BR112018013835B1 - BOTTOM WELL ASSEMBLY AND DIRECTIONAL DRILLING METHOD OF WELL BORE SECTIONS - Google Patents

Abstract

The rotary drill tool and system described herein combine both point the bit and push the bit techniques to actively change the direction of the unfinished hole path. In this system, deflection of the drill bit is limited to a single degree of freedom with respect to a coordination system that is attached to and rotates with the rotatable steerable drill tool, which results in simplified attachment of the drill assembly and mechanics. impeller unit. Additionally, drilling is accomplished by dynamically controlling the spatial phase and amplitude of coherent symmetrical bidirectional oscillating deflections of the drill bit relative to fixed ground information as the tool is simultaneously rotating, aiming and pushing the bit. The amplitude and strength of drill deflections can be variably controlled during driving operations to dynamically adjust the instantaneous build-up rate as needed. When driving is not active, the drill can be mechanically locked in the neutral position.

Description

FIELD OF TECHNIQUE

[001] The apparatus and methods disclosed in this invention relate to drilling wells and precision navigation of placement of wellbore trajectories, which includes wells for the production of crude oil, hydrocarbon or natural gas. More specifically, the apparatus and methods disclosed in this invention relate to a rotary drilling downhole assembly that is driveable and a positive displacement power section, which can be used independently or in combination with each other.

BACKGROUND

[002] Rotary drilling systems have long been used in directional drilling for hydrocarbons. Generally, such systems used both “push the bit” and “point the bit” technology. The first type of system continually off-centers the drill in a given direction, while the latter changes the direction of the drill relative to the rest of the tool. Both types of existing rotary drive systems offer significant advantages, although both also suffer from certain disadvantages, as discussed in further detail below.

[003] A prior disclosure for a rotary drive drilling apparatus and method is no later than 1973 and is described by Bradley in U.S. Patent 1973. 3,743,034 (hereinafter "Bradley"). This disclosure covers a range of topics, such as using a mud-driven downhole turbine or an electric motor to drive a positive displacement hydraulic pump, the use of a universal joint to connect two shafts that can be arbitrarily or continuously articulated. relative to each other and use hydraulic pistons as actuators to continuously maintain a desired offset direction that is constant relative to ground information as the tool is rotating. Since Bradley predates the commercial application of microprocessors in downhole tools, it relies on a high-speed scalar surface telemetry link using wired drill pipe in which segments of insulated electrical conductor are constructed within each drill pipe joint (as described by Fontenot in 1970 in U.S. Patent 3,518,699) to carry electrical signals through the drill pipe to the surface in order to control tool driving. Bradley has been shown to control the angle of deflection of the impeller unit by regulating the length of time the piston control valves, the same valves that also control the drilling direction in this configuration, open and close, to allow greater or lesser amounts of fluid to flow. enter or leave the pistons, thereby changing the amplitude of the oscillating motion of the pistons.

[004] Some previous designs of rotary driven tools use the drilling mud and the pressure drop along the bit to actuate the drive drive mechanism, regardless of whether you use the point the bit technique, push the bit technique or a combination of the two. two. Other earlier tool designs use a mud turbine that drives an electrical alternator to generate the electrical power to drive the bit and maintain angular displacement.

[005] The rotary driveable apparatus that is the topic of this disclosure solves a number of operational limitations associated with existing rotary driveable systems. Initially, it is important to note that this disclosure encompasses two distinct inventions, both of which are described in greater detail below - a dynamically variable displacement axial piston pump and a hinge joint that limits the drill pivot to a single degree of freedom ( instead of a universal joint with 2 or more degrees of freedom), which provides spatially phased coherent symmetrical bidirectional deflection of the drill bit. Both inventions can be used together, but either can also be used independently of the other. The term “spatial phasing” refers to the dynamic timing of an event or action related to the bit's articulation, as the tool is rotating, relative to fixed terrestrial inputs, such as gravity or the earth's magnetic field. Spatial phase is expressed in terms of the instantaneous rotational orientation (a tool face) of a datum mark on the tool with respect to gravity (gravity tool face) or the earth's magnetic field (magnetic tool face).

[006] First, regarding the advantages of the dynamically variable displacement axial piston pump, using a fixed positive displacement pump in the wellbore to generate hydraulic power works only over a very narrow range of mud flow rates. If the turbine is generating enough power at the low end of the flow range, then it will potentially be generating too much power at the high end of the flow range unless the allowable flow range is extremely narrow, in which case This way, it restricts the drill chief's ability to optimize drilling parameters for efficiency and safety without damaging the tool. The innovative use of a dynamically variable displacement axial piston pump disclosed herein solves this problem by dynamically reducing pump displacement per revolution to maintain constant power output as slurry flow increases, and increasing It dynamically changes its displacement per revolution as the mud flow decreases. Second, the amplitude of drill deflections, whether static or oscillatory, can be controlled by additionally adjusting the displacement per revolution of the dynamically variable displacement pump, which allows control of the drill linkage amplitude independent of the speed control. drilling direction as the tool is rotating, whether the objective is to maintain a constant bit offset angle regardless of rotation or whether the bit is oscillating at the same frequency as the drill collar rotation.

[007] As used in this document, the term "dynamically variable displacement axial piston pump" refers to a hydraulic pump with a rotating cylinder, driven by a drive shaft, which can be configured with two or more pistons, symmetrically arranged in the cylinder, which oscillates in a direction that is parallel to the axis of rotation of the cylindrical piston block. The structure of this bomb is described in further detail in the following sections of this disclosure. One end of each piston may end with a “slider cup” that contacts and slides on the face of a swashplate type swashplate. The swashplate type swash plate is not connected to the drive shaft. Instead, the swashplate-type swashplate is mounted on a separate shaft whose centerline is orthogonal to, but intersects, the centerline drill string of the driveshaft. When the face of the swashplate swashplate is perpendicular to the axis of the drive shaft, this is called a “zero degree” swashplate swashplate angle. In this swashplate swashplate position, as the cylinder block rotates, the pistons do not wobble and pump displacement is zero. As the slope angle of the swashplate type swashplate is increased to some angle θ, the pistons begin to oscillate, which increases the displacement of the pump according to the equation Q=QO * sin(θ), where Qo =[QMAX/sin@MAX)], where QMAX is the maximum practical pump displacement per revolution of the drive shaft at the maximum practical swashplate swashplate angle ΘMAX. The other end of the pistons connects to the pump's “A” and “B” hydraulic fluid ports. Depending on whether the swashplate type swashplate angle is positive or negative, “A” will be the output and “B” the input, or “A” will be the input and “B” will be the output, respectively. The swashplate swashplate angle can be controlled by an electric actuator or a hydraulic actuator through a linkage that is connected to the swashplate swashplate. The position of the swashplate type swashplate can be measured by an LVDT (“Linear Variable Differential Transformer”) or a simple potentiometer. In a preferred embodiment, the swashplate-type swashplate angle is dynamically controlled by a drive control module.

[008] Third, the use of a dynamically variable displacement axial piston pump allows instantaneous continuously variable control of the severity of the wellbore toothed leg in the curved sections without having to dispense excess high pressure fluid back into the tank . For tools that use the drilling mud and pressure drop across the bit to actuate the driving control surfaces, actuation is typically all or none. In these cases, it is not possible to partially actuate the drill deflection. By allowing partial actuation of bit deflection, a finer granularity of driving adjustment can be achieved and maintained while drilling.

[009] The second invention disclosed in this document relates to a hinge joint that limits the articulation of the drill bit in relation to the tool to a single degree of freedom. As will be explained in the discussion that follows, limiting the drill pivot to a single degree of freedom with respect to a fixed point on the tool, and using the method of spatially phased coherent symmetrical bidirectional deflections with respect to fixed ground information, to control the drilling direction, allows the use of a single axis hinge instead of a two degrees of freedom universal joint to attach the bit to the bottom of the swivel driven drill tool. The innovative method that is required to drive the well and fully benefit from the simplified mechanics of the innovative rotary steerable drilling tool is called “spatially phased coherent symmetrical bidirectional deflection” of the bit. This will be explained in greater detail later in this reveal. The hinge limits drill movement to a single degree of freedom. However, two degrees of freedom are required in order to drive a well toward an intended target. In the invention of this disclosure, the second degree of freedom is provided by rotating the rotatable driveable drilling tool while drilling.

[010] A BHA or “downhole assembly” describes the lower or bottom section of the drill string that ends with the bit and extends in the hole upwards to the point just below the lower end of the drill pipe. In addition to the bit, the BHA may be comprised of any number of drill collars for added weight or special purpose collars which may or may not be included, such as, but not limited to: outriggers, down reamers, positive displacement mud motors, right angle installations, instrumented drill collars for the measurement of various formations and environmental parameters (for the determination, versus depth and time, of the mixing and volume of fluids in the formation or formation lithology or formation and mechanical properties of unfinished hole or slope and unfinished pit azimuth), or rotary driven tools, such as the topic of this disclosure. The components that are part of a given BHA are selected to optimize drilling and placement efficiency and borehole geometry.

[011] The timing or spatial phasing of the drill deflections is controlled in such a way that, for an observer who is stationary with respect to the earth, the drill is oscillatingly deflected in the same direction for every 180° of BHA rotation. On the other hand, for an observer who rotates with the tool, i.e., is stationary relative to the tool, for every 360 degree rotation of the tool, a positive drill deflection will be seen towards a fixed reference mark (a “ guideline") followed by a negative drill deflection away from the guideline datum mark, the two deflection events separated by 180° of tool rotation.

[012] Other benefits of using a single degree of freedom of articulation relative to a fixed point on the collar will be explained further in the disclosure that follows. While not a preferred embodiment of the invention, it should be understood that a hydraulic dynamically variable displacement pump could also be used to control downhole tools other than the rotary drive tool described above, which includes, but is not limited to, a more with multiple actuators and a pivot with multiple degrees of freedom of articulation to continuously maintain a bit pivot angle in a particular direction that is fixed relative to the earth or to control the counter-rotating scalar speed of a geostationary assembly to maintain an orientation fixed position of the geostationary mount relative to the earth as the tool rotates.

SUMMARY OF THE INVENTION

[013] An object of one aspect of the present invention is to provide an innovative dynamically controlled rotary driven drilling tool connected by wires to a rotary drive component such as the output shaft of a mud motor or a rotary drill string is driven by a turntable or top drive of a drilling rig, which enables directional drilling of selected borehole sections, either curved or straight, accurately driving the borehole towards an underground target. The rotary driveable drill tool will have the ability to drill out of the casing shoe, drill the bend and drain hole to depth and achieve “range” with the specified inclination and azimuth, in a single drill run, which minimizes rig time to complete the well.

[014] One problem that this aspect of the present invention seeks to address is to minimize the mechanical complexity of a dynamically controlled rotary driveable drilling tool. In a preferred embodiment, this is accomplished using the simplest pivotal attachment of the drill assembly to the lower end of the swivel steerable drill collar, namely, a single hinge. The drill assembly includes the drill attached to the bottom end of a pivot drill shaft. Affixing the upper end of the drill shaft to the drill collar via a single hinge joint limits the drill mount pivot to a single degree of freedom with respect to a reference coordinate system attached to and rotating with the collar rotary drive drilling machine (the “tool coordination system”). During active driving operations, the long axis of the drill assembly is oscillating, bidirectional, and symmetrical offset at the same frequency as rotation of the rotatable steerable drill collar via a single bidirectional actuator that rotates with the steerable drill collar swivel. Further mechanical simplification can be derived from the computational deployment of a 9-axis virtual geostationary navigational platform comprised of sensors that are packaged in a physical chamber that is attached to and rotates with the rotatable driveable drill collar, thereby eliminating any stationary and/or quasi-stationary mechanical assembly or apparatus which counter-rotates relative to the rotatable steerable drill collar but is otherwise a part of the rotatable steerable BHA. Eliminating the need for a geostationary and/or quasi-stationary mechanical assembly eliminates the complementary need for rotating electrical connections (eg slip rings), pressure seals and bearings.

[015] A difference between the above-described embodiment of the rotary steerable drilling tool apparatus disclosed herein and other rotary steerable drilling tools is that a bidirectionally oscillating drill shaft is mechanically connected to the bottom of the rotary steerable drilling collar by means of of a single-axis hinge that transmits torque and weight from the rotatable driveable drill collar to the drill shaft and drill bit. This design contrasts with the more complex affixation and actuation mechanics that are required to sustain two or more degrees of articulation freedom for tools that continuously point the bit in a given direction with respect to ground information as the rotary driveable tool rotates, for example, splined ball joints, CV joints or universal joints with multiple independent actuators. For push-drill tools that continually off-center the drill in a given direction, multiple actuators and/or control surfaces are required, and the ability to maintain off-center drill location while drilling can be restricted by the number and placement of configured actuators.

