Maintaining Dynamic Friction in a Wellbore Through Harmonic Rotary Oscillations

Abstract

Techniques are disclosed which acts to maintain a drillstring in dynamic friction during geo-steering operations when the drillstring is not rotating. Embodiments of the invention include a drilling system having a drillstring coupled to a top drive or a kelly, and a method of estimating a frictional torque along the drillstring to compute an oscillatory rotary input to the top drive or the kelly based on an input period or amplitude received at a human machine interface. A rotary control signal based on the oscillatory rotary input is transmitted to the top drive or the kelly via a variable-frequency drive (VFD) motor control system. The drillstring can be further coupled to a sensor and the feedback from the sensor can be monitored for proper operation to adjust the oscillatory rotary input during the geo-steering operations.

Description

FIELD OF THE INVENTION

The present disclosure relates to the process of wellbore construction. More specifically, the present disclosure relates to the reduction of friction along the drillstring through the injection of a harmonic torsional oscillation from the surface, wherein the friction reduction acts to maintain the drillstring in a dynamic friction regime during operations rather than in a static friction regime.

BACKGROUND OF THE INVENTION

Wellbore fluids comprising natural resources such as oil, gas, or water are recovered from a wellbore that is drilled from surface. A wellbore is drilled using a string of tubing known as a drillstring, which generally includes a drilling assembly that terminates in a drill bit. Drilling fluid known as drilling mud is passed down the string of tubing to the drill bit to clean the wellbore, cool the drill bit, and carry drill cuttings back to surface. While a wellbore can be generally vertical, wells can be drilled directionally using various directional drilling or geo-steering techniques. Directional drilling or geo-steering includes the practice of drilling non-vertical wells and is typically employed in oilfield directional drilling or utility installation directional drilling (e.g., horizontal directional drilling or directional boring) to keep a wellbore in a particular section of a reservoir, which can minimize gas or water breakthrough and/or maximize economic production from the well. More specifically, directional drilling allows for drilling into a reservoir where vertical access is difficult or impossible, or where it is desirable to increase the exposed section length through the reservoir. Directional drilling can also allow for more wellheads to be grouped together on one surface location to make drilling operations more efficient in terms of time and cost.

Generally, directional drillers use a downhole mud motor that can kick off the well, build angle, drill tangent sections, and maintain a trajectory. A bend in the motor housing is key to steering the drill bit toward its target. The surface adjustable bend can be set between a predetermined range of degrees to point the drill bit in a given direction and permit rotation of the entire mud motor assembly during rotary drilling. The angle of deflection can determine the rate at which the motor builds angle to establish a new wellbore trajectory. By orienting that bend in a specific direction, called its toolface angle, the driller can alter the inclination and azimuth of the well path. To maintain the orientation of that bend and thus change wellbore trajectory, the drillstring must not be allowed to rotate.

A mud motor is a type of positive displacement motor powered by drilling fluid. An eccentric helical rotor and stator assembly drive the mud motor. As it is pumped downhole, the drilling fluid flows through the stator and turns the rotor. The mud motor can convert hydraulic power to mechanical power to turn a drive shaft that causes the drill bit to rotate. Using mud motors, directional drillers alternate between rotating and sliding modes of drilling. In the rotating mode, the drilling rig's top drive or the drilling rig's kelly coupled to a rotary table rotates the entire drillstring to transmit power to the bit. These rotations enable the bend in the motor bearing housing to point equally in all directions and thus maintain a straight drilling path. Measurement-while-drilling (MWD) tools can provide real-time inclination and azimuth measurements that alert the driller to any deviation from the intended course. To correct for those deviations or to alter the wellbore trajectory, the driller switches from rotating to the sliding mode, which decreases the rate of penetration (ROP). In the sliding mode, the drillstring does not rotate. Instead, the downhole motor turns the drill bit and the hole is drilled in the direction that the drill bit is pointing, which is controlled by a toolface orientation. This requires the driller to stop drilling and determine the wellbore deviation using real-time MWD toolface measurements. Upon correcting course and re-establishing the wellbore trajectory needed to hit the target, the driller may then switch back to the rotating mode.

