β is the state vector including , G is the system matrix (and not to be confused with the total gravity), R is the covariance matrix of system uncertainty, Q is the measurement noise covariance matrix, and J is the Jacobian matrix that is the differential of H with respect to β. The content of the Jacobian matrix can be obtained, for example, using the symbolic math toolbox of MATLAB.

[0149] In some embodiments, when using gyro surveys to determine azimuth, the Jacobian matrix of K with respect to x is given by:

[0150]

[0151] where X is the system vector:

[0152]

[0153] If multiple surveys are performed during the drilling process with various tool face angles but without changing the inclination and / or azimuth, then:

[0154]

[0155] The parameter x can be estimated using:

[0156]

[0157] This recursive process can end when the process converges:

[0158] err = norm(x j+1 - x j )

[0159] According to at least one embodiment of the present disclosure, the azimuth can be calculated while performing drilling activities. For example, a gyro survey can measure the tool face or gyro azimuth of the tool while the drill string is rotating. Performing a survey of the tool face while performing drilling activities in combination with the magnetic deviation determination discussed herein can help generate a more responsive real-time survey. Such a real-time survey can respond more quickly to sudden changes in azimuth. This can enable the drilling operator to implement changes to the drilling system, including changes to the RSS, more quickly, thereby improving the steering accuracy and / or precision.

[0160] The system azimuth model can be estimated by:

[0161]

[0162] The observation model can be identified by the following formula:

[0163]

[0164] where ψ magk is the azimuth estimated from the 6-axis magnetic survey readings. is the azimuth change rate estimated from the gyroscope signal. can be calculated by the following formula:

[0165]

[0166] where φ is the tool face, ω y , ω z are the gyroscope readings of the y-axis and z-axis, and θ is the pitch angle. The survey measurements from the gyroscope survey can be used to further apply this smoothing to the inclination and tool face.

[0167] Figure 13A and Figure 13B (collectively referred to as Figure 13) depict the flowcharts of example methods for drilling an underground wellbore. These methods may include deploying a BHA in the wellbore, where the BHA includes a rotary steerable drilling tool having a rolling stabilizer sensor housing, as described above with respect to Figure 12 (and Figure 8 and Figure 9). At 1322, the BHA is rotated in the wellbore to drill, for example. At 1324, corresponding sensors located in the rolling stabilizer housing are used to perform triaxial magnetic field measurements and triaxial accelerometer measurements (gravitational field measurements). The rotation rate of the drill collar can also be measured at 1324. At 1326, the triaxial accelerometer measurements can be evaluated to calculate the wellbore inclination I, the total gravity G, and the gravity tool face GTF of the sensor housing.

[0168] In Figure 13A , at 1328, the eddy current compensation term γ can be calculated based on the measured drill collar rotation rate (or the change in the drill collar rotation rate), as also shown at 1340 in Figure 13B . At 1330, the wellbore inclination, the gravity tool face, the magnetic field measurements, and the latest magnetometer bias, the eddy current compensation term, and the total magnetic field are then processed using a Kalman filter to calculate the wellbore azimuth ψ, the derivative of the wellbore azimuth with respect to time and the updated magnetometer bias and the total gravity. When drilling continues at 1322, the wellbore inclination and the wellbore azimuth can optionally be used for wellbore position and trajectory control at 1332. For example, the drilling direction at 1322 can be adjusted (e.g., by adjusting the position of the blades or other actuating components in the rotary steerable tool) in response to the inclination and azimuth to continue drilling along a predetermined path.

[0169] As discussed above with respect to FIG. 12, a gyroscopic survey tool can be used to directly measure the wellbore azimuth. This can help increase the accuracy of eddy current compensation.

[0170] It should be understood that Figure 13A and Figure 13B the method in Figure 12A and Figure 12B is similar to the method in

[0171] β k+1 ×Gβ k +ω

[0172] In one example:

[0173]

[0174] The measurement model can be defined as described above, for example, where γ is obtained using a separate algorithm. The content of an example Jacobian matrix for H can also be obtained as described above.