[016] The method of conducting a well in a particular direction with respect to gravity or magnetic north is performed by controlling the spatial phasing of said coherent symmetric oscillating deflections of said drill axis with respect to both the gravity tool face ( GTF) as a magnetic tool face (MTF) as the tool rotates. (An instantaneous GTF of zero degrees corresponds to the point when a reference mark on the tool, known as a “guideline,” is oriented toward the top of the unfinished hole. An instantaneous GTF of 180° corresponds to the point when the line- guide is oriented toward the bottom of the unfinished hole. Similar to MTF, an instantaneous MTF of zero degrees corresponds to the point when the guideline is oriented toward magnetic north; and an instantaneous 180° MTF corresponds to the point when the guideline is oriented towards magnetic south. In the case of a perfectly vertical unfinished well, the value of GTF is undetermined. And similarly for the MTF, in the case where the unfinished well azimuth is due to north or south and the slope of the unfinished hole is equal to the local inclination angle in degrees of the earth's magnetic field, so the MTF value is undetermined.) This allows the drill to preferentially remove formation on a particular side of the unfinished hole (“the front end”) while removing less formation on the opposite side of the unfinished well (“the back end”) in order to change the borehole direction towards a target slope and/or azimuth for the purpose of drilling a curved and/or straight borehole progressively towards an intended geometric or geological target or for the active drilling of vertical boreholes. This method allows for an unfinished hole diameter that is slightly enlarged from zero to about 5 percent of the nominal drill diameter in the curved sections, thereby reducing frictional forces and mechanical stress concentrations in the BHA and other tubulars as they slide or rotate through the tine leg, which results in less resistance on the drill string and therefore more weight and torque on the bit while in and under the curve. The slight enlargement of the unfinished hole during driving operations while drilling a curved section is a direct result of the driving movement of the bit while the tool is rotating. This will be explained in detail in the discussion of Figures 7C and 7D, below. Drill deflection during driving operations increases the effective cutting diameter of the drill by a few percent in the preferred driving direction. While additional material is preferentially being removed from the “front end” of the hole in the direction the tool is being driven, less material is being removed from the “back end” of the hole, which results in a hole path curved with a slightly enlarged unfinished pit diameter. Another advantage of the innovative method disclosed herein is that during driving operations, while in the turn, additional mechanical cutting power is being added to the bit as it drills. This is due to the additional motion imparted to the bit as a result of driving operations. Other methods that maintain a constant off-center or angular orientation of the drill bit as the tool rotates do not add any additional cutting power to the bit. In practical terms, the additional mechanical cutting power provided to the bit 12 results in faster drilling on the curve and higher overall drilling efficiency.

[017] Using the method of spatially phased coherent symmetrical oscillating movements of the drill to drill in a directional manner is in direct contrast to traditional point drill systems that continuously maintain a given offset angle of the drill axis of rotation relative to the axis of BHA rotation and fixed ground information that is independent of rotation of the rotary steerable drill tool as the collar is rotating during driving operations, requiring mechanical articulation and actuation with two or more degrees of freedom. Additionally, the use of spatially phased spatially coherent bidirectional symmetrical oscillating deflections of the drill is in direct contrast to traditional push drill systems that continuously maintain a constant parallel lateral offset of the drill axis of rotation relative to the axis of rotation of the BHA and fixed ground information that is independent of rotation of the rotary driveable drill tool as the collar is rotating during drive operations, requiring mechanical actuation with two or more degrees of freedom to continuously generate lateral offset forces in a given direction.

[018] Some embodiments of the invention use a drilling mud-fed dynamically variable displacement axis piston pump that regulates the variable input power and/or float available from a turbine driven by drilling mud and also regulates the output flow rate of pressurized hydraulic fluid to the load in response to the power demands of the drive drive actuators to instantaneously and continuously control the deflection force and deflection amplitude of coherent symmetrical bidirectional oscillations of the drill shaft and drill bit. The term "pusher unit" describes that section of the rotatable drive tool that "pushes" or drives the tool in a given direction. The driving unit is comprised of the drill, actuation and control means for offsetting or pivoting the drill, a collar, optionally one or more centralizers and a power source. The pump output drives a single bidirectional hydraulic piston with a force axis that is oriented orthogonally to both the hinge axis and the BHA axis of rotation, which actuates so-called spatially phased coherent symmetrical oscillations of the axis of rotation. auger and auger for the purpose of driving the borehole in said selected direction. During active driving operations, the dynamically variable displacement axial piston pump enables continuously variable control of the amplitude of said coherent symmetrical oscillating deflections of said drill assembly in order to control the tine leg severity (bending rate) of said drill assembly. changing direction of the borehole and to dynamically control the lateral driving forces applied to the bit responsive to the mechanical properties of the formation, the cutting dynamics and bit health, the perceived ineptitude of discontinuous slip rotation (stick slip) and /or to allow discontinuous slip (stick slip) rotation up to some predefined limit.

[019] In one embodiment of the tool, the amplitude and spatial phasing of said coherent drill oscillations are controlled by an onboard borehole tool microcontroller and/or microprocessor assembly. This assembly may have variant configurations that may include a microcontroller and/or microprocessor, memory, non-volatile memory, input/output channels, various navigational sensors, and/or stored-to-memory programming that the assembly executes when in operation. The downhole tool microcontroller and/or microprocessor assembly generates the driving control signals in response to either surface generated commands or autonomous algorithmic commands derived from acquired downhole navigational parameters, or a combination of the same. In this way, the rotatable drivable drilling tool of this invention is dynamically adjustable while the tool is located in the borehole and during drilling to controllably change the inclination and azimuth of the borehole path as desired. The spatial phasing of said coherent oscillations is dependently controlled, separate from the amplitude of the oscillations, as it rotates to progressively drill the wellbore in a given direction. On the other hand, the amplitude of said oscillations can be dynamically adjusted independently of the spatial phasing of said oscillations, to continuously and progressively increase or decrease the rate of curvature of the wellbore to achieve the intended downhole trajectory and to optimize quality. and smoothness of borehole. In one embodiment of the present invention, during driving operations, the duty cycle of each of the individual valves that operate the hydraulic actuator is 50%, that is, the time of each valve is approximately equal to the pause time. Also, the valves are out of phase with each other. While one valve is ON, the other valve is OFF. While one valve is transitioning from OFF to ON, the other valve is transitioning from ON to OFF. As the tool rotates, the timing of the valve control signals relative to the GTF or MTF controls the spatial direction the tool is drilling, but not the amplitude of the bit pivots. Instead, controlling the swashplate-type swashplate angle of the dynamically variable displacement axial piston pump controls the amplitude of the drill joints. This method of independently controlling the range of the joints separately from the timing of the drill joints as the tool is rotating results in a smooth, repeatable resultant drill movement regardless of the range of the joints. This method should be contrasted with the method disclosed by Bradley which will result in sudden and compact drill movements as the tool attempts to maintain a constant drill offset angle in a constant direction relative to the axis of rotation of the tool. Bradley reveals varying the duty cycle of the individual valves that operate each of the hydraulic actuators to control the amplitude of the drill linkages simultaneously with controlling the timing of each valve turning on and off to control the direction the tool is drilling.

[020] Rotary drilling tools can rely on accelerometers, magnetometers and gyroscopes to provide navigational information for driving underground wells for oil and gas production or water and/or steam injection. These navigational sensors can be packaged within a secondary mount within the rotatable driveable drill tool that rotates counter to the drill collar so that the sensors maintain a stationary relationship to the earth, commonly referred to as a “geostationary platform”. . However, the concept of a counter-rotating geostationary platform brings with it additional mechanical complexity in terms of seals, bearings and slip rings, as well as a means of controlling and maintaining counter-rotation with variable BHA rotation rates and the significant mechanical inertia of the geostationary platform. Bradley in US 3,743,034 suggests using an "inertial reference" mounted directly to a camera on the rotary drill collar - in this case, "a reference, such as the center of a gimbal (sic) gyroscopic platform", packaged inside the tool pivot section located below the universal joint connection - to determine which direction the bit is pointing. An “inert reference” is, by definition, a non-rotating or geostationary reference. Thus, by gimbal mounting the gyroscope in a rotating housing, the gyroscope is in fact a geostationary reference that maintains a constant orientation of the gyroscope platform relative to the earth by the angular momentum of the gyroscope.

[021] In one embodiment of the present invention, accelerometers and magnetometers are packaged in and rotate with the tool comprising a "non-inertial rotating navigational platform." A benefit of relying on a rotating navigational platform rather than a geostationary inertial navigational platform is that physical mounting alignment errors of navigational sensors, specifically accelerometers and magnetometers, can be minimized or canceled out to improve measurement accuracy, with the result that result that the placement of the unfinished pit will be as intended by the customer. There are at least two sources of mechanical misalignment errors when using accelerometers and magnetometers. The first is the misalignment of the device within its package, and the second is the misalignment of the package mounting to a PC board or chassis in the tool. Mechanical misalignment errors affect the relative orthogonality of each of the sensitivity sensors' geometric axes. Accelerometers can be additionally affected by centripetal effects when not mounted exactly on the axis of the rotation tool. For some dual axis microelectric and micromechanical (“MEMS”) systems, the relative orthogonality of the geometric axes is determined by the lithographic process used to manufacture the device, which results in near perfect orthogonality, thereby virtually eliminating a source of error when compared to orthogonally mounted single axis devices. Errors caused by misalignment can be important both when you are actively drilling a vertical hole and the slope (slope) of the unfinished well is by definition very close to zero degrees, and when the slope of the unfinished well is close to horizontal. When actively drilling a vertical well, the slope is typically specified as within about 1 degree of vertical. For example, for a target depth of 3048 m (10,000 ft), the bottom of the vertical downhole section should not have laterally deviated more than 53.34 m (175 ft) in any direction relative to the drill rig on the surface or at the point of underwater entry to the seabed. For transverse magnetic field gravity measurements made with a rotational navigational platform, the misalignment and electrical compensation errors occur in DC while the measurements of interest have the same AC frequency as the rate of rotation of the tool. Additionally, any differences in gain and sensitivity between the two orthogonal transverse channels caused by setup misalignment can be easily dynamically corrected by normalizing the amplitude of the AC measurements from one channel to the other to improve measurement accuracy. In addition, for transverse magnetic field measurement, there will be a small correction needed to compensate for the AC electromagnetic film effect which is proportional to the rotational frequency. The phase correction could be as much as 15° and the amplitude correction could be as much as 2.6 dB. The effect is repeatable and can be empirically derived as a function of frequency and temperature. For axial gravity and magnetic field measurements made with a rotational navigation platform, misalignment errors occur at a frequency equal to the rate of rotation of the tool. The amplitude of the AC error signal will provide a quantitative indication of axial misalignment to allow a small correction factor to be applied to the DC component of the measurement. Proper low-pass filtering of the AC error signals will remove the error. For the axial magnetic signal, no compensation for the electromagnetic film effect is needed since the axial magnetic field component is at DC whether the collar is rotating or not. However, using a rotational navigation platform does not eliminate the need for DC compensation and thermal gain characterization for axial devices and thermal gain characterization for transverse devices.

[022] Assume, for example, in a vertical well that is drilled with a geostationary navigational rig, that the x, y, and z accelerometers are each misaligned by some arbitrary small angle in an arbitrary direction with respect to a Cartesian coordinate system fixed to the tool. So when doing a static survey, which can take several minutes to acquire, the misalignment of the accelerometers to the tool axis will affect the accuracy of the survey and will introduce a source of error within the borehole path unless it is calibrated and accounted for. Consider that accelerometers are typically mounted orthogonally to each other relative to a Cartesian coordinate system that rotates with the tool, with the z axis oriented so that it points into the borehole toward the bit along the axis. BHA rotation. Two other transverse geometric axes are identified as “x” and “y” and form a right coordination system with “z” in such a way that ix crossed with iy is equal to iz, where ix, iy and iz are the vectors of units that correspond to their respective Cartesian geometric axes attached to the tool. While rotating, misalignment error behaves differently for x & y transverse sensors than it does for z axis sensors. For transverse sensors, the primary sensitivity is orthogonal to the axis of rotation which yields an AC signal with a frequency equal to the rotation frequency and an amplitude proportional to the value of the unfinished well slope angle. The transverse misalignment error yields a small vector sensitivity in the z direction along the tool geometry axis. Therefore, the transverse sensor error response caused by misalignment is independent of tool rotation, i.e. it is DC compensation. When using superimposition, the transverse sensor signal is the primary AC signal with a small DC offset superimposed on it. For axial sensors, the conversion is true, the misalignment error yields a small transverse vector sensitivity to the tool axis. When using superimposed, the total axial sensor signal is the primary DC signal which is proportional to the earth's gravity times the cosine of the slope angle plus a small AC misalignment error signal superimposed on it. However, the misalignment error of an axial sensor is simply canceled out by averaging the samples over an integral number of BHA rotations.