During these operations, the drillstring experiences static friction, which is greater than the dynamic friction of pipe in motion, particularly as the depth or lateral reach increases. The static friction makes the transmission of surface axial and rotary motion to the motor housing and the drill bit difficult. Axial motion is required to impart the necessary weight on bit (WOB) to continue hole deepening while rotary motion is necessary to change the angular position of the bent housing motor assembly, or the toolface, to allow geo-steering operations to occur. If the drillstring remains motionless and then an axial or rotary force is imparted, the resulting downhole motion is irregular due to the transition from a higher static friction to a lower dynamic friction along sections of the drillstring in motion. This presents the need for a system that maintains the entire drillstring in motion while not affecting the downhole drilling process. Such a system would improve the transmission of surface axial and rotary changes to the downhole equipment by reducing this change from static to dynamic friction. In this regard, the disclosure herein addresses these problems.

SUMMARY OF THE INVENTION

The following discloses a simplified summary of the specification in order to provide a basic understanding of some aspects of the specification. This summary is not an extensive overview of the specification. It is intended to neither identify key or critical elements of the specification nor delineate the scope of the specification. Its sole purpose is to disclose some concepts of the specification in a simplified form as to prelude to the more detailed description that is disclosed later.

Techniques are described herein for automatically imparting a harmonic rotary motion at the surface of a drillstring that will maintain rotary motion along a majority of the drillstring, especially where friction is highest in curved sections of the wellbore. The present system uses an estimate of the torsional friction in the drillstring to compute an equivalent number of twists in the drill pipe to automatically compute the amplitude or the period based on an input period or amplitude of a harmonic torsional oscillation of a top drive or a kelly that is coupled to the drillstring.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 graphically depicts an exemplary wellbore construction environment in a case where geo-steering is used.

FIG. 2 shows a block diagram of various components of an illustrative computing device comprising a human-machine interface (HMI), according to aspects of the present disclosure.

FIG. 3 shows a workflow of example architecture for a drilling system, according to aspects of the present disclosure.

FIGS. 4 and 5 show example processes for imparting a harmonic rotary motion from the top drive or the kelly to rotate the drillstring, in accordance to aspects of the present disclosure.

DETAILED DESCRIPTION OF THE INVENTION

Referring now to FIG. 1, there is shown an exemplary wellbore construction environment 100 comprising a drilling system having a drilling rig 102 that is mounted at a surface 106. In various embodiments, the surface 106 can be on land or the surface 106 can comprise a drilling platform for offshore operations. The drilling rig 102 includes equipment used to drill a wellbore 116. For example, the drilling rig 102 can include mud tanks 110, mud pumps 112, a derrick or mast, drawworks, a top drive or a kelly coupled to a rotary table 104, a drillstring 114, a hook coupled to a swivel 124, and power generation equipment (not pictured). As used herein, the terms “top drive,” and “kelly” may be used interchangeably unless the context clearly indicates otherwise. The swivel allows the drillstring 114 to rotate while allowing mud pumps to pump fluid through the drillstring 114. The swivel can be coupled to the top drive or the kelly 104. In the latter case, the rotary table can be disposed on the derrick floor and connected to one or more engines or motors for rotating the kelly. The kelly fits onto a kelly brushing, which attaches to the rotary table. The rotary table, kelly brushing, and kelly rotate as a unit. In various embodiments, the top drive or the kelly 104 can comprise one or more electric or hydraulic motors that is connected to the drillstring 114 via a quill, wherein the orientation of the quill can be changed.

The drilling rig 102 may also include at least one programmable logic controller (PLC) system 108, a remote controller assembly, an industrial panel computer (IPC), a computing device, and/or so forth. In various embodiments, the PLC system 108 can comprise a CPU, an encoder, an interface module (IM) (e.g., a human machine interface (HMI)), a communication interface or a communication processor (CP), and a power supply unit (PSU). The PLC system 108 can be distributed processing nodes that may provide data and processing redundancy, in which data processing and data storage may be scaled in response to demand. In this regard, the PLC system 108 can comprise multiple PLCs in a network environment for controlling hardware resources and managing data processing and storage, wherein one or more PLCs can be added or removed on the fly without affecting the operation of the drilling system. Additionally, the environment 100 can comprise multiple networks, wherein the networks can communicate, for example, via a DP/DP coupler. The HMI can comprise a display (e.g., liquid crystal display (LCD), LCD touch screen, cathode ray tube (CRT), light emitting diode (LED)) that may comprise a graphical user interface (GUI), which can provide various dialogue boxes or icons for operating the rig 102. The display may be connected to various input/output devices such as a keyboard or a mouse that enables an operator to input commands to control one or more components of the rig 102.