[0175] For example, the eddy current compensation term γ can be estimated based on the change in angle X when the rotation rate changes. It should be understood that angle X is the angle between the gravity and magnetic field vectors in the y - z plane (the transverse axis plane perpendicular to the axis of the BHA) and can be calculated, for example, as follows:

[0176]

[0177] where |B yz | and |G yz | represent the magnitudes of the transverse (yz) components of the magnetic field measurement results and accelerometer measurement results. In the absence of eddy currents, angle X is substantially constant. However, it has been found that angle X changes with the change in the drill collar rotation rate (e.g., increases as the rotation rate increases). This dependence on the drill collar rotation rate can be used to estimate the eddy current compensation term γ (and to estimate the change in the eddy current compensation term as the drill collar rotation rate changes). An example error model for angle X is given below:

[0178]

[0179] where σ(dB) and σ(dG) are the magnetometer readings and the accelerometer readings The standard deviation of the noise level (including ambient noise). There are geometric conditions where high errors are observable. Generally, high errors are observed when the tool axis is parallel to the reference magnetic field or the gravitational field. More generally, the noise may be greater when the wellbore is traveling north in the northern hemisphere, south in the southern hemisphere, and the tool is vertical.

[0180] Figure 14 Schematically depicts a cross - section of an exemplary drill collar and indicates an example method for estimating the eddy - current compensation term γ based on the relationship between the angle X and the rotational rate of the drill collar (or sensor housing). (For simplicity of illustration, the sensor housing is not shown.) The transverse - axis magnetic field B is indicated 场 and the transverse - axis gravitational field G yz . As described above, the angle X is the angle between these two vectors in the transverse - axis plane. In this depiction, it is assumed that the angle X is X0 when the drill - collar rotational rate is zero, X1 when the drill - collar rotational rate is ω1, X2 when the drill - collar rotational rate is ω2, and so on. Based on Figure 14 the depiction in, the angle X can be expressed as a function of the drill - collar (and / or sensor housing) rotational rate as follows:

[0181] X ω = X0+atanγω

[0182] Taking the derivative of the angle X with respect to ω and solving for γ yields the following equation:

[0183]

[0184] Although the foregoing equation provides a suitable solution for the eddy - current compensation term γ, a simplified solution can be obtained by recognizing that when ω 2 <<α 2 (e.g., when ω 2 / α 2 is close to zero), the eddy - current compensation term can be approximated as follows:

[0185]

[0186] This approximation can provide a more robust calculation of γ and advantageously has an error of less than 1% under most drilling conditions (e.g., drill - collar rotational rate less than about 900 rpm).

[0187] Referring again to Figure 13B, at 1340, an updated eddy current compensation term γ can be calculated, for example, as follows. At 1342, a change in the rotary rate of the drill collar (or sensor housing) can be detected. For example, a moving average can be applied to the drill collar rotary rate measurements at 1342 (e.g., a moving average of 25 or 50 measurements). The range (max - min) of the average rotary rate can be calculated over a predetermined time interval (e.g., in overlapping 2 - minute windows) and compared at 1344 to a threshold (e.g., 50 rpm, 100 rpm, or 150 rpm). When the range is greater than the threshold, additional data is collected at 1346 and an updated eddy current compensation term γ is calculated at 1348, for example, via calculating a linear regression of the rotary rate and angle X. At 1350, the updated eddy current compensation term γ can optionally be checked, for example, via evaluating the standard error σ γ , the fitting error e X and / or the difference from a reference obtained from a previous data set |γ - γ ref |. When the quality control parameters are within a predetermined standard, the updated eddy current compensation term γ can be input into a Kalman filter. It should be understood that the updated eddy current compensation term γ can be calculated, for example, by averaging a new estimate with a previous estimate (or a fraction of the previous estimate) to reduce noise.