[023] In the case of a vertical wellbore such that the z axis of the tool is precisely aligned with the earth's gravity vector, that is, when the slope angle is zero degrees, the transverse accelerometers of x and y do not will have no AC component, just a small DC sensor offset. When the AC amplitude of the transverse accelerometers is zero, this confirms that the borehole is vertical. When the unfinished well begins to deviate away from the vertical direction, that is, when the unfinished well begins to slope, the AC amplitude of the x and y transverse accelerometers begins to increase, with the amplitude proportional to the amount of slope. The axially oriented z-axis accelerometer measures the cosine of the slope angle times the earth's gravity, and since the cosine of the slope angle is somewhat insensitive to small changes in slope angle when the axial accelerometer is aligned with the gravity vector earth, it is not suitable for vertical drilling control. In practice, for the case where the rotational tool axis is downhill at some angle with respect to the earth's gravity vector, transverse accelerometers can be used dynamically to quantify the unfinished borehole slope up to about 75° of tilt angle using the fundamental frequency amplitude of the AC signal from the transverse accelerometers. Above about 75°, the DC signal from the “z axis” accelerometer should be used for a dynamic unfinished hole slope measurement.

[024] When using accelerometers dynamically at the BHA rotation rate, Gaussian noise reduction techniques are used to lessen the acceleration effects caused by shocks and random vibrations. For best results, the frequency response of navigational accelerometers should be band-limited by device physics so that the device is inherently insensitive to high-frequency shocks and vibrations which can be large, which saturate the device outside of the frequency band. of interest, which affects the accuracy of the device in the band of interest. The "frequency band of interest" is typically understood to mean average frequencies below about 2 to 3 times the maximum rotation rate of the BHA. Additionally, proper device selection will minimize the effects of vibration rectification, which allows full noise filtering benefits to be realized for robust computation of unfinished hole downhill inclination, unfinished hole downhill azimuth, and the instantaneous GTF and MTF of the tool.

[025] One embodiment of the present invention relies on a completely autonomous virtual geostationary platform with self-correction and self-calibration measurements to generate the signals and timing required to dynamically drive the rotary steerable drilling tool in a desired direction relative to ground information or a a target. Three orthogonal accelerometers, three orthogonal magnetometers, and three orthogonal rate gyroscopes are arranged in the tool to cover a wide range of drilling conditions, inclined borehole angles, and cases where the earth's magnetic field is distorted by nearby well casings. or if the borehole path runs north-south or south-north and the downhill slope of the borehole is within a few degrees of matching the local degree slope angle of the earth's magnetic field. These 9 geometry axes are dynamically blended over a wide range of BHA rotation rates from zero RPM to several hundred RPM. The “geostationary” emissions from the rotating virtual geostationary platform are unfinished well downhill slope and unfinished well downhill azimuth. The instantaneous or dynamic emissions are GTF, MTF, the local angle between GTF and MTF (Angle X), and the instantaneous rotation frequency. These 6 emissions are used to control the timing of the actuators that dynamically deflect the bit and cause the rotating tool to drive the well in a particular direction that is fixed relative to the earth.

[026] In one embodiment, the virtual geostationary platform may include a separate virtual geostationary platform (“VGPMA”) microcontroller and/or microprocessor assembly, or it may use the microcontroller and/or microprocessor assembly of another system, such as that of the rotatable drive mount as described above. The VGPMA, if configured, can have varying configurations that can include a microcontroller and/or microprocessor, memory, non-volatile memory, input/output channels, various sensors, and/or programming stored in memory that the assembly executes when in operation. Additionally, as discussed in the paragraph above, the virtual geostationary platform can be configured with sensors that include: three orthogonal accelerometers, three orthogonal magnetometers, and three orthogonal rate gyroscopes, all of which provide input (or inputs) to the VGPMA or surrogate processing system , such as that of the rotatable drive mount. The system processing this sensor input data then processes this information to calculate location and determine any potential misalignment errors. Optionally, sensor data and/or other data can be logged to memory.

[027] Rate-referenced gyroscopes in this modality are not used for inertial navigation; they are not the north seeking gyroscopes that would be needed for inertial guidance or they are gimbal mounted. They measure BHA rotation rates along each geometric axis of the tool coordination system for the determination of parameters pertaining to drilling dynamics and kinematics. The z-axis gyroscope measures the instantaneous rate of rotation of the tool about the z-axis to identify and correct for stick slip movement and magnetic interference zones. The x-axis and y-axis gyroscopes provide an indication of tool movement in response to shock and vibration while drilling. Namely, if the movement of the BHA deflection to shock is translational, then the x and y gyroscopes will not read any relative rotation. However, if the x and y gyroscopes detect a rotational component of BHA motion that correlates to the y-axis and x-axis accelerometers respectively, then this means that the tool's response to shock and vibration includes obliquity and yaw in the bore and that the drive includes a pendulum-type component. This movement could identify a false indication of unfinished hole grade so that it could be properly identified as the tilting tool in the hole and not tilting the hole.

[028] Electronic instrumentation and processing for tool driving control incorporates multiple feedback sensors, navigation sensors, and a microcontroller and/or microprocessor assembly to process the combined inputs from multiple sensors to drive the tool based on the sensor inputs, any pre-programmed control parameters and/or additional control inputs communicated from surface or other downhole systems. In one embodiment, signal acquisition, noise reduction, and dynamic error correcting processing enable accurate real-time computation of instantaneous tool face measurements and BHA rotation rates and geostatic borehole path parameters regardless of the tool is either rotating or static, thereby eliminating the need for a geostationary or quasi-geostationary platform for the navigational sensors, and enabling immediate or instantaneous borehole course corrections without interruption and transparent to the drilling process. Additionally, it is a well-known technique to place two similar measurements separated by a known spacing, e.g., slope, to dynamically compute and monitor instantaneous sprocket severity so that preventive adjustments to the accumulation rate can be made quickly without interrupting rotary drilling and driving operations, and without having to downlink depth and/or ROP information from the surface and without a surface generated command. Additionally or alternatively, strain gauges can be used to determine the severity of tine leg based on the full reverse bending amplitude of the drill collar as it rotates in or through the curved section of the wellbore.

[029] Additionally, in one embodiment, the control instrumentation and electronics of the rotary drilling tool can be combined with a downlink channel from the surface to the downhole tool that allows updating the tool and/or reprogramming the tool from the surface in order to adaptively set or change the desired borehole azimuth and inclination target values while continuing to rotate and/or drive. In addition to the required navigational instrumentation, in one embodiment, the tool may incorporate instrumentation for various formation assessment measurements, such as mean natural gamma ray and/or quadrant detection, multi-depth formation resistivity, neuron density and porosity, sonic porosity, unfinished borehole resistivity imaging, look-ahead and look-around detection, an ultrasonic caliper measurement of borehole diameter, and drilling mechanics. Electronic non-volatile memory, in one embodiment of the tool's on-board electronics, has the ability to record and hold and/or record and transmit, or simply transmit in real time or on a delay using temporary storage memory, a complete set of borehole surveys and other data to enable geological guidance capability so the rotary steerable drilling tool can be effectively deployed to drill all sections of the well within a given diameter. When located below a positive displacement mud motor, real-time data from the rotary drive tool can be monitored by wireless short range telemetry to a suitable remote receiver tool located above the mud motor and then monitored. by surface telemetry via mud pulse, electromagnetic (“EM”) or other telemetry as may become available. In one embodiment, the electrical power for control and operation of the solenoid valves and instrumentation, acquisition, and short range telemetry electronics is provided by wellbore batteries, or a turbine slurry feed alternator, or a combination of the two. Additionally, the system can be powered by other downhole power generation systems.

BRIEF DESCRIPTION OF THE DRAWINGS

[030] Figure 1 illustrates a perspective side view of an implemented rotary drill string that has a downhole assembly (“BHA”).

[031] Figures 2A and 2B illustrate an embodiment of a rotatable driven drilling tool and show two orthogonal side views of the drill attachment to the rotary driven drilling tool.

[032] Figure 2C illustrates an embodiment of the drill bit of the rotary driven drilling tool shown in Figures 2A and 2B from the perspective of an observer looking towards the unfinished hole drill above and defines a Cartesian coordinate system for reference .

[033] Figures 3A-1, 3B-1, 3C-1 and 3D-1 illustrate an embodiment of a swivel driven drilling tool and show a sequence of orthogonal side views of the drill attachment to the custom swivel steerable drilling tool that the tool is dynamically reducing the angle.

[034] Figures 3A-2, 3B-2, 3C-2, and 3D-2 illustrate an embodiment of a rotary driven drilling tool and show the drill bit of the rotary driven drilling tool shown in Figures 3A-1, 3B-1, 3C1 and 3D-1 respectively from the perspective of an observer looking towards the bit from the inside of the well and defining a Cartesian coordinate system for reference

[035] Figures 4A to 4B show a cutaway side perspective view illustrating the internal structure of an embodiment of the rotary driveable drilling tool and show two views of the oscillating movement of the drill and drill axis.

[036] Figure 5 shows an enlarged section of the lever arm actuator of the rotary driveable drilling tool shown in Figures 4A to 4B.

[037] Figures 6A to 6B show a side perspective view illustrating the internal structure of an embodiment of the rotary driving drilling tool and show two views of the operation of the lever arm locking mechanism that is used to lock the drill in the centered position when driving operations are not active. Figure 6A is locked. Figure 6B is unlocked.

[038] Figures 7A to 7D illustrate an embodiment to actuate the bit of a rotating drilling tool.

[039] Figures 8A to 8D illustrate an embodiment of the navigation module for the virtual geostationary platform.

[040] Figure 9 illustrates a perspective side view of a rotary driven tool string implemented that has a downhole assembly (“BHA”) configured with a virtual geostationary platform.

[041] Figure 10 illustrates another application for drilling oil and gas wells and shows an embodiment in which an output of a dynamically variable displacement axial piston pump can be connected by a hydraulic line to a hydraulic motor, the which thereby forms a hydraulic transmission.

[042] Figures 11A to 11B illustrate yet another application mode in which an output shaft of a hydraulic motor can be configured to drive a rotary mud valve for generating mud pulse telemetry.

[043] Figure 12 illustrates an application of the dynamically variable displacement axial piston pump in a closed-loop reversible hydraulic system for cutting sidewall cores.

[044] Figure 13 shows the prior technique used to drive a claw-type coupling pump for sampling formation fluid.

[045] Figure 14 shows an embodiment that uses a dynamically variable displacement axial piston pump in a closed-loop configuration to control and drive a claw-type coupling pump.

DETAILED DESCRIPTION OF THE PREFERRED MODALITIES

[046] Referring to Figure 1, a well hole 10 is shown being drilled by a rotary drill bit 12 that is connected to the lower end of a drill string 14 that extends upwards to the surface on which it is driven by the turntable 16 or a top drive 6 of a typical drill rig 8. The drill string 14 typically is comprised of sections of drill pipe 18 connected to a downhole assembly (BHA) 28 having one or plus drill collars 20 connected thereto for the purpose of applying weight to the drill bit 12. The borehole 10 of Figure 1 is shown as having a vertical or substantially vertical upper section 22 and an offset, curved or horizontal lower section 24 being drilled under the active control of the rotatable driveable drilling tool shown generally at 26 which is constructed in accordance with one aspect of the present invention. As will be described in detail below, the rotatable steerable drilling tool 26 is constructed and arranged to cause the drill bit 12 to drill along a curved path that is designated by the control settings of the rotary steerable drilling tool 26 in accordance with with the principles set out in this document. Drilling mud is pumped into the drill string 14, flows through the BHA 28 and out of jets in the bit 12, and returns to the surface with the drill cuttings at the annulus 30. The BHA 28 includes an attached drill bit 12 directly to the bottom of the actively controlled rotary driveable drilling tool 26. The BHA may also include other drilling tools, such as positive displacement mud motors to control rotational speed and torque, and thrusters to control weight on the bit. Furthermore, the arrangement of these components within a drill string can be selected by drilling personnel based on their experience and preferences according to a wide variety of drilling characteristics, such as the turning radius of the curved borehole section. that is drilled, the characteristics of the formation that is drilled, the characteristics of the drilling equipment that is employed for drilling, and the depth to which drilling is taking place. Since the number of possible combinations and permutations of these other necklaces is large, they will not be enumerated in this disclosure. Suffice it to say that the placement and arrangement of these additional components on the drill string in relation to the actively controlled rotary steerable drill tool 26 is unsupported by the construction and operating principles of the present invention.