The drillstring 114 comprises a drill bit 120, a bottom-hole-assembly (BHA), drill collars (DC) (e.g., slick DC, spiral DC), drilling stabilizers, a bent housing motor assembly 122, and one or more drill pipes 126, wherein the pipes can be engaged together. The one or more steel drill pipes comprise a given diameter and thickness. More particularly, the pipes comprise a substantially circular cross section with an outer diameter and an inner diameter. The drill bit is coupled to the BHA and the bent housing motor assembly 122. The bent housing motor assembly, the BHA, and the drill bit 120 are located at the terminal end of the drillstring 114. The bent housing motor assembly 122 can comprise an eccentric rotor within an elastomer stator. As drilling mud flows through the stator, it displaces the helical rotor shaft, causing the shaft to rotate within the stator's protective housing, which turns the drill bit 120.

The BHA can include logging while drilling (LWD) tools, measurement while drilling (MWD) tools, and a communication interface, depending upon embodiments. The LWD tools and MWD tools can include downhole instruments, including sensors for monitoring downhole drilling characteristics and conditions. Example downhole conditions include formation resistivity, permeability, and/or so forth. Example downhole drilling characteristics include the rate of rotation of the drill bit, the torque-on-bit (TOB), the weight on the bit (WOB), and/or so forth. Data generated by the LWD tools and MWD tools can be transmitted to a data store or a repository via the communication interface for access by an operator in a remote room.

The top drive or the kelly 104 can be coupled to the drillstring 114 in order to impart torque and rotation to the drillstring 114 (e.g., via a motor), causing the drillstring 114 to rotate. Torque and rotation imparted on the drillstring 114 may be transferred to the BHA and the drill bit 120, causing both to rotate. The torque at the drill bit 120 is the TOB and the rate of rotation of the drill bit 120 may be expressed in rotations per minute (RPM). The rotation of the drill bit 120 and the top drive or the kelly 104 may cause the drill bit 120 to engage with or drill into the formation and extend the borehole. It is noted that one of ordinary skill in the art will appreciate that various drilling assembly arrangements are possible.

During drilling operations, the drillstring 114 extends downwardly through the wellbore 116. The wellbore 116 is substantially vertical from the surface to the curve 118 and then deviated into another direction that is angled or substantially horizontal. In this regard, the bent housing motor assembly 122 is configured to steer the drill bit 120 towards the desired angle or direction and control the wellbore trajectory. The bend in the housing is dialled in at the drill floor when the drilling crew makes up the BHA. Larger bend in the housing can create a curve with a smaller radius. While the illustrated embodiment depicts a single curve 118, it is contemplated that other environments of the present system comprise a plurality of curves and a plurality of deviated horizontal sections, depending upon embodiments.

Referring now to FIG. 2, there is shown a component level view of an illustrative programmable logic controller system (PLC) or a computing device comprising an HMI, in accordance with embodiments of the disclosure. It is noted that the PLC 108 as described herein can operate with more or fewer of the components shown herein. Additionally, the PLC 108 as shown herein or portions thereof can serve as a representation of one or more of the computing devices of the present system. The PLC 108 can include a communication interface 202, one or more processors 204, hardware 206, and memory unit 214. The communication interface 202 includes wireless and/or wired communication components that enable the PLC 108 to transmit data to and receive data from other devices or components of a drilling system as shown in FIG. 1.

The hardware 206 can include additional user interface, data communication, or data storage hardware. For example, the user interface of the hardware components 206 includes input/output (I/O) devices 208. In various embodiments, the I/O devices 208 can include any sort of output devices known in the art, such as a display (e.g., a liquid crystal display), speakers, a vibrating mechanism, or a tactile feedback mechanism. Output devices also include ports for one or more peripheral devices, such as headphones, peripheral speakers, or a peripheral display. In various embodiments, the I/O devices 208 include any sort of input devices known in the art. For example, input devices may include a camera, a microphone, a keyboard/keypad, a mouse, or a touch-sensitive display. A keyboard/keypad may be a push button numeric dialing pad (such as on a typical telecommunication device), a multi-key keyboard (such as a conventional QWERTY keyboard), or one or more other types of keys or buttons, and may also include a joystick-like controller and/or designated navigation buttons, or the like. The PLC 108 further comprises one or more processors 204. The processors 204 can comprise a central processing unit (CPU), a graphics processing unit (GPU), or both CPU and GPU, or any other sort of processing unit.