[0188] Now turning to Figure 15A and Figure 15B (collectively FIG. 15), a flowchart depicting yet other example methods for drilling a subterranean wellbore is shown. The methods in FIGS. A and Figure 15B are similar to the above - described methods in that they include deploying a BHA in the wellbore, where the BHA includes a rotary steerable drilling tool having a rolling - stabilized sensor housing, as described above. At 1562, the BHA is rotated in the wellbore to, for example, drill the well. At 1564, the rolling - stabilized sensor housing is rotated slowly relative to the wellbore. Slowly rotating means that the sensor housing rotary rate is much less than the drill collar and / or BHA rotary rate. For example, the sensor housing rotary rate can be less than about 10 rpm. In one example implementation described in more detail below by way of example, the sensor housing rotary rate is 4 rpm. In the example implementation, the rolling - stabilized sensor housing can be stationary relative to the ground during certain time intervals and slowly rotate during other time intervals. For example, at a predetermined time or depth interval, the rolling - stabilized sensor housing can slowly rotate for a predetermined time (e.g., 1 minute or 2 minutes) or a predetermined number of rotations (e.g., 2, 4, or 6 full rotations).

[0189] At 1566, triaxial magnetic field measurements and triaxial accelerometer measurements (gravity field measurements) are made using corresponding sensors located in a rolling stabilization housing while the sensor housing rotates slowly. The rotation rate of the drill collar and / or the sensor housing can also be measured at 1566. At 1568, the triaxial accelerometer measurement results can be evaluated to calculate the wellbore inclination I, the total gravity G, and / or the gravity tool face GTF of the sensor housing.

[0190] Figure 15A and Figure 15B The methods in Figure 13A and Figure 13B are similar in that they also include, at 1570, calculating an eddy current compensation term γ (or terms) based on the rotation rate of the drill collar and / or the sensor housing (or a change in the rotation rate). For example, the methods in 15A and 15B can include calculating a first eddy current compensation term γ based on the rotation rates of the drill collar and the sensor housing c and a second eddy current compensation term γ s . It should be understood that in some tool embodiments, the sensor housing can be made of a highly conductive aluminum alloy, and even if the sensor housing rotates slowly relative to the drill collar, the eddy current effect can be significant.

[0191] At 1572 (also depicted at 1580 in Figure 15B ), the magnetometer measurements taken at 1566 while the sensor housing rotates slowly downhole and the updated eddy current compensation term are processed to calculate a new magnetometer bias. At 1574, this new magnetometer bias, the eddy current compensation term, the magnetometer measurement results, and the wellbore inclination are evaluated to calculate the wellbore azimuth ψ. At 1576, the calculated wellbore azimuth and the previous wellbore azimuth can be further processed using a Kalman filter to calculate a corrected (or smoothed or filtered) wellbore azimuth. When drilling continues in 1562, the wellbore inclination and the wellbore azimuth can then optionally be used for wellbore position and trajectory control at 1578. For example, the drilling direction in 1562 can be adjusted (e.g., by adjusting the position of vanes or other actuating components in a rotary steerable tool) in response to the inclination and the azimuth to continue drilling along a predetermined path.

[0192] Continuing to refer to FIG. 15, the state model of the Kalman filter can be given, for example, as follows:

[0193] β k+1 = Gβ k + ω In one example,

[0194]

[0195] The measurement model can be defined as follows, where the updated eddy current compensation term γ is calculated as described above.

[0196]

[0197] where ψ temp k is the temporary orientation and H = (1 0). The latest ψ temp k can be derived from the modified magnetometer readings with the latest deviation and γ. For example, the magnetometer readings can be corrected using the following equation.

[0198]

[0199] It should be noted that the magnetometer measurement results are corrected to remove the deviation and compensate for the eddy current induced effect on the magnetometer measurement results.

[0200] The orientation, magnetic dip, and total magnetic field can be calculated as follows based on the measured accelerometer and magnetometer measurement results.

[0201]

[0202] The system prediction step can be given as follows:

[0203]

[0204] The Kalman gain calculation is given below.