[047] Figures 2A and 2B illustrate an embodiment of the rotatable drilling tool 26 (“RSDT”) and show two orthogonal side views of the drill attachment 12 to the RSDT. A fixed reference point on the RSDT, called a guideline 7, may or may not be visibly marked on the RSDT drill collar. Visibly marked or not, the guideline is fixed relative to and rotates with the mechanical and electronic features of the rotary steerable drilling tool and serves as a spatial reference point for calculations performed by the guidance system. For this discussion, it will be helpful to define a three-dimensional reference Cartesian coordinate system, shown in Figure 2C, from the perspective of an observer looking downhole toward the drill bit, which is attached to and rotates with the rotary steerable drill tool. . The origin 203 of the reference Cartesian coordinate system is the intersection point of the centerline 50 of the RSDT and the geometric x and y axes. The x axis 204 passes through the origin 203 and orthogonally intersects the guideline 7. The y axis 205 is orthogonal to the x axis and parallel to the axis of hinge 5 of hinge 3. Consistent with industry standard nomenclature, the z-axis 206 shown in Figures 2A and 2B, is collinear with RSDT centerline 50 and is positive in the downhole direction with increasing measured depth and negative in the uphole direction with decreasing measured depth. The polarity of the y axis 205 is chosen such that the x, y, & z axis always form a right coordinate system. The unit vectors Ix, Iy, and Iz satisfy the following vector product relations: Ix (x) Iy = Iz; Iy (x) Iz = Ix; and Iz(x) Ix = Iy. Referring to Figure 2A, one can define a straight line segment parallel to the x axis that extends from and is perpendicular to RSDT centerline 50 and terminates at guideline 7, which forms a vector of tool orientation 60. When the tool is rotating in a borehole that is not vertical to the earth's gravitational field, the instantaneous GTF of the RSDT is said to be "0°" or "up" when the vertical component of the vector tool orientation 60 is pointing in a direction opposite to the earth's gravity vector. On the other hand, when the tool is rotating in a borehole that is not vertical to the earth's gravitational field, the instantaneous GTF of the RSDT is said to be "180°" or "down" when the vertical component of the Tool orientation 60 is pointing in the same direction as the earth's gravity vector.

[048] Referring again to Figure 2C, it is useful to define a cylindrical tool coordination system that is attached to and rotates with the rotatable driving drilling tool. The z axis 206 remains the same as defined for the 3D Cartesian coordinate system. Viewing the AA cross-sectional view in Figure 2A, the x and y geometric axes are replaced by radius r 210 and angle θ (theta) 212. When describing a point on the tool, its radius “r” is equal to (x2 + y2) 1/2. The angle θ is defined relative to guideline 7 and is zero degrees on the guideline and positive in the clockwise direction when viewed looking in the +z direction in the downhole direction.

[049] Referring to the embodiment of the RSDT illustrated in both Figures 2A and 2B, the drill assembly is attached to the bottom end of the RSDT by means of a hinge of a single axis hinge assembly 5, comprised of a yoke 41 which is preferably integral with the collar of the rotatable drilling tool 43, the drill shaft 33 which screws into the drill 12 at its lower end and joins the yoke 41 at its upper end, and a hinge pin 37 which fits into the yoke 41 and the upper end of the drill shaft 33. As shown in both Figures 2A and 2B, the orientation of the hinge pin 37 is parallel to the y axis 205 of the Cartesian tool reference coordinate system, the which makes it perpendicular to both tool orientation vector 60 and centerline 50 of the RSDT. The tool orientation vector 60 would be in the 0° direction in the cylindrical tool coordination system. The hinge 5 allows the drill shaft 33 to pivot with a single degree of freedom with respect to the swivel steerable drilling tool collar 43 about the axis of the hinge 5 of the hinge 3.

[050] This is in contrast to point-drill systems that employ multi-degree-of-freedom omnidirectional pivots or universal joints such that the deflection of the drill can be held constant relative to a geostationary coordination system (a coordination system that does not rotate with the tool, but is referenced to earth) as the tool rotates. As will be discussed in more detail below, changing the direction of the borehole in a particular direction using this aspect of the present invention is accomplished by the spatially phased coherent symmetrical bi-directional oscillations of the drill shaft 33 and drill bit 12 as the Actively controlled RSDT rotates.

[051] A pair of stabilizing blades 35 can be either integral with or welded to the drill shaft 33 at θ212 = 0° and 180° to the drill shaft, which extends above the hinge pin 37 to improve the ability to conducting the RSDT. Additionally, it may be helpful to add a pair of full gauge stabilizing blades just above the drill with the blades centered at θ212 = 90° and 270° to further improve the driving ability of the RSDT. One or more fixed stabilizing blades 39 can be positioned and mounted on the outer diameter of the RSDT collar 43 above the hinge as needed for stability and BHA driveability. The stabilizing blades 39 may be straight bladed or curved bladed, cylindrical or watermelon shaped, consistent with the intended buildup rates and downhole drilling characteristics desired by the drilling personnel.

[052] The “photographs” of the tool in Figures 3A through 3D show a sequence of views from 4 sides and from the rising end as the RSDT is being rotated and driven into the scenario where the wellbore is reducing the angle, that is, the “front end” of the curve is down. The drill collar above the hinge is identified 43 and rotates on the tool centerline 50. The instantaneous GTF orientation of the tool in each Figure is identified by the location of the guideline 7 and the tool orientation vector 60. For clarity, drill shaft deflection is exaggerated and stabilizing blades are not shown.

[053] The direction of rotation in each figure is clockwise when viewed from the surface and is shown by the curved arrows that are identified with the symbol “W” (omega). As the RSDT rotates, the drill spindle 33 and the drill 12 offset relative to the tool centerline 50. For convenience, the geometry axes of the tool reference Cartesian coordinate system are superimposed on each photo. The z axis 206 is collinear with the tool centerline 50. Both the x axis 204 and the y axis 205 are transverse to the tool centerline 50. For this discussion, the origin of the reference coordinate system 203 is shown at the intersection of the z axis 206, the x axis 204, and the hinge axis of hinge 3. The hinge axis of hinge 3 is collinear with the hinge axis 203. y-axis 205. The deflection of the drill relative to the centerline 50 of the RSDT rotation is identified by the Greek letter delta (δ), which is the angle formed by the long axis 85 of the drill axis 33 and the centerline 50 from RSDT. Said angle convention δ is negative when the drill axis 33 deviates away from the guideline 7 and is positive when the drill axis 33 deviates towards the guideline 7. The GTF angles 0°, 90°, 180° and 270° are identified in the bottom end view in each Figure. These angles are fixed with respect to the earth's gravity vector and do not rotate with the tool.

[054] In Figure 3A, the guideline 7 is “up” and the GTF is 0°. In Figure 3C, guideline 7 is “down” and the GTF is 180°. The "right" and "left" directions are defined from the driller's perspective, as opposed to the end views shown in Figures 3B and 3D. In Figure 3B, guideline 7 is at 90°. A GTF equal to 90° is termed “right” as drill deflections in that direction will cause the unfinished hole to make a right turn. Similarly, for Figure 3D, guideline 7 is at 270°, which is termed “left” as drill deflections in that direction will cause the unfinished hole to make a left turn. Figure 3A shows the long axis 85 of the drill axis 33 offset away from the guideline 7 by some negative angle δ, but since the guideline GTF is 0°, the drill bit 12 preferentially removes the material on the underside of the hole. The photograph in Figure 3C is taken after the RSDT has rotated 180° from its orientation in the photograph in Figure 3A and shows the long axis 85 of the drill shaft 33 offset towards the guideline 7 by some positive angle δ, however since the guideline GTF is 180° (which points downwards), the drill bit 12 again preferably removes material on the low side of the hole.

[055] The photographs in Figures 3B and 3D show the long axis 85 of the drill shaft 33 aligned to the centerline 50 of the RSDT. In this position, the drill 12 makes momentary contact with the “back” diameter of the hole and therefore removes less material from the “back” diameter of the hole during driving operations than it normally would when drilling. When driving is activated and the RSDT is rotating, this symmetric oscillating movement of the bit 12 at the same frequency as the rotation of the BHA, phased synchronously with respect to the spatial direction in which the borehole is being driven is a unique aspect of the method and apparatus of the present invention.

[056] In one embodiment of the RSDT, the oscillating movements of the drill 12 and drill shaft 33 can be actuated by the mechanism shown in Figures 4A and 4B. A lever arm 87 is affixed to the drill shaft 33 at the hinge 5 by a lower extension 121 of the lever arm 87 which engages a centerline hole through the middle of the drill shaft 33 that is orthogonal to the axis of pivot hinge pin 3. An elastomeric mud seal 91 on this connection is provided to prevent drilling fluid from escaping around lever arm extension 121 as it engages hinge 5. Lever arm extension 121 includes its own centerline hole which is tapped to the centerline hole in the drill spindle 33 to allow the passage of drilling mud to reach the bit 12 and the nozzles in the bit. In this embodiment, the lever arm 87 is comprised of two parallel rails and numerous spacers and fasteners that are attached to the lower end extension 121. In Figure 4A, as the lever arm 87 is angularly displaced towards the line- guide 7, drill 12 and drill shaft 33 will angularly move in the opposite direction away from guide line 7 through the action of hinge 5. On the other hand, in Figure 4B, as lever arm 87 is angularly displaced away from the guideline 7, the drill 12 and the drill shaft 33 will angularly displace in the opposite direction towards the guideline 7 through the action of the hinge 5. In this embodiment, the displacement lever arm angle 87 is actuated by a servo hydraulic piston assembly 95, although other means may be used, such as an axial servo hydraulic piston with a linkage, an electric actuator with or without a linkage, or a drilling mud piston . Such variations are within the scope of this invention. The angular displacement of drill 12 is equal and opposite to the angular displacement of lever arm 87 through hinge action. The maximum angular displacement of drill 12 is limited by the maximum angular displacement of lever arm 87 which is limited by the maximum displacement of lever arm actuating servo piston assembly 95.

[057] The embodiment shown in Figures 4A and 4B includes an electronics housing 67 that contains dynamic navigational sensors and acquisition electronics located between the two parallel rails of the lever arm 87. The centerline of the housing is collinear with the line center 50 of collar 43 and fixedly mounted to collar 43 via mechanical brackets 68. Electrical connections are provided via a wire tube 130 running from an upper electronics chamber (not shown) to the lower end of the collar 43. electronics housing 67. The housing rotates with the collar and does not rotate in the opposite direction or oscillate with movements of the lever arm 87. In this mode, no part of the tool, mechanical or electronic, rotates in the opposite direction in relation to the rotation of the RSDT , although such counter-rotation of certain components is not prohibited by this aspect of the present invention.

[058] Figure 5 shows a detailed view of the lever arm 87 that actuates the servo piston assembly 95. This embodiment is shown with two pistons 106 hydraulically connected in parallel to minimize the cross-sectional area presented to the mud flow through the RSDT, to further balance the forces on the pivot attachment 114 to the lever arm 87, and to conveniently pack the assembly within the available volume. A single servo piston may be used provided sufficient actuation force can be achieved given the operating limits of the hydraulic system, namely the maximum flow rate and output pressure while fitting the servo piston within the available volume. There are two upper chambers 105 and two lower chambers 107. The upper chambers 105 are hydraulically connected to the power source via hydraulic swivel 113 and hydraulic piping 109. The lower chambers 107 are hydraulically connected to the power source via hydraulic swivel 115 and hydraulic piping 111. When high pressure hydraulic fluid from pump (not shown) and control valves (not shown) is connected to lower piston chambers 107, and upper piston chambers 105 are connected to tank/reservoir low-pressure hydraulic pump 75 (not shown), then piston assembly housing 95 will move down away from guideline 7 and cause the drill to deflect upward toward guideline 7. On the other hand , when high pressure hydraulic fluid from the pump (not shown) and control valves (not shown) is connected to the upper piston chambers 105 and the lower piston chambers 1 07 are connected to low pressure hydraulic tank/reservoir 75 (not shown), then piston assembly housing 95 will move upwards towards guide line 7 and cause the bit to deflect downward away from the line -guide 7. Once the maximum angular deflection of the drill assembly has been determined in the design, then the placement of the piston assembly 95 relative to hinge axis 3 (Figures 4A and 4B) and the permissible travel of the assembly piston can be selected to limit the corresponding maximum angular displacement of the drill 12.

[059] Figures 6A and 6B, show the operation of the locking mechanism 125 lever arm 87 that can be used to lock the drill in the centered position when driving operations are not active. The lever arm 87 ends with a wedge assembly comprising a mounting bracket 116 and a male wedge 117. A drawer assembly comprises a female drawer 103, a shaft 119, a piston 101 and a spring 99. spring 99 is hydraulically connected to the tank. The high pressure side of the piston 101 is hydraulically connected to the high pressure fluid through a hydraulic channel 123.

[060] Figure 6A shows the case when the conduction is disabled and the wedge 117 is mechanically engaged by the drawer 103 and held in position by the spring 99. This corresponds to the case where the hydraulic system pressure is low, which allows the spring 99 forces female drawer 103 to engage male wedge 117. This mechanically locks lever arm 87 in the centered position and prevents it from moving. Figure 6B shows the case where conduction is enabled. As the hydraulic operating pressure increases, high pressure hydraulic fluid flows through passage 123 retracting piston 101, compressing spring 99, and disengaging female slide 103 from male wedge 117, thereby allowing oscillating movement of lever arm 87.

[061] Figure 6B corresponds to the case where the lever arm 87 is free to move, but is being actively held momentarily in the centered position by the RSDT driving control system in preparation for the start of driving operations . Figures 4A and 4B show the case where active driving is enabled and lever arm 87 is shown in an angularly offset position during active driving operations. If lever arm 87 is not being actively driven by RSDT operation, then lever arm 87 will be in the locked position as shown in Figure 6A. As a precaution, if the hydraulic operating pressure in line 123 drops below the threshold set by spring 99 for any reason, then locking slide 103 engages wedge 117 and returns drill 12 to the locked, centered position.