The PLC 108 further comprises a system memory 214, wherein the memory 214 may be implemented using computer-readable media, such as computer storage media. Computer-readable media includes, at least, two types of computer-readable media, namely computer storage media and communications media. Computer storage media includes volatile, non-volatile, or some combination of the two. Computer storage media can also include additional data storage devices (e.g., removable storage 210 and/or non-removable storage 212) implemented in any method or technology for storage of information, such as computer readable instructions, code segments, data structures, program modules, or other data. Thus, computer-readable storage media include, but are not limited to, RAM, ROM, EEPROM, flash memory or other memory technology, CD-ROM, digital versatile disks (DVD), or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other medium which can be used to store the desired information and which can be accessed by the PLC 108. Any such tangible computer-readable media may be part of the PLC 108. In contrast, communication media may embody computer-readable instructions, code segments, data structures, program modules, or other data in a modulated data signal, such as a carrier wave, or other transmission mechanisms.

The processors 204 and the memory 214 can implement an operating system 216 in order to operate as control circuitry to control the operation of the system of FIG. 1 and execute any methods disclosed herein. It is noted that other modules or data (not pictured) stored in the system memory 214 can comprise any sort of applications or platform components of the PLC 108, as well as data associated with such applications or platform components. For example, the system memory 214 can comprise a calculation module 220 for computing an equivalent number of twists in the drill pipe to automatically compute the amplitude or the period based on an input period or amplitude of a harmonic torsional oscillation of the top drive or the kelly.

The system memory 214 can also comprise a validation module for validating calculated or realized values or input values from a human operator or an automated system. The system memory 214 can also comprise a feedback module 222 for monitoring the operations of the drilling system. In various embodiments, the feedback module 222 is configured to receive data from one or more sensors coupled to the MWD and/or LWD tools of the drillstring to monitor the operations of the drilling system. The operating system 216 can include components that enable the PLC 108 to receive and transmit data via interfaces (e.g., user controls, communication interface, and/or input/output devices), as well as process data using the processors 204 to generate output. The operating system 216 can include a presentation component that presents the output (e.g., display the data on an electronic display, store the data in memory, transmit the data to another electronic device, etc.). Additionally, the operating system 216 can include other components that perform various additional functions generally associated with an operating system.

In various embodiments, the PLC 108 comprises an HMI 218 that enables an operator to interact with one or more components of the present system. For example, the HMI 218 comprises a home screen that comprises a navigation bar to enable the operator to access a friction test screen, a manual control screen, and a setup screen. The home screen comprises various fields for receiving user input. For example, the home screen comprises a toggle switch to enable a variable-frequency drive (VFD) motor control system, a dropdown menu to select the system mode (e.g., oscillation mode, friction test mode, manual mode), an emergency stop button for stopping the operation of the drilling system, and a time series showing a series of data points related to commanded RPM indexed in time order. The VFD motor control system coupled to one or more motors, wherein the one or more motors can be coupled to a top drive or a kelly. The HMI allows an operator to drive the one or more motors by varying the frequency and voltage supplied to the electric motor, whereby frequency is directly related to the motors' RPMs. In various embodiments, each of the one or more motors can be coupled to its own PLC.

The friction test screen displays a field for receiving a drillstring length input, a pipe size selector for receiving a pipe size input, a friction test activation button, a friction test status, a first time series comprising a series of data points related to RPM indexed in time order, and a second time series comprising a series of data points related to torque indexed in time order. The manual control screen displays a manual mode status, an RPM set point input, a toggle switch for specifying directional setting (e.g., backward, forward, etc.), and a time series showing a series of data points related to commanded RPM indexed in time order. The system setup screen displays a maximum top drive RPM setting, an oscillation period setting, and a run time setting.