[0205]

[0206] The state vector and covariance matrix can be updated with the measurement results, for example, as follows:

[0207]

[0208] Continuing to refer to Figure 15B , the eddy current compensation term γ c and γ s as well as the magnetometer bias are updated independently of the Kalman filter. At 1580, downhole multi-station analysis (MSA) can be used to estimate the bias components. In this exemplary implementation, bias determination includes detecting slow sensor housing rotation and (e.g., over at least 2 full rotations of the sensor housing) collecting multiple sets of magnetometer measurement results. MSA can be used to evaluate the magnetometer bias (described in more detail below). An optional quality control step can be employed before outputting the updated magnetometer bias.

[0209] An example measurement model for MSA is given below.

[0210]

[0211] where w( and ) represents the error, and K can be defined according to the measurement model discussed above:

[0212] The system vector x includes at least the magnetometer bias b x , b y and b z , and may optionally also include other known parameters, such as B, D, and / or ψ. Including one or more of the other known parameters may be advantageous, for example, to provide a quality control check on the calculated bias. An example system vector x is given below:

[0213]

[0214] In this example, the other parameters (such as I, γ s , γ c , ω s , ω c , D, and φ) are considered known and input into the MSA model as constants. Since the relationship between the system vector and the observed magnetic field measurements is non - linear, it is advantageous to use non - linear optimization (such as the Gauss - Newton method for minimizing w) to solve the problem.

[0215] The Jacobian matrix of K with respect to the system vector x is given below.

[0216]

[0217] where the components of J can be obtained as described above K .

[0218] Continuing to refer to FIG. 15, multiple sets of accelerometer and magnetometer measurements can be taken while slowly rotating the sensor housing. It can be assumed that these multiple survey sets have the same azimuth and inclination (since the depth of the wellbore is essentially constant over the short time period during which multiple sets are collected), but have different tool face angles (since the sensor housing is slowly rotating while multiple sets are being collected). The measurements can be expressed, for example, as follows:

[0219]

[0220] The system vector x can be estimated by repeatedly solving the following equations:

[0221]

[0222] The recursive process ends when it converges and the error is less than a threshold, where:

[0223] error = norm(x j+1 - x j ) Although magnetic dip is used to estimate the bias, B can also be estimated and can be used for QC of the estimated bias parameters.

[0224] It should be understood that the above process can also be used to correct accelerometer bias, for example, by including an accelerometer bias term in the system vector x.

[0225] The effectiveness of the methods in Figure 15A and Figure 15B is now shown in more detail by the following non - limiting synthesis examples. Figure 16 FIG. depicts the tool face of the sensor housing, the drill collar rotation rate, and the wellbore azimuth over time. In this example, the drill collar rotation rate 1602 increases from about 60 rpm to about 840 rpm at 600 seconds. The sensor housing rotates slowly at 4 rpm through 4 complete rotations at 400 seconds, 800 seconds, and 1200 seconds, and otherwise is stationary relative to the ground at a tool face angle of - 90 degrees, as indicated at 1604. The true wellbore azimuth 1606 is constant at 50 degrees from 0 to 900 seconds and then increases linearly over time to 70 degrees at 1800 seconds. The wellbore azimuth calculated using the raw magnetometer measurements is about 3 to about 6 degrees less than the true wellbore azimuth, as indicated, for example, at 1608. At about 400 seconds (at 1610), the method described above with respect to FIG. 15 is used to correct the magnetometer bias. However, the eddy current compensation is arbitrarily set to a default value based on the size (e.g., diameter) of the drill collar. The resulting wellbore azimuth measurement is about 1 degree less than the true wellbore azimuth (due to uncompensated eddy currents). At about 600 seconds, the rotation rate of the drill collar increases to about 840 rpm, thereby further increasing the eddy current error, as shown at 1612. At about 1250 seconds, the eddy current compensation term is updated, but the magnetometer bias remains the same as the correction made at 400 seconds. It should be noted that the azimuth error is significantly reduced but still significant. At about 800 seconds and 1200 seconds, the eddy current compensation term and the magnetometer bias are updated simultaneously as described above with respect to FIG. 15. The resulting wellbore azimuth estimate is within about 0.1 degrees of the true wellbore azimuth or less, as shown at 1614.