[062] Figures 7A to 7D show a hydraulic modality to act on drill movements while driving and the method associated with that modality. Figure 7A is a schematic of the RSDT hydraulic system. Power is supplied by a drilling mud-fed turbine 71 mounted on a drive shaft 83, which is connected to a dynamically variable displacement axial piston pump 70, a small charge pump 72 and a small electrical alternator 73. displacement of the dynamically variable displacement axial piston pump 70 is dynamically controlled by means of an axial piston pump actuator 74 which controls the angle of an internal non-rotating swashplate type swashplate with respect to the axis of rotation of the drive shaft . The displacement per revolution of the drive shaft of the dynamically variable displacement axial piston pump 70 is controlled by the angle of the swashplate type swashplate. At zero degrees, pump displacement is essentially zero dc/rev. Maximum pump displacement will be achieved when the swashplate type swash plate is at its maximum allowable angle. A charge pump 72 draws hydraulic fluid from reservoir 75 through an F1 filter and supplies a minimal flow to the dynamically variable displacement axial piston pump 70 through the low pressure inlet line 97. Once primed, the dynamically variable displacement axial piston pump 70 will draw additional fluid from hydraulic reservoir 75 through filter F2 and check valve 78 and low pressure inlet line 97. dynamically variable displacement axial piston pump 70 performs two important functions simultaneously, namely, dynamically regulating the amount of hydraulic power that is supplied to the system from the mud-fed turbine 71, and dynamically regulating the amount of power that is supplied to the lever arm actuating the piston assembly 95 The swashplate-type swashplate angle will be adjusted to compensate for changes in both the scalar speed of rotation of the aci axis and 83 as well as the pump output flow rate 70 required to actuate the driving motion of the bit 12. The drilling mud-fed turbine 71 is designed to handle a practical range of mud flow rates determined by the driller and driller. of drilling. This requires the tool to run at a minimum flow rate and minimum mud weight at full power, which means that with a hypothetical fixed displacement pump, there would be excess power in the maximum flow range and maximum mud weight. Since the axial piston pump 70 is specifically designed for the purpose of regulating input and output power, as the available turbine input power 71 increases, the swashplate type swashplate of the axial piston pump 70 can be required to generate only the power that is demanded by the tool and therefore no excess power will be generated by the axial piston pump 70. Excess power must be dissipated as heat without doing any useful work. As flow rate and/or slurry weight increases, the swashplate swash plate angle dynamically decreases to generate only the power required for any given load. On the discharge or load side of the pump, the hydraulic power required by the load is determined by the BHA rpm and the required amount of auger deflections during driving operations. If the energy demanded by the RSDT dynamically increases, the angle of the swashplate type swashplate will be dynamically increased by the actuator 74 in response to control signals from the drive control processor.

[063] When conduction is disabled, the power required from the pump is mechanical equivalent power of essentially zero watts; and the swashplate swashplate angle of the pump 70 will be close to zero degrees. In this state, valve 86 is OFF and diverts flow from pump 70 through hydraulic line 81 and check valve 80 to tank 75. Valve 86 also connects pressure line 123 to tank 75, so that the lever arm locking mechanism 125 mechanically lock lever arm 87 in the centered position, as piston 101 provides no resistance to spring 99, which forces wedge 103, via shaft 119, into mechanical engagement with drawer lock 117. During the transition time when driving operations are being activated for the first time, the control electronics sends a signal to solenoid 84 of valve 86 which changes it to the “ON” state and sends a signal to the actuator swashplate swashplate swashplate angle 74 to increase swashplate swashplate angle, which causes pump outlet pressure in line 81 to increase which retracts female gate 103 of lever arm locking mechanism 125 into action by pulling piston 101 and compressing spring 99 which retracts shaft 119. At the same time, both valves 90 and 94 will be activated by "ON" signals from solenoids 92 and 96, respectively. This applies the same pressure to both chambers 105 and 107 of lever arm actuating piston assembly 95, hydraulically momentarily locking the lever arm in the center position by the action of check valves 88 and 89 which prevents fluid from hydraulic power to transfer between chambers 105 and 107. Drive movement of the drill begins once timed signals to valve solenoids 92 and 96 alternately open and close valves 90 and 94 as shown by curves 51 and 52 in Figure 7B. (These curves will be explained in the discussion of Figure 7B). A high pressure accumulator 93 is provided to smooth out any transient pressure spikes that may be generated by momentary switching of valves 94 and 90; and together with the check valve 80, to be a local high pressure reservoir to keep the lever arm locking mechanism 125 in the non-latched position until the valve 86 is turned "OFF" which allows the lever arm locking mechanism 125 to lever arm engages gate 103 with wedge 117. In Figure 7A, overpressure relief is provided by relief valves 76 and 77. If the pressure in hydraulic line 81 exceeds the predetermined relief pressure of relief valve 77, the pressure will be relieved by releasing fluid back to the inlet side of the axial piston pump 70 through the check valve 79 and hydraulic line 97. If the pressure in the inlet side of the axial piston pump 70 is too high, it will be relieved. relieved by releasing fluid to tank 75 through relief valve 76.

[064] For a given rate of rotation of input shaft 83, the amplitude of drill deflections is proportional to the angle of the swashplate-type swashplate. This reveals another advantage of the dynamically variable displacement axial piston pump 70, namely, that the amplitude of drill deflections can be dynamically reduced in response to detection of discontinuous (stick slip) rotations of the drill 12 independent of the marking. of valves 90 and 94. As the amplitude is being increased, if the incipience of discontinuous slip (stick slip) rotation is detected, the angle of the swashplate type swashplate can be immediately reduced to alleviate or prevent the condition. discontinuous slide (stick slip type), until the drilling parameters have been changed in response to an uphole drilling mechanics alarm that is transmitted to the surface. Yet another advantage of the axial piston pump 70 is that the driving operations can be gradually phased in and out to avoid ridges forming in the unfinished pit wall. By slowly increasing the swashplate-type swashplate angle of the dynamically variable displacement axial piston pump 70, the RSDT will smoothly migrate from a straight orifice section to a curved orifice section by inversely feathering the amplitude of the drill 12 deflects in a controlled manner. When it is time to suspend driving operations, the angle of the swashplate type swash plate will be gradually reduced to zero degrees causing the drill deflections 12 to feather back to zero in a controlled manner.

[065] Figure 7B shows a diagram of the timing and preferred waveforms that implement the method of phased synchronous bidirectional oscillating deflections of the drill 12 that are used by the RSDT, which is an aspect of the present invention. For the curves in Figure 7B, the x axis of each plot is GTF over the range 0° to 360° for two consecutive rotations of the RSDT. The curves in Figure 7B are consistent with the previously discussed “decreasing angle” scenario shown in Figures 3A to 3D. A person of ordinary skill in the art should understand that the relative timing of the waveforms with respect to one another will remain the same for driving the well in other directions, only the spatial phasing of the waveforms with respect to the GTF (or MTF) will be different. . However, for this example, the objective is to drive the borehole towards the bottom of the hole or towards a GTF equal to 180°. Additionally, a rotation rate of 420 RPM is implicitly assumed when it is necessary to convert the x-axis from GTF to time.

[066] When conducting the well, the modulation of drill deflections is controlled by an on-board electronics control module (shown in Figure 8) that repeatedly and alternately activates valves 94 and 90, through their respective solenoids 96 and 92. The onboard electronics control module will provide the spatial phasing of solenoid control signals necessary to drive the well in any desired direction. In Figure 7B, curve 51 shows the control signal that drives solenoid 96 to control valve 94. Curve 52 shows the control signal that drives solenoid 92 to control valve 90. The y-axis curve plots 51 and 52 designate a logical value of 1 for ON and 0 for OFF. As stated earlier, the x-axis of the plots of all curves in the Figure is the instantaneous GTF of the RSDT guideline 7. The x-axis of the plots covers a range of about 800° or slightly more than 2 full RSDT rotations. Curves 51 and 52 are logical complements and each has a duty cycle of 50%. At points "A" and "C" valve 94 is being switched ON at the same time as valve 90 is being switched OFF. On the other hand, at points "B" and "D", valve 94 is being switched OFF at the same time that valve 90 is being switched ON. When valve 90 is OFF and valve 94 is ON, chamber 107 of lever arm actuating piston assembly 95 is pressurized causing lever arm 87 to move away from guide line 7, which, thereby causing the drill 12 to move in the opposite direction towards the guideline 7 or towards the positive x axis 204 of the RSDT coordination system shown in curve 56 between 0° and 180° of GTF. Conversely, when valve 94 is OFF and valve 90 is ON, chamber 105 of lever arm actuating piston assembly 95 is pressurized causing lever arm 87 to move toward guide line 7 , which thereby causes the drill 12 to move in the opposite direction away from the guideline 7 or towards the negative x axis 204 of the RSDT coordination system shown in curve 56 between 180° and 0 ° of GTF. In this particular example of driving the well in the down direction, the positive bit deflections on turn 56 will be a maximum when the GTF equals 180° or the guideline is “DOWN, and the negative bit deflections on turn 56 will be a maximum when the GTF equals 0° or when the guideline is “UP”.

[067] In Figure 7B, curve 53 shows the differential pressure between chambers 107 and 105, specifically, ΔP = P107 - P105. When ΔP is positive, the drill is being deflected in the direction towards guideline 7. When ΔP is negative, the drill is being deflected in the direction away from guideline 7. The amplitude of ΔP is determined by the flow rate dynamically variable displacement axial piston pump 70 and by frictional drag forces on the bit as it deflects and the RSDT rotates. Curve 54 shows the hydraulic flow rate at pin 1 of valve 94. Curve 55 shows the negative hydraulic flow rate at pin 1 of valve 90. Valves 94 and 90 do not instantly switch from ON to OFF and from OFF to CONNECTED. Each valve takes a finite amount of time to migrate from one state (ON or OFF) to another state (OFF or ON). This finite transition time must be accounted for by the onboard electronics control module by advancing the timing of the solenoid control signals by an amount equal to half the transition time. At 420 RPM, the transition for each valve requires about 54°, so the control signals should drive the intended timing of the drill deflections by half that amount, or by approximately 27°. For the maximum positive drill deflection 12 to occur at a GTF of 180°, the valves must be switched at a GTF of 153°. And for the maximum negative 12 drill deflection to occur at a 0° GTF, the valves must be switched at a -27° GTF. The amount of main valve control angle will decrease linearly as the RPM decreases. Figure 7B demonstrates an advantage of using two independent three-way 2-position valves to separately and simultaneously control each chamber of the lever arm actuating piston assembly 95: the transition time is cut in half by switching both valves 94 and 90 at the same time, compared to the switching transition time of a single 3-position 4-way valve with a core that must travel twice as long and take twice as long to switch.

[068] Figure 7C shows two curves that represent the drill displacement as a function of GTF for the “decreasing angle” or “downward driving” scenario illustrated by Figures 3A to 3D. For the purpose of this discussion, the term “deflection” will specifically refer to the movement of the drill relative to the coordination system that is attached to and rotates with the tool. The graph's x axis shows the instantaneous angular orientation or GTF of the RSDT guideline 7. The y-axis of the graph shows the percent maximum drill travel in two orthogonal directions: in this case, the vertical plane (curve 62) and the horizontal plane (curve 63). More generally, curve 62 shows the instantaneous displacement of the bit in the driving direction, in this case up and down. Curve 63 shows the instantaneous displacement of the drill in the direction perpendicular to the drill's driving direction, in this case, to the left and to the right. The "resultant drill offset" is the vector sum of the coherent oscillating deflections of the drill 12 and the tool rotation. When actuated and decreasing the angle, the electronics control module in the tool will spatially time the oscillating drill movement so that the maximum deflection of the drill 12 occurs in the direction of the vector of gravity so that the drill 12 will remove from preferably more formation from the bottom side of the hole than from the top side of the hole. Labeling “3A” corresponds to the case in Figure 3A where the deflection of drill 12 is “negative” or far from guideline 7. Since guideline 7 is UP with a GTF of 0°, the drill 12 is shifted in the “DOWN” direction. Labeling “3C” corresponds to the case in Figure 3C where drill deflection 12 is “positive” or goes towards guideline 7. Since guideline 7 is DOWN with a GTF of 180°, the drill 12 is shifted in the “DOWN” direction again. Since the repetitive movement of the bit deflection is at the same frequency as the rotation of the RSDT, for an observer fixed relative to the earth, the displacement movement of the bit will appear to be twice the frequency of the rate of rotation of the RSDT. For every 180° of RSDT rotation, the drill will complete one full cycle of motion from centered (3B) to fully displaced in the driving direction (3C) and back to centered (3D). For the next half rotation of the RSDT, the movement will be from centered (3D) to fully shifted in the driving direction (3A) and back to centered (3B). In practice, the maximum displacement of drill 12 is typically a few tens of an inch, but could be more or less in design depending on the desired buildup rate specification.