FIG. 3 shows an example workflow for a drilling system, according to aspects of the present disclosure. A main PLC 108 is operatively connected to a drilling system 314, which comprises a drillstring 114 that is coupled to a top drive or a kelly 104 comprising a motor 320. The top drive or the kelly 104 an also include a quill 328, which can also be connected to the motor 320. The motor 320 can be operatively connected to a VFD 318, which can be coupled to its own VFD PLC 316. In various embodiments, the VFD 318 can be directly connected to the main PLC 108. In this regard, the VFD 318 can operate when enabled or upon receiving instructions or commands from the HMI 218. The VFD 318 is configured to control the motor 320 by varying a frequency, voltage, and/or pulse width modulated signal supplied to the motor 320. The VFD PLC 316 can be communicably coupled with the main PLC 108. In various embodiments, the PLC 108 can determine desired motor parameters or schemes such as how the motor 320 is started or stopped under normal or special conditions, how to accelerate or decelerate the motor, torque, shaft speed, and/or so forth. The VFD PLC 318 can transmit motor parameters from the main PLC 108 to the VFD 318. Based at least partially on the motor parameters, the VFD 318 can determine the frequency, voltage, and/or pulse width modulated signal to transmit to the motor 320.

The drillstring 114 is further coupled to a BHA 326, MWD and/or LWD tools 322, the MWD and/or LWD tools 322 comprising one or more sensors 324 (e.g., surface sensors) for monitoring downhole conditions during drilling operations. The PLC 108 provides a HMI 218, wherein the HMI 218 can be coupled to the main PLC 108 and/or another PLC such as a remote room controller. The HMI 218 includes various graphical user interface such as a home screen 302, a friction test screen 304, a manual control screen 306, and a set up screen 308. One or more of the screens can be used to input drilling parameters from a human operator and/or an automated system. In various embodiments, drilling parameters can include oscillatory period, frequency of oscillation, amplitude of oscillation, torsional friction, torque, RPM, pipe length, pipe size, and/or so forth.

Additionally, the one or more screens can display operating components and data related to drilling operations in real-time or near-real-time. In this regard, the PLC 108 can receive data pertaining to drilling conditions from the one or more sensors 324 coupled to the MWD and/or LWD tools 322 of the drillstring 114. The PLC 108 can be further connected to a lookup table 310 or another data repository for receiving additional drilling parameters such as torsional friction. The lookup table 310 can be communicably coupled to one or more data sources generated via models 312 or computer-generated models. Additionally, or alternatively, the lookup table 310 can be communicably coupled to one or more data sources comprising at least one log from previous drilling operations, wherein the log can include data pertaining to drilling parameters and/or measurements from the previous drilling operations. The PLC 108 can transmit rotary control signals to the top drive or the kelly 104 via the motor 320 based at least partially on the drilling parameters, data, and/or feedback received from the one or more sensors 324, wherein the data received from the one or more sensors 324 can comprise measured torque and/or RPM of the drillstring 114 and/or the BHA 326, as well as downhole conditions and/or downhole drilling characteristics. The sensors 324 can thus provide feedback to the PLC 108 to determine whether the drillstring and/or the BHA is stationary. Based on the feedback received at the PLC 108, the VFD 318 can adjust the frequency, voltage, and/or pulse width modulated signal to transmit to the motor 320. In various embodiments, feedback from the sensors 324 can also be used to modulate the rotary control signal is to achieve a user-defined surface quill orientation, wherein the orientation can be defined at the HMI 218. Thus, the rotary control signal imparted on the top drive or the kelly 104 also allows an operator to adjust or maintain the orientation of the quill.

FIGS. 4 and 5 present illustrative processes 400-500 for imparting a harmonic rotary motion from the top drive or the kelly to rotate the drillstring. The processes 400-500 are illustrated as a collection of blocks in a logical flow chart, which represents a sequence of operations that can be implemented in hardware, software, or a combination thereof. In the context of software, the block can represent computer-executable instructions or code segments that, when executed by one or more processors, perform the recited operations. Generally, computer-executable instructions or code segments may include routines, programs, objects, components, data structures, and the like that performs particular functions or implement particular abstract data types. The order in which the operations are described herein is not intended to be construed as a limitation, and any number of the described blocks can be combined in any order and/or in parallel to implement the process. For discussion purposes. The processes 400-500 are described with reference to the architecture 100 of FIG. 1.