[0226] Further referring to the methods disclosed in FIGS. 12, 13, and 15, it should be understood that the calculated survey parameters (e.g., wellbore inclination and wellbore azimuth) can be stored in downhole memory and / or transmitted to the surface, for example, via mud pulse telemetry, electromagnetic telemetry, wired drill pipe, or other telemetry techniques. In some embodiments, the accuracy of the wellbore inclination and wellbore azimuth may be sufficient such that the drilling operation can forego the use of conventional static survey techniques. In such embodiments, the wellbore survey can be performed at the surface based on the transmitted measurements and / or at the downhole using a downhole processor.

[0227] Still further referring to FIGS. 12, 13, and 15, the calculated survey parameters can be used to control and / or change the drilling direction. For example, in many drilling operations, the wellbore (or a portion of the wellbore) is drilled according to a drilling plan, such as according to a predetermined direction (e.g., defined by the wellbore inclination and wellbore azimuth) or a predetermined curvature. In some embodiments, the calculated wellbore inclination and wellbore azimuth can be compared with the desired inclination and azimuth. For example, to meet the drilling plan, or when the difference between the calculated direction (inclination and azimuth) or curvature and the desired direction (inclination and azimuth) or curvature exceeds a predetermined threshold, the drilling direction can be changed. Such a change in the drilling direction can be effected, for example, by actuating a steering element deployed in a rotary steerable tool (such as one of the rotary steerable tools described above) above the drill bit. In some embodiments, the survey parameters can be calculated in the rolling stabilizer housing in the RSS, which can further evaluate the survey parameters and the drilling plan to calculate a new drilling direction to meet the plan. In some embodiments, the survey parameters can be sent to the surface using telemetry such that the survey parameters can be analyzed. In view of the survey parameters, the drilling parameters (e.g., bit weight, rotary speed, mud pump rate, etc.) can be modified and / or a downlink can be sent to the RSS to change the drilling direction. In some embodiments, both downhole control and surface control can be used.

[0228] It should be understood that the methods described herein can be configured to be implemented via one or more controllers deployed downhole (e.g., in a rotary steerable tool or an MWD tool). Suitable controllers can include, for example, programmable processors such as digital signal processors or other microprocessors or microcontrollers and processor-readable or computer-readable program code embodying logic. Suitable processors can be used, for example, to execute the method embodiments (or various steps in the method embodiments) described above with respect to FIGS. 12, 13, and 15. Suitable controllers can also optionally include other controllable components such as sensors (e.g., temperature sensors), data storage devices, power supplies, timers, etc. The controller can also be arranged to communicate electronically with an accelerometer and a magnetometer. Suitable controllers can also optionally communicate with other instruments in the drill string (e.g., a telemetry system that communicates with the surface). Suitable controllers can also optionally include volatile or non-volatile memory or data storage devices.

[0229] The implementation of the downhole survey system has been described mainly with reference to wellbore drilling operations; the downhole survey system described herein can be used in applications other than wellbore drilling. In other implementations, the downhole survey system according to the present disclosure can be used outside of wellbores or other downhole environments for the exploration or production of natural resources. For example, the downhole survey system of the present disclosure can be used in boreholes for placing utility pipelines. Accordingly, the terms "wellbore", "borehole", etc. should not be construed as limiting the tools, systems, components, or methods of the present disclosure to any particular industry, field, or environment.

[0230] One or more specific implementations of the present disclosure are described herein. These described implementations are examples of the presently disclosed technology. Additionally, to provide a brief description of these implementations, not all features of the actual implementations may be described in the specification. It should be understood that numerous implementation-specific decisions will be made in developing any such actual implementation in any engineering or design project to achieve the developer's specific goals, such as meeting system-related and business-related constraints, which may vary between different implementations. Further, it should be understood that such development work may be complex and time-consuming, but would still be a routine task in design, fabrication, and manufacture for those of ordinary skill in the art who would benefit from the present disclosure.