[069] Figure 7D is a polar plot of the resulting displacement of drill 12 during driving operations. Curve 64 is a reference plot of the instantaneous displacement of drill 12 for true sinusoidal “simple harmonic” motion versus RSDT rotations as a function of the GTF of guideline 7. Curve 65 is a plot of the ideal instantaneous displacement of drill 12 verses the RSDT rotations as a function of the GTF of guideline 7, which uses the “bang-bang” control algorithm and apparatus disclosed in Figures 7A and 7B. Using complementary control signals to control the valves 94 and 90 yields hydraulic flow rates to the lever arm actuating the piston assembly 95 that are trapezoidal and hence the vector velocity profile of the drill displacement 12 is also trapezoidal , by the fact that the vector velocity of the bit displacement is linearly proportional to the rate of net flow into and out of the lever arm 87 actuating the piston assembly 95. The plot of actual bit displacements shown in curve 65 is very similar to the plot of idealized drill offsets shown on curve 64. The drill path 12 shown on curve 65 is actually preferable to the path shown on curve 64 as the actual widening of the unfinished hole in the curved section with motion control trapezoid is somewhat less than the flare that would occur with sinusoidal motion control. If the maximum drill deflections are on the order of 0.64 cm (0.25 inches) while the tool is driving, then the hole diameter in the curved section will be asymmetrically enlarged by 0.64 cm (0.25 inches) in the turn direction; and the sides of the unfinished well (left and right) will be symmetrically widened by approximately 0.51 cm (0.2 inches), which reduces frictional forces on the BHA and drill string as it rotates and slides through the hole. curved section of the hole.

[070] Figure 8A shows a block diagram of optionally dynamic non-inertial navigational sensors and processing. All navigational elements, including sensors and acquisition and processing electronics, are mounted directly to the collar or to a mechanical structure that is fixedly mounted to the collar and rotates with the collar. In this modality, there is no structure in the tool that rotates against the rotation of the RSDT to create a geostationary platform or quasi-geostationary platform. By not using a counter-rotating assembly, impeller unit mechanics and cabling are simplified by eliminating the need for slip rings and rotary pressure compensated mud seals. Another advantage from a computational point of view is that there is a common coordination system, a common rotation rate, and a common instantaneous GTF and MTF for the entire tool and all sensors. Additionally, the absence of a physical geostationary mount allows the sensors to be located within a few feet of the drill face and directly behind the hinge.

[071] The term “geostationary platform” or geostationary assembly” refers to an assembly on a rotating tool that rotates in the opposite direction relative to the rotating tool so that the assembly does not rotate relative to a coordination system that is fixed in ground as the rest of the tool rotates. The orientation of such a physical geostationary assembly, defined in terms of a non-rotating GTF and/or MTF, is controlled to realize the driving direction of the tool in a particular direction. The accelerometers and magnetometers used to control the orientation of the intended geostationary mount can be mounted directly to the geostationary mount or to the rotating collar as done in US Patent 6,742,604 for Brazil (hereinafter referred to as “Brazil”). In Brazil, the instantaneous position of the collar relative to the geostationary mount is measured with an additional electromechanical component known as a resolver that would instantly read the relative position of the inner geostationary mount relative to the outer rotating collar. The electromechanical resolver angle is used to translate only the GTF from the rotating collar reference frame into the non-rotating reference frame of the geostationary mount. A much simpler approach shown in Figure 8A creates a “virtual geostationary platform” by simultaneously acquiring 3 geometry axes for each of 3 types of sensors, namely accelerometers, gyroscopes and magnetometers, 9 geometry axes in total, all sharing a common coordination system fixed to and rotating with the RSDT. Measurements are acquired in block B1. They are sent to block B2 where the conditioning algorithm shown in Figures 8B and 8C removes errors due to DC offsets and mounting misalignment, as well as errors from shock and vibration in the accelerometers. The virtual geostationary processing algorithm in block identification B2 “EARTH COORDINATION SYSTEM” can be used to calculate the inclination and azimuth of the RSDT axis of rotation. By definition, the inclination and azimuth of the RSDT axis of rotation are the same as the inclination and azimuth of unfinished well. A rotation matrix driven by either instantaneous GTF or instantaneous MTF plus the x angle or rate of rotation of the tool from the z-axis gyro is used to convert the accelerometer and magnetometer measurements acquired on the rotating reference RSDT frame to a virtual geostationary frame of reference (ie, the “EARTH COORDINATION SYSTEM”) to calculate the inclination and azimuth of the RSDT axis of rotation. The instantaneous GTF and MTF of the guideline 7 on the rotating collar 43, and the angle between them, defined as “angle X”, together with the virtual geostationary emissions of inclination and azimuth are used to navigate the RSDT and drive the well in the direction required by the customer.

[072] The geostationary reference frame will have a geometric axis z that points to the interior of the well and collinear with the geometric axis of unfinished well and substantially parallel to the geometric axis z of the RSDT. The x axis of the geostationary reference frame points up perpendicular to the z axis of the unfinished well. The x-axis and z-axis and the gravity vector are coplanar. The y axis of the geostationary frame of reference is horizontal and points to the right when looking downhole, it is orthogonal to the x axis, the z axis and the gravity vector. By definition, the unfinished pit slope is expressed as a positive number of degrees equal to the angle between the gravity vector and the z axis of the unfinished pit and can range from 0° to 180°. The slope value for a vertical well is zero degrees and the slope for a horizontal well is 90°. By definition, the azimuth of the unfinished well is expressed as a positive number of degrees between 0° and 360° equal to the angle between the z-axis projection on the horizontal plane and the direction of magnetic north. Azimuth computation is well known to anyone of ordinary skill in the art. To instantly convert a pair of transverse measurements, both acceleration due to gravity and the earth's magnetic field, from the rotating non-inertial RSDT coordination frame of reference to the local non-rotating inertial reference frame, AxUNFINISHEDPOT = AxRSDT*cos(GTF ) + AyRSDT*sen(GTF), and AyPOÇOINACABADO = AxRSDT*-sen(GTF) + AyRSDT*cos(GTF), where AxPOÇOINACABADO and AyPOÇOINACABADO are the transverse components of earth gravity in the reference unfinished well frame, AxRSDT and AyRSDT is the gravity components in the RSDT frame of reference, and GTF is the instantaneous gravity tool face of the RSDT. As a quality check, the value of AyPOÇOINAFADO should likewise be zero; if AyUNFINISHEDPOT is not zero, then the unfinished well slope computation will not be valid. If a valid GTF is not available, then (MTF+Angle X) can be used as an estimate of the GTF value. If both a valid GTF and a valid MTF are momentarily unavailable, then it may be possible to derive an estimated GTF value from the RSDT rotational vector velocity integration from the z-axis gyro sensor, Gz. The unfinished pit slope calculation is then INCL = -ARCTAN(AxUNFINISHEDPOT/AzRSDT). MxRSDT, MyRSDT, MzRSDT, MxPOÇOINACABADO and MyPOÇOINACABADO, can be replaced by AxRSDT, AyRSDT, AzRSDT, AxPOÇOINACABADO, AyPOÇOINACABADO respectively in the rotation matrix for calculating the earth's magnetic field in the reference unfinished well frame and in the standard azimuth calculation of unfinished pit.

[073] An advantage of a rotating navigational platform is that the devices are continually self-calibrating using system rotation to cancel mount and DC device errors that may be a function of temperature. This allows accurate measurement of very small values of downhill slope when the unfinished well is nearly vertical and downhill azimuth when the unfinished well is oriented N-S or S-N and the tool axis is oriented parallel to the earth's magnetic field lines. Unlike Brazil, one embodiment in this disclosure translates the measurements from the rotating frame of reference RSDT to the downhill slope of unfinished well and downhill azimuth of unfinished well into the stationary frame of reference earth, without the need to stop drilling. or create a geostationary mount in the tool. RSDT's virtual geostationary platform has the capability to continuously and dynamically measure unfinished pit inclination (downhill inclination) and unfinished pit azimuth (downhill azimuth) relative to the non-rotating earth coordination system.

[074] Figure 8B shows a block diagram of a processing algorithm modality that is used to cancel misalignment errors in transverse accelerometers. These discussions are also applicable to magnetometers. Three accelerometers, 600, 610, 620, are shown for Ax, Ay, and Az, respectively. The x and z geometry axes represent the transverse geometry axes, the z axis is the tool centerline and is positive of the downhole direction. The output of the accelerometers is a serial digital data stream; there are no analog signals represented in the schematic. Processing for Az, 620, is straightforward as it always reads a gravity DC value, unlike axial shocks and misalignment errors which can easily be filtered out by filter 624, even at low rotation rates. Accelerometers should preferably be mounted as close to the RSDT axis of rotation as possible to minimize the effects of stick slip rotation that drives one AC component to the other DC value of centripetal acceleration. It is also beneficial for Az's accelerometer to be mounted as close to the centerline of rotation as possible to minimize any centripetal acceleration errors from misalignment; for the Ax and Ay accelerometers, 600 and 610, misalignment errors and off-axis centripetal accelerations are signs of DC. Filters 604 and 614 are identical digital 4th order adaptive IIR low pass filters. The cutting frequency is a function of the tool rotational frequency. If the rotation frequency is 7Hz (420 rpm), then the low-pass cutoff frequency is 0.5 Hz. If the rotation frequency is 3 Hz (180 rpm), then the low-pass cutoff frequency is 0.214 Hz. The filter gain is reduced by approximately 90 dB with 360° phase shift in tool rotation rate, so the output of each filter 604 and 614 is just the error signals from DC to Ax and Ay respectively, which are , then subtracted from their respective channels, which yields error-free signals 606 and 616. This allows Ax and Ay to be used to detect all small amounts of slope when drilling vertically. This same error correction processing is also used for magnetometers. Filter 624 for Az (and Mz) is identical to filters 604 and 614 for transverse measurements Ax and Ay. Because DC errors such as electrical offsets cannot be canceled by this method, devices for axial measurements must be calibrated under temperature.

[075] Figure 8C shows a flowchart of dynamic navigational processing that can be used to drive the tool while it is rotating. This processing is running continuously as the tool is running. The axial values of Az and Mz do not change quickly and may be updated every few seconds in step 2.b. The transverse measurements are continually being updated in step 2.a. In step 3, the gyro offsets for all three geometry axes are updated when the tool is stationary in the hole. The z-axis gyro error is calibrated inside the well by correlating with either Mx as My or Ax as Ay in the case of magnetic interference. In step 4, the instantaneous values of GTF and MTF and X angle are calculated first as these are needed to dynamically drive the coefficients in the rotation matrix. Then, the transverse accelerometer and magnetometer measurements are translated to the ground coordination system and combined with Az and Mz to compute the unfinished well inclination and unfinished well azimuth. Angle X has two purposes. One is that sensitive azimuth measurements are typically required versus MTF. The MTF plus the X angle will provide a pseudo GTF value so that measurements acquired by azimuth can be oriented correctly relative to the unfinished well type. In step 5, the GTF and MTF are corrected for processing delays so that they read the spatially corrected GTF and MTF values for driving purposes. The data is then transmitted at low latency to the conduction control unit for generation of conduction commands, storage in tool memory and combination with other data for transmitting R/T telemetry to the surface.

[076] Figure 8D shows the static lift processing that can be used when the tool is not moving, typically in every connection while the drill string is in the slips. This processing takes several minutes to acquire and process the measurements. The tool must be stopped. Earth's gravity accelerations and Earth's magnetic field are measured in all 3 tool axes. If magnetic interference or misalignment errors are suspected, static measurements from the two or more additional GTF and/or MTF orientations can be combined to improve accuracy of unfinished well inclination and azimuth.

[077] Figure 9 shows a general tool model of a possible RSDT modality. At the bottom end of the tool, the bit 12 is attached to the bit shaft 33 which is attached to the drill collar 43 via hinge 5. The stabilizers are not shown. The 9-axis dynamic navigation and drive control electronics and sensors comprising the virtual geostationary platform are located in a housing well above (or behind) hinge 5. The dynamically variable displacement axial piston pump is located in the drive block. “Hydraulic Power and Drive Actuation Section”. The top section of the tool includes ancillary measurements that include, but are not limited to, a 6-axis static survey package, drilling and environmental mechanics measurements, ultrasonic gauge, propagation resistivity of multiple spacings, transverse EM for distance for contrasts of adjacent resistivity, short-range telemetry antenna, natural quadrant GR, central data acquisition, communications, memory, and backup batteries for power during connections.

[078] This disclosure introduced and discussed several benefits and features unique to the dynamically variable displacement axial piston pump in relation to RSDT operation and deployment. However, it should be noted that these same benefits and features unique to the dynamically variable displacement axial piston pump are applicable to the design and operation of other downhole tools, whether conveyed by drill pipe, wireline or tubing. spiral.

[079] When the energy and/or total energy required to operate an MWD or LWD downhole tool for up to 200 hours exceeds the energy that can be practically provided by downhole batteries suitable for use in an oil field, then, it becomes practical to generate energy inside the well through a mud-driven fluid turbine. In that case, the common practice is to supply a mud-driven fluid turbine, such as that described in Bradley in US 3,743,034, and Jones and Malone in US 5,249,161. The fluid turbine can provide energy to drive an electrical alternator or a hydraulic pump. The fluid turbine must operate over a range of mud flow rates and mud densities to be a practical source of downhole power.