At block 402 the computing device, via for example, a calculation module, determines the total torsional friction along the drillstring. This value is obtained using one of the following methods as indicated in FIG. 5. At block 502, the total friction can be estimated using the recorded release torque at the drill bit, wherein the torque and rotation imparted on the drillstring is transferred to the drill bit. Alternatively, at block 504, the total friction value can be obtained from a lookup table generated prior to operations using data from other wellbores or from modeling (i.e., computational models). Alternatively, at block 506, the total friction value can be manually input by a driller or a remote operator via a HMI.

At decision block 508 the value input is validated, via for example, a validation module, to fall within a predetermined or specified range and carries displayed units. In this regard, the calculation module can be operatively connected to the validation module. The processor may change the units of the value during the calculation. The total friction value can be saved in the memory, a machine-readable medium, or a database within the system to be used by the proceeding steps as maximum torque, T_max (e.g., maximum torque measured via one or more sensors during the first sixty seconds as the estimate of the torsional friction along the drillstring).

Turning back to FIG. 4, at block 404, the computing device obtains the desired period or frequency of rotary oscillation from the driller, the remote operator, or an automated drilling system. Some embodiments of the system may obtain the desired amplitude of rotary oscillation in lieu of the desired period. At block 406, the computing device, via the calculation module, computes the equivalent twist stored within the drillstring using the relation according to Equation 1 below.

${\theta }_{\mathrm{twist}}=\frac{L_{\mathrm{drillpipe}}{\tau }_{\mathrm{ma}x}}{J_{\mathrm{drillpipe}}G_{\mathrm{steel}}}=\frac{32L_{\mathrm{drillpipe}}{\tau }_{m\mathrm{ax}}}{\pi G_{\mathrm{steel}}\left({\mathrm{OD}}^4-{\mathrm{ID}}^4\right)}$

where L_drillpipe is the drill pipe length, τ_max is the maximum shear stress, J_drillpipe is the torsion constant of the drill pipe, G_steel is the shear modulus or the rigidity modulus of steel, OD is an outer diameter of the drill pipe, and ID is an inner diameter of the drill pipe. The calculation module can receive the drill pipe length input from the driller or the remote operator, at the friction test screen of the HMI. Similarly, the outer diameter and the inner diameter of the drill pipe can be input from the driller or the remote operator at the friction test screen of the HMI. The shear modulus or the rigidity modulus value of steel can be obtained from a lookup table or another data source. One of ordinary skill in the art will appreciate, however, that equivalent twist can be calculated in any number of appropriate ways. Thus, various drilling parameters can be used to compute the equivalent twist.

At block 408, the computing device, via the calculation module, utilizes the equivalent twist value in order to compute the amplitude of rotary oscillation, or the frequency in some embodiments, using the relation as depicted in Equations 2 and 3 below, respectively.

$A={\theta }_{\mathrm{twist}}\pi f\mathrm{or}f=\frac{A}{{\theta }_{\mathrm{twist}}\pi }$

At block 410, the computing device, via the calculation module, continuously computes the rotary control signal based on the amplitude of rotary oscillation for the top drive or the kelly using the relation as depicted in Equation 4 below:

RPM=SF·A sin(f(t−t₀)+ϕ)

where SF is a safety factor chosen to be between 0.7 and 0.9, ϕ is a time shifting constant, t is the current time in seconds and t₀ is the time, in seconds, since the system was activated. One of ordinary skill in the art will appreciate, however, that the amplitude of rotary oscillation and the frequency can be calculated in any number of appropriate ways. At block 412, the computing device, via a feedback module, monitors the sensor(s) of the LWD and MWD tools of the drillstring to ensure the BHA does not rotate due to system operation. If the BHA rotates or is not stationary, the amplitude of rotary oscillation is reduced to generate a new rotary control signal until the BHA is stationary.

The foregoing descriptions of specific embodiments of the present invention have been presented for purposes of illustration and description. They are not intended to be exhaustive or to limit the present invention to the precise forms disclosed, and obviously, many modifications and variations are possible in light of the above teaching. The exemplary embodiment was chosen and described in order to best explain the principles of the present invention and its practical application, to thereby enable others skilled in the art to best utilize the present invention and various embodiments with various modifications as are suited to the particular use contemplated.