[0231] Additionally, it should be understood that references to "one implementation" or "implementations" of the present disclosure are not intended to be construed as excluding the existence of additional implementations that also incorporate the recited features. For example, any element described with respect to an implementation herein can be combined with any element of any other implementation described herein. As will be appreciated by those of ordinary skill in the art as covered by the implementations of the present disclosure, the numbers, percentages, ratios, or other values recited herein are intended to include the recited values, and also other values that are "about" or "approximately" the recited values. Accordingly, the values should be construed broadly enough to cover at least values that are sufficiently close to the recited values to perform the desired function or achieve the desired result. The values include at least the variations expected in a suitable manufacturing or production process, and can include values within 5%, 1%, 0.1%, or 0.01% of the recited values.

[0232] In view of the present disclosure, those of ordinary skill in the art should recognize that equivalent structures do not depart from the spirit and scope of the present disclosure, and various changes, substitutions, and alterations can be made to the embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent structures (including functional "means-plus-function" clauses) are intended to cover structures described herein as performing the recited function, including structural equivalents that operate in the same manner and equivalent structures that provide the same function. The applicant's express intent is not to invoke means-plus-function or other functional limitations for any claim, except for those claims in which the words "means for" appear with the associated function. Every addition, deletion, and modification to an embodiment that falls within the meaning and scope of the claims will be embraced by the claims.

[0233] As used herein, the terms "about," "approximately," and "substantially" mean an amount that is within standard manufacturing or process tolerances or an amount that is close to the recited amount and still performs the desired function or achieves the desired result. For example, the terms "about," "approximately," and "substantially" can refer to an amount that is within less than 5%, less than 1%, less than 0.1%, and less than 0.01% of the recited amount. Additionally, it should be understood that any direction or reference frame in the foregoing description is only a relative direction or movement. For example, any reference to "up" and "down" or "above" or "below" only describes the relative position or movement of the relevant elements.

[0234] Without departing from the spirit or characteristics of the present disclosure, the present disclosure may be embodied in other specific forms. The described embodiments are to be considered illustrative rather than restrictive. Accordingly, the scope of the present disclosure is indicated by the appended claims rather than by the foregoing description. Changes within the meaning and range of equivalents of the claims will be included within the scope of the claims.

Claims

1. A rotary steerable system for drilling a subterranean wellbore, the rotary steerable system comprising: A rolling stabilizer housing deployed in a drill collar, the drill collar being configured to rotate with a drill string, the rolling stabilizer housing being configured to rotate independently of the drill collar during drilling; And An azimuth sensor package, the azimuth sensor package including a multi-axis gyroscopic azimuth sensor capable of rotating about the axis of rotation of the rolling stabilizer housing, the azimuth sensor package including at least one of the following: A rotation rate sensor configured to measure the rotation rate of the drill collar; A triaxial accelerometer set; and A triaxial magnetometer set deployed in the rolling stabilizer housing.

2. The rotary steerable system of claim 1, wherein the azimuth sensor package is located on the rolling stabilizer housing.

3. The rotary steerable system of claim 1, wherein the azimuth sensor package is rotationally fixed relative to the rotation of the drill string.

4. The rotary steerable system of claim 1, wherein the azimuth sensor package is within 20 m of the tool face.

5. The rotary steerable system of claim 1, wherein the azimuth sensor package includes a calibration manager that uses azimuth measurements from the multi-axis gyroscopic azimuth sensor to calibrate the triaxial magnetometer set.

6. The rotary steerable system of claim 5, wherein the calibration manager uses measurements from the triaxial magnetometer set to calibrate the multi-axis gyroscopic azimuth sensor.

7. A method for drilling a subterranean wellbore, the method comprising: Rotating a bottom hole assembly (BHA) in the subterranean wellbore for drilling, the BHA including a rolling stabilizer housing deployed in a drill collar and configured to rotate relative to the drill collar, a triaxial accelerometer set, a triaxial magnetometer set, and a gyroscopic azimuth sensor deployed in the rolling stabilizer housing; Using the gyroscopic azimuth sensor to collect azimuth measurements; Using the triaxial accelerometer set and the triaxial magnetometer set to make corresponding triaxial accelerometer measurements and triaxial magnetometer measurements while the BHA rotates; Measuring the rotation rate of the drill collar while the BHA rotates; Using the azimuth measurements to generate a tool face of the BHA; And Using the tool face of the BHA, the triaxial magnetometer measurements, and the rotation rate to generate an azimuth of the BHA.