[080] The no-load rotational velocity of the turbine is proportional to the flow rate and the stagnant torque is proportional to the flow rate and mud weight. Since power is the product of torque times rotational velocity, available power can increase approximately as the second power of mud flow rate times the increase in mud weight. Additionally, it is common to cover a 2:1 flow rate range with a single turbine design, meaning that available power can easily quadruple over that range. By way of illustration, if the minimum mud weight is taken as 994.559 grams per liter (8.3 pounds per gallon), the maximum mud weight may be 1917.22 (16 pounds per gallon), another factor of two increments in torque available. A well-designed turbine must provide the minimum amount of power required to operate the system at the minimum flow rate and minimum drilling mud weight. For the purposes of this discussion, the minimum power required to operate a given system can be chosen as 2 HP. This means that the power from the turbine at maximum flow rate and mud weight can be approximately 8 times the power available at minimum flow rate and mud weight, approximately 16 HP.

[081] If the turbine is driving an electrical alternator, as described in “Jones and Malone” in US 5,249,161, the output current can be managed by the load, but the alternator output voltage will tend to double as the turbine rotational speed doubles. One method of dealing with this situation is to use a hybrid homopolar alternator with field windings to boost or step down the output voltage and retain it within a manageable range over all or part of the mud flow range. There will be several design implications for minimizing copper I2R losses in the alternator windings in order to minimize temperature rise while keeping the output voltage below a manageable level. Also, there are copper I2R losses in the field windings as well. The field windings will never have the ability to practically cancel the internal magnetic field, so there will be a rotational vector speed above which the voltage will inevitably increase even at maximum field decay current. Additionally, due to efficiency and volumetric limitations, there is a practical upper limit to the amount of power that can be reliably generated by an electrical alternator. For those applications that require more than about 3 HP, it may be more practical to drive a hydraulic pump with a fluid turbine rather than an electrical alternator.

[082] One embodiment of the present disclosure uses a hydraulic pump driven by the mud-fed fluid turbine. If the turbine is driving a fixed positive displacement pump as described in "Bradley" (U.S. Patent 3,743,034), as the turbine speed increases, the pump output flow rate will increase. Additionally, as the flow rate increases, the pressure will increase to the point limited by a pressure relief valve. At maximum flow rate and drilling mud weight, which generates approximately 16 HP, the turbine will wear out prematurely from erosion effects and the relief valve at the pump outlet will dissipate 5 to 10 HP as the hydraulic fluid is drained. vented adiabatically through an orifice back to the low pressure hydraulic reservoir, which causes the valve temperature to rise well beyond specified levels, resulting in valve and system failure.

[083] A solution to this problem is to replace a fixed positive displacement pump with a dynamically variable displacement axial piston pump, also called “swashplate type swashplate pump”. The dynamically variable displacement axial piston pump is ideally suited for use in an embodiment of the present disclosure. Outside the field of underground oil well interior drilling tools, dynamically variable displacement axial piston pumps are used in many places such as hydraulically operated tractor deployments, construction equipment such as excavators and very commonly in Zero Radius Maneuver Grass Cutting. In such cases, one or more dynamically variable displacement axial piston pumps are used to control variable output flow rate and flow direction to independently drive wheels and/or axles. In the field of mud-fed MWD and LWD downhole tools, the pump provides an effective power management solution for mud driven drill collar mounted tools for use in oil and gas wells, although such deployment has not been previously deployed. As flow rate and slurry weight increase, the swashplate type swash plate angle can be decreased, which reduces pump displacement, which allows the flow rate out of the pump to remain constant. For a given flow rate and weight of drilling mud, the swashplate type swashplate angle will be selected to provide the amount of flow and pressure required by the load that is driven by the dynamically variable displacement axial piston pump. The swashplate swashplate angle can be controlled either by an electrically powered linear actuator or an “electronic displacement controller,” which uses a proportional valve and hydraulic pistons to actuate the swashplate swashplate.

[084] Figure 7A, as previously described above, shows an open loop hydraulic embodiment in which the dynamically variable displacement axial piston pump 70 is used to regulate the variable output power from the turbine 71 and match the same to the variable output power demanded by the dynamic load, comprised of valves 90 and 94 and bidirectional piston actuator 95. In this mode, the definition of the swashplate type swashplate angle is determined by the drilling mud flow rate and the amount of fluid hydraulic required by the load. As previously discussed in detail, the swashplate type swash plate angle is adjusted to increase or decrease the range of motion of lever arm 87 which controls coherent symmetric deflections of the drill.

[085] Figure 10 shows another application for drilling oil and gas wells, in which the output of the dynamically variable displacement axial piston pump 300 can be connected by a hydraulic line 302 to a hydraulic motor 310, which forms a hydraulic transmission. In this embodiment, the swashplate swashplate angle is adjusted by means of an actuator 325, which may be motor driven or hydraulically driven, to control the output shaft speed of hydraulic motor 310. Hydraulic motor 310 may be a fixed displacement hydraulic motor or a variable displacement hydraulic motor to allow more degrees of freedom for control. The output shaft 312 of the hydraulic motor 310 can drive an electric alternator 315. Whereas the transmission comprised of the dynamically variable displacement axial piston pump 300 and hydraulic motor 310 can maintain a constant speed of the output shaft 312 over a wide range of flow rates and mud weights, the generator can be a very simple and basic brushless alternator. The output voltage of ΦA, ΦB and ΦC would be kept constant by maintaining a constant speed of the input shaft 312 of the motor 310 by adjusting the swashplate angle which depends on the drilling mud flow rate. Power supply 330 would measure the output voltage of alternator 315 and generate a feedback signal 335 to increase or decrease the angle of the swashplate swashplate via actuator 325. A charge pump 305 ensures that the axial piston pump of dynamically variable displacement 300 is prepared at startup. Hydraulic fluid reservoir is 75. Various relief valves, PRV3 and PRV4 are provided to prevent any over pressure conditions. Several check valves, CV5, CV6, and CV7 are provided to prevent any unwanted backflow. Filters F2 and F3 are provided to ensure that any particulate matter in the hydraulic fluid remains in the fluid reservoir and is not recirculated through the system. The swashplate type swashplate angle of the 300 dynamically variable displacement axial piston pump regulates the input power available from the drilling mud driven turbine as well as providing the variable power that can be demanded by the load for measurements and transmitted services. per drill pipe.

[086] Figure 11A shows yet another embodiment in which the output shaft 412 of the hydraulic motor 410 can be used to drive a rotary mud valve rotor 450 for generating a mud pulse telemetry transmitted by drill pipe while it pierces. As the rotary mud valve rotor 450 is rotated close to the rotary mud valve stator 452, it generates an oscillating sequence of high and low pressures as described in Jones and Malone. Phase changes are periodically introduced into the rotation of the rotary valve rotor 450 in order to digitally encode data into a sequence of high and low pressures. The dynamically variable displacement axial piston pump 400 and hydraulic motor 410 would replace the electric motor which is driving a rotary valve as described in Jones and Malone. The output of the hydraulic motor shaft 412 would be connected to a shaft resolver 420 and a 2 pole 1 position magnetic positioner 435. The gearbox 440 can be any gear ratio that is advantageous for the operation of the hydraulic motor 410, however it would need to match the number of lobes on a rotary mud valve rotor 450 and stator 452. The telemetry control processor 430 receives an input data stream 432, and uses shaft position feedback from a resolver 420 to actuate the swashplate swashplate through an actuator control line 437 and swashplate swashplate actuator 425 to introduce phase shifts in the slurry pressure wave generated by the rotary valve rotor 450 and stator 452.

[087] An alternative embodiment of a hydraulically driven mud pulse telemetry system is shown in Figure 11B, which is similar to the embodiment shown in Figure 11A, but with a 2-lobe rotary valve rotor 460 and stator 462, without a gearbox, however using a 4-pole (2-position) magnetic positioner 437 and a resolver 420. The resolver 420 is required at the output of the hydraulic shaft in order to know and control the rotation of the hydraulic motor shaft 412 as a function of time. Magnetic positioner 437 is an optional but preferred mechanism in that it will passively return rotary valve rotor 460 to an open position when power is OFF or in the event of an electronics failure to prevent pipe pulling from extinction. A processor 430 attached to the swashplate type swashplate actuator control 425 will accept a drill current received 432 via a digital data bus. It will convert the received digital data stream 432 into a sequence of axis positions 412 as a function of time. Drills can be encoded in pressure pulses using BPSK or Feher QPSK. Resolver 420 feeds back the position of shaft 412 to processor 430 which controls the data stream from rotary valve 460 so that processor 430 can make dynamic adjustments to the swashplate angle via control line 437 and the actuator. of swashplate type swashplate 425, to achieve the desired pressure wave sequence of mud pressures for a mud pulse telemetry transmitted by drill pipe while drilling.

[088] The applications and modalities previously revealed for the dynamically variable displacement axial piston pump were all open loop hydraulic circuits that do not fully take advantage of the reversibility of the dynamically variable displacement axial piston pump. The dynamically variable displacement axial piston pump can also be used in closed loop hydraulic applications where the pump's ability to reverse the flow of hydraulic fluid through the pump can result in a significant reduction in the number of valves to be controlled, a reduction the number of hydraulic passes, as well as more precise control of low pressure differential applications, such as formation fluid sampling. Figures 12 and 14 will illustrate the benefits of using the dynamically variable displacement axial piston pump in closed loop fully reversible hydraulic circuits. These embodiments can be incorporated within downhole tools that are conveyed in wireline, coiled tubing and/or drill collar.

[089] Figure 12 is the hydraulic schematic for a sidewall drilling application Hydraulic pumps have been used in this type of application before, however the pumps are fixed displacement and unidirectional. If the core cutting hole saw becomes stuck, the motor that drives the saw cannot be reversed and the shaft must be sheared so that the tool can be safely extracted from the hole without damaging either the unfinished pit or the tool. The schematic shown in Figure 12 solves this problem. An electric motor 540 drives a shaft 512 which drives a dynamically variable displacement axial piston pump 500 and a charge pump 505. The swashplate type swashplate angle of the dynamically variable displacement axial piston pump 500 is increased by an actuator swashplate type swash plate assembly (not shown) so that high pressure hydraulic fluid flows out of line 502 to hydraulic motor 510, causing shaft 522 to rotate core cutting hole saw 550 in the cutting direction. Pressure across the 510 hydraulic motor can be monitored to confirm system operation and identify possible anomalous conditions. If cutter 550 becomes stuck, the high pressure in line 502 will increase so that it triggers pressure relief valve PRV11 and guides fluid through line 507 connected to negative servo piston 576, which reduces angle of type swashplate. swashplate on pump 500. If it is determined by the operator that cutter 550 is stuck, the direction of rotation of shaft 522 of motor 510 can be reversed, which unscrews the cutter, setting the swashplate-style swashplate angle to one negative value, causing high pressure to flow in line 503. Overpressure relief is provided by PRV14. In this case, the high pressure would be applied to the positive swashplate swashplate servo valve 575 causing the swashplate swashplate angle to reduce the flow rate of the dynamically variable displacement axial piston pump 500 which alleviates the low condition. overpressure in line 503. The advantage of this system is that it automatically protects itself, and if cutter 550 becomes stuck, the pump can be reversed, which unscrews cutter 550 from shaft 522 so that shaft 522 can be safely retracted and the tool can be pulled out of the hole.

[090] Another application where a variable displacement piston pump is ideally suited is formation fluid sampling using a “claw-type coupling piston pump”. An example of the prior art is shown in Figure 13. Using a 600 fixed displacement single ended pump requires 4 valves VA, VB, VC and VD, and 4 check valves CV20, CV21, CV22 and CV23 to drive the piston pump 640 Grapple Type Coupling Hose. The 653 Sidewall Packing Probe is deployed against the unfinished well wall with sufficient force to make a hydraulic seal with the formation. To drive the "right" clutch coupling piston pump piston 649 649 in the Figure, the electric motor 635 drives the non-reversing fixed displacement pump 600. Valves VA and VD are actuated or "opened" while valves VB and VC are off or “closed”. High pressure fluid in line 623 flows through check valve CV21 through valve VA into chamber 641, which moves piston 649 to the right. Low pressure fluid flows out of chamber 644 through valve VD to tank 75. Fluid is drawn from the formation through flow line 647, and is sucked into chamber 643. At the same time, formation fluid in the chamber 642 is pushed out through check valve VC32 into flow line 648, where the fluid will either be discharged into the unfinished well or redirected to the sample bottle for transport to the surface when the tool is pulled out of the hole . Once the piston 649 of claw type coupling piston pump 640 has moved all the way to the right, the valves are reversed. VA and VD are closed while valves VB and VC are open, which allows high pressure fluid from pump 600 to flow into chamber 644, which displaces claw-type coupling piston 649 to the left in the Figure. Formation fluid that has just been pushed into chamber 643 is now pressed through check valve CV33 into line 648 for discharge into the unfinished well or to further fill a sample bottle for transport to the surface. The VA, VA, VC and VD valves are all controlled via a 611 control unit. Any other pressure condition that occurs is relieved by the PRV60 pressure relief valve. Controlling the formation fluid sampling rate is accomplished by controlling the speed of the electric motor 635 in response to changes in pressure measured by the pressure transducer 650. The embodiment in Figure 14 is the result of replacing the fixed displacement pump of the “prior art” 600 in Figure 13 with a dynamically variable displacement axial piston pump 700 shown in Figure 14. Valves VA, VB, VC, and VD and check valves CV20, CV21, CV22, and CV23 in Figure 13 can be removed , and the number of hydraulic passages is reduced, which greatly simplifies hydraulic piping. A further simplification is that the electric motor 735 which drives the variable displacement axial piston pump 700 and the charge pump 705 through the drive shaft 712 may be a fixed speed induction motor. With the sidewall packing probe 753 deployed against the unfinished well wall so that it makes a hydraulic seal with the formation, the swashplate-type swashplate angle of the dynamically variable displacement axial piston pump 700 is increased in the direction positive by the swashplate-type swashplate actuator 725 so that hydraulic fluid flows through line 702 into chamber 741 and out of chamber 744 of claw-type coupling piston pump 740 through line 703, causing Claw coupling piston 749 travels to the right. This forces formation fluid out of chamber 742 through check valve CV42 into line 748 for discharge into the unfinished well or dispersion into a sample bottle for transport to the surface when the tool is pulled out of the hole. . At the same time, formation fluid from probe 753 is drawn into chamber 743 through flow line 747 and check valve CV41. The swashplate-type swashplate angle setting can be increased or decreased in response to readings from the 750 flowline pressure transducer to ensure that the pressure drop across the 747 flowline is not too low, which would any gas dissolved in the formation fluid in line 747 to come out of solution. Once the 749 claw type coupling piston has reached its full right travel, the swashplate swashplate angle of dynamically variable displacement axial piston pump 700 is reversed via the swashplate swashplate actuator. 725 under the control of control module 711 and control lines 716. When the angle of the swashplate type swashplate is negative, the flow through the dynamically variable displacement axial piston pump 700 is reversed. High pressure hydraulic fluid flows from line 703 into chamber 744 and out of chamber 741 through line 702 back to the pump. This causes the claw-type coupling piston 749 to shift to the left in the Figure, which forces the formation fluid in chamber 743 to flow through check valve CV43 into flow line 748 for discharge into the unfinished well or continuous dispersion into a sample bottle (not shown) for transport to the surface when the tool is pulled out of the hole. At the same time formation fluid is drawn into chamber 742 through check valve CV40, flow line 747 and probe 753. Overpressure relief for pump 700 is provided by pressure relief valves PRV31 and PRV32. Using a reversible closed-loop variable displacement axial piston pump results in a significant simplification of the hydraulic piping required to interact with the claw type coupling pump and results in a greater degree of formation fluid pressure control.

Claims (28)

1. Downhole assembly (28) CHARACTERIZED by the fact that it has an axis of rotation and comprising: a drill bit assembly (12), a drill collar (43) having a central longitudinal axis, a rotatable driveable drilling tool (26) operatively connected to the drill bit assembly (12), comprising: a pivotal connection (5) between the drill collar (43) and the drill bit assembly (12), which is capable of to articulate in a single plane that is fixed with respect to a reference point in the downhole assembly (28); said articulated connection (5) configured so that it is able to articulate using deflections that are bidirectional and geometrically symmetrical around said central longitudinal geometric axis of the drilling collar (43) from a fixed reference point relative to the piercing collar (43); and said articulated connection (5) further configured such that it is capable of articulating using deflections that are spatially phased such that consecutive deflections occur in the same geostationary direction at the same point in space, while starting from a fixed reference point at with respect to the drilling collar (43), said consecutive deflections occur in opposite directions. 2. Bottomhole assembly (28), according to claim 1, characterized by the fact that: the rotatable driveable drilling tool (26) additionally comprises: a lever (87) configured to articulate the articulated connection (5) and the drill bit assembly (12), and a hydraulic piston operatively connected to the lever (87). 3. Downhole assembly (28), according to claim 2, characterized by the fact that: the rotatable driveable drilling tool (26) additionally comprises: an electronically actuated valve, a microcontroller assembly comprising: a processor , a non-volatile memory element, an algorithm stored in non-volatile memory configured to control the timing of the lever movement (87) actuating the electronically actuated valve. 4. Downhole assembly (28), according to claim 3, characterized by the fact that: the rotary driveable drilling tool (26) additionally comprises a power source comprising: a dynamically displaced axial piston pump (70), a drilling mud-fed fluid turbine (71) driving a dynamically variable displacement axial piston pump input shaft (70). 5. Bottomhole assembly (28), according to claim 2, characterized by the fact that: the rotary driveable drilling tool (26) additionally comprises a power source comprising: an axial piston pump of dynamically variable displacement (70), a drilling mud-fed fluid turbine (71) driving a dynamically variable displacement axial piston pump input shaft (70). 6. Bottom-hole assembly (28), according to claim 5, characterized by the fact that: the rotating driving drilling tool (26) additionally comprises: a hydraulic fluid passage that connects the output of the piston pump dynamically variable displacement axis (70) to the hydraulic piston. 7. Downhole assembly (28), according to claim 1, characterized by the fact that: the rotary driveable drilling tool (26) additionally comprises a power source comprising: an axial piston pump of dynamically variable displacement (70), a drilling mud-fed fluid turbine (71) driving a dynamically variable displacement axial piston pump input shaft (70). 8. Downhole assembly (28), according to claim 7, characterized by the fact that: the rotatable driveable drilling tool (26) additionally comprises: an electronically actuated valve, a microcontroller assembly comprising: a processor, a non-volatile memory element, an algorithm stored in non-volatile memory configured to perform the steps of: controlling the amplitude of the deflections by changing the displacement of the dynamically variable displacement axial piston pump (70). 9. Downhole assembly (28), according to claim 8, FEATURED by the fact that the algorithm stored in the non-volatile memory additionally performs the steps of: controlling the timing of the lever movement (87) acting the electronically actuated valve. 10. Bottomhole assembly (28), according to claim 1, FEATURED by the fact that: the hinge (5) of the swiveling driving drilling tool (26) is configured to be orthogonal to the geometric axis of the line of center of the piercing collar (43). 11. Downhole assembly (28), according to claim 1, CHARACTERIZED by the fact that: the rotatable driveable drilling tool (26) additionally comprises a non-inertial navigational module that is fixedly mounted in a chamber that is connected to and rotates with the drill collar (43), comprising: a plurality of orthogonally oriented accelerometer sensors configured to generate output data, one or more gyro sensors configured to generate output data, comprising at least one gyro sensor having an axis aligned with the axis of rotation of the downhole assembly (28), one or more magnetometer sensors configured to generate output data, and a navigational module microcontroller assembly comprising: a processor, an element non-volatile memory, an algorithm stored in non-volatile memory configured to perform the steps of: receiving output data from the plurality of accelerometer sensors, one or more gyro sensors and one or more magnetometer sensors, processing output data received from the plurality of accelerometer sensors to correct device and mechanical misalignment errors in the data, generating misaligned accelerometer sensor data mechanical and device corrected, process the output data received from the one or more gyro sensors, the output data received from one or more magnetometer sensors, and the accelerometer sensor data with mechanical and device misalignment corrected, use the processed data to generate output with respect to one or more of: gravity tool face, magnetic tool face, x-angle, and rotation frequency. 12. Downhole assembly (28), according to claim 11, FEATURED by the fact that the algorithm stored in non-volatile memory is additionally configured to perform the step of: using output data from the plurality of accelerometer sensors orthogonally oriented to generate the output relative to the downhill slope of the axis of rotation of the downhole assembly (28). 13. Downhole assembly (28), according to claim 11, FEATURED by the fact that the algorithm stored in non-volatile memory is additionally configured to perform the step of: using output data from one or more sensors of magnetometer to generate the output related to the downhill azimuth of the axis of rotation of the downhole assembly (28). 14. Downhole assembly (28), according to claim 11, FEATURED by the fact that the algorithm stored in the non-volatile memory is additionally configured to perform the step of: integrating the output in relation to the rotation frequency to estimate face of gravity tool. 15. Method of directional drilling of wellbore sections FEATURED in that it comprises the steps of: implementing a downhole assembly (28) having an axis of rotation and comprising: a drill bit assembly (12), a drill collar (43) having a central longitudinal axis, a rotatable drivable drill tool (26) operatively connected to the drill bit assembly (12), comprising: a pivotal connection (5) between the drill collar (43) and the drill bit assembly (12), which is capable of pivoting in a single plane that is fixed with respect to a reference point on the downhole assembly (28); and pivoting the hinge (5) so that the drill bit is driven in a desired direction using deflections that are: bidirectional and geometrically symmetrical around said central longitudinal geometric axis of the drill collar (43) from a point of fixed reference with respect to the drill collar (43), and spatially phased so that consecutive deflections occur in the same geostationary direction at the same point in space, while from a fixed reference point with respect to the drill collar (43), said consecutive deflections occur in opposite directions. 16. Method, according to claim 15, characterized by the fact that it additionally comprises the steps of: using a lever (87) to articulate the articulated connection (5) and the drill bit assembly (12), and move the lever (87) with a hydraulic piston. 17. Method according to claim 15, CHARACTERIZED by the fact that the rotatable driveable drilling tool (26) additionally comprises: an electronically actuated valve, a microcontroller assembly comprising: a processor, a non-volatile memory element , an algorithm stored in non-volatile memory configured to control deflections through actuation of the electronically actuated valve. 18. Method, according to claim 17, characterized by the fact that it additionally comprises the steps of: using a dynamically variable displacement axial piston pump (70) to supply power to the rotary driveable drilling tool (26), and driving a dynamically variable displacement axial piston pump input shaft (70) with a drilling mud-fed fluid turbine (71). 19. Method, according to claim 16, characterized by the fact that it additionally comprises the steps of: using a dynamically variable displacement axial piston pump (70) to supply power to the rotating drilling tool (26), and driving a dynamically variable displacement axial piston pump input shaft (70) with a drilling mud-fed fluid turbine (71). 20. Method according to claim 19, CHARACTERIZED by the fact that: the rotatable drilling tool (26) additionally comprises: an electronically actuated valve, a microcontroller assembly comprising: a processor, a memory element not volatile, an algorithm stored in non-volatile memory configured to control the amplitude of lever movement (87) by changing the displacement of the dynamically variable displacement axial piston pump (70). 21. Method, according to claim 20, CHARACTERIZED by the fact that the algorithm stored in the non-volatile memory additionally performs the steps of: controlling the timing of the lever movement (87) actuating the electronically actuated valve. 22. Method, according to claim 19, CHARACTERIZED by the fact that: the rotating driving drilling tool (26) additionally comprises: a hydraulic fluid passage that connects the output of the dynamically variable displacement axial piston pump (70 ) to the hydraulic piston. 23. Method, according to claim 19, CHARACTERIZED by the fact that: the rotatable driving drilling tool (26) additionally comprises a non-inertial navigational module, which is fixedly mounted in a chamber that is connected to and rotates with the drill collar (43), comprising: a plurality of orthogonally oriented accelerometer sensors configured to generate output data, one or more gyro sensors configured to generate output data, comprising at least one gyro sensor having an axis aligned with the axis of rotation of the downhole assembly (28), one or more magnetometer sensors configured to generate output data, and a navigational module microcontroller assembly comprising: a processor, a non-volatile memory element, an algorithm stored in non-volatile memory configured to perform the steps of: receiving output data from the plurality of accelerometer sensors one or more gyro sensors and one or more magnetometer sensors, processing output data received from the plurality of accelerometer sensors to correct device and mechanical misalignment errors in the data, generating accelerometer sensor data with mechanical misalignment, and corrected device sensor, process the output data received from the one or more gyro sensors, the output data received from the one or more magnetometer sensors, and the accelerometer sensor data with mechanical and device misalignment corrected, use the data processed to generate output with respect to one or more of: gravity tool face, magnetic tool face, x-angle, and rotation frequency. 24. Method, according to claim 23, characterized by the fact that it further comprises the step of: using output data from the plurality of orthogonally oriented accelerometer sensors to generate output relative to the downhill slope of the geometric axis of rotation of the downhole assembly (28). 25. Method, according to claim 23, CHARACTERIZED by the fact that it additionally comprises the step of: using output data from one or more magnetometer sensors to generate the output related to the downhill azimuth of the geometric axis of rotation of the downhole assembly (28). 26. Method, according to claim 23, CHARACTERIZED by the fact that it additionally comprises the step of: integrating the output in relation to the rotation frequency to estimate the gravity tool face. 27. Method, according to claim 15, characterized by the fact that it further comprises the steps of: using a dynamically variable displacement axial piston pump (70) to supply power to the rotary driveable drilling tool (26) , and driving a dynamically variable displacement axial piston pump input shaft (70) with a drilling mud-fed fluid turbine (71). 28. Method, according to claim 15, characterized by the fact that: the hinge (5) of the rotary driven drilling tool (26) is configured to be orthogonal to the geometric axis of the center line of the drilling collar (43) .

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