8. The method of claim 7, the method further comprising: Generating eddy current effects and magnetometer biases, and wherein generating the azimuth includes compensating for eddy current effects and magnetometer biases.

9. The method of claim 7, wherein the BHA further includes a rotary steerable drilling tool, the rolling stabilizer housing is deployed in the rotary steerable drilling tool, and the method further includes actuating a steering element on the rotary steerable drilling tool to change the drilling direction.

10. The method according to claim 7, wherein generating the orientation includes inputting the tool face, the triaxial magnetometer measurement result, the magnetometer deviation, and the eddy current compensation term into a Kalman filter, thereby generating an updated magnetometer deviation and an updated eddy current compensation term.

11. The method according to claim 7, the method further comprising using the triaxial accelerometer measurement result to determine the inclination angle of the BHA.

12. The method according to claim 11, wherein determining the inclination angle includes: detecting a change in the rotation rate of the drill collar; using the change in the rotation rate of the drill collar and the triaxial magnetometer measurement result to generate an eddy current compensation term; and inputting the inclination angle, the tool face, the triaxial magnetometer measurement result, the eddy current compensation term, and the magnetometer deviation into a Kalman filter to generate the orientation and an updated magnetometer deviation.

13. The method according to claim 12, wherein the eddy current compensation term is generated based on a change in angle when the change in the rotation rate of the drill collar is detected, wherein the angle is formed between the gravity and magnetic field vectors in the transverse axis plane of the drill collar.

14. The method according to claim 13, wherein the eddy current compensation term is equal to the derivative of the angle with respect to the rotation rate of the drill collar.

15. A rotary steerable system for drilling a subterranean wellbore, the rotary steerable system comprising: a rolling stabilizer housing deployed in a drill collar, the drill collar being configured to rotate with a drill string, the rolling stabilizer housing being configured to rotate independently of the drill collar during drilling; an orientation sensor package; and a controller including a memory and a processor, the memory including instructions that cause the processor to: collect gyroscopic orientation measurement results, accelerometer measurement results, and magnetometer measurement results using the orientation sensor package; measure the rotation rate of the rolling stabilizer housing when the drill collar rotates; generate the tool face of the drill collar using the gyroscopic orientation measurement results; and generate the orientation of the drill collar using the tool face, the magnetometer measurement result, and the rotation rate.

16. The rotary steerable system according to claim 15, wherein the instructions further cause the processor to generate an eddy current effect and a magnetometer deviation, and wherein generating the orientation includes compensating for the eddy current effect and the magnetometer deviation.

17. The rotary steerable system according to claim 15, the rotary steerable system further comprising a rotary steerable drilling tool, the rolling stabilizer housing being deployed in the rotary steerable drilling tool, and wherein the instructions further cause the processor to actuate a steering element on the rotary steerable drilling tool to change the drilling direction.

18. The rotary steerable system according to claim 15, wherein generating the orientation includes inputting the tool face, the magnetometer measurement result, the magnetometer deviation, and the eddy current compensation term into a Kalman filter, thereby generating an updated magnetometer deviation and an updated eddy current compensation term.

19. The rotary steerable system according to claim 15, wherein the memory includes instructions that further cause the processor to use the accelerometer measurement results to determine the inclination angle of the drill collar.

20. The rotary steerable system according to claim 19, wherein determining the inclination angle comprises: detecting a change in the rotational rate of the drill collar; using the change in the rotational rate of the drill collar and the magnetometer measurement results to generate an eddy current compensation term; and inputting the inclination angle, the tool face, the magnetometer measurement results, the eddy current compensation term, and the magnetometer bias into a Kalman filter to generate the azimuth and an updated magnetometer bias.

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