Claims

1. A method for imparting a harmonic rotary oscillation to a drillstring during a wellbore construction process, comprising the steps of:

determining an estimate of a torsional friction along a drillstring of a drilling system to determine a desired amplitude of a rotary oscillatory motion based at least partially on drilling parameters comprising an oscillatory period or frequency transmitted to at least one motor coupled to the drilling system;

generating a rotary control signal based at least partially on the desired amplitude of the rotary oscillatory motion when the drilling system is activated;

transmitting the rotary control signal to the at least one motor via a variable-frequency drive (VFD); and

monitoring the drilling system to determine whether a bottom hole assembly (BHA) of the drilling system remains stationary, the BHA coupled to the drillstring.

2. The method of claim 1, further comprising the steps of:

reducing the desired amplitude of the rotary oscillatory motion upon detecting that the BHA is not stationary; and

transmitting a new rotary control signal based at least partially on the reduced amplitude of the rotary oscillatory motion.

3. The method of claim 1, wherein the determining comprises the steps of:

prescribing the rotary control signal to the drilling system starting from the drillstring when the BHA is stationary;

sensing recorded torque from the drillstring of the drilling system; and

recording a maximum torque sensed during a predetermined time period to determine an estimate of the torsional friction along the drillstring.

4. The method of claim 1, further comprising the steps of:

obtaining the torsional friction from a lookup table comprising data from a generated model of the drilling system based at least partially on a set of downhole measurements and the drilling parameters of the drilling system.

5. The method of claim 1, wherein the monitoring comprises the steps of:

monitoring rotations per minute (RPM) and torque of the drillstring.

6. The method of claim 1, wherein the oscillatory period or the frequency is manually input by a remote human operator.

7. The method of claim 1, wherein the oscillatory period or the frequency is automatically input via an automatic system.

8. The method of claim 1, further comprising the steps of:

determining an equivalent twist stored within the drillstring, the equivalent twist based at least partially on the torsional friction along the drillstring.

9. A drilling system for wellbore construction, comprising:

a drillstring comprising a drill bit coupled to a bottom-hole-assembly (BHA);

a top drive coupled to a surface end of the drillstring, wherein the top drive is configured to rotate the drillstring upon receiving an input signal from a controller; and

one or more sensors coupled to the drillstring and the controller, wherein the one or more sensors is configured to detect rotation or torque in the drillstring.

10. The system of claim 9, wherein the controller comprises one or more nontransitory storage mediums configured to provide stored code segments, the one or more nontransitory storage mediums coupled to one or more processors, each configured to execute the code segments and causing the one or more processors to:

receive a desired oscillatory period or frequency;

compute an amplitude of oscillation based at least partially on an estimated torsional friction and the oscillatory period or the frequency;

transmit a rotary control signal to the top drive, the rotary control signal based at least partially on the amplitude of oscillation;

receive torque and realized rotations per minute (RPM) of the drillstring from the one or more sensors; and

determine whether the BHA is stationary.

11. The system of claim 10, wherein the one or more processors is further configured to transmit the rotary control signal based at least partially on feedback received from the one or more sensors.

12. The system of claim 10, wherein the torsional friction is validated via the controller.

13. The system of claim 10, wherein the one or more processors is further configured to provide a human machine interface (HMI).

14. The system of claim 9, wherein the one or more sensors is operable to provide real-time downhole conditions and downhole drilling characteristics, the downhole conditions comprising formation resistivity, permeability, and the downhole drilling characteristics comprising a rate of rotation of the drill bit, a torque-on-bit (TOB), and a weight on the bit (WOB).

15. The system of claim 10, wherein the one or more processors is further configured to receive a user-defined surface quill orientation and transmit the rotary control signal based at least partially on feedback received from the one or more sensors in order to achieve the user-defined surface quill orientation.

16. The system of claim 9, wherein the one or more sensors is coupled to measurement while drilling (MWD) tools and/or logging while drilling (LWD) tools.

17. The system of claim 9, further comprising a bent housing motor assembly coupled to the drill bit, wherein an angular position of the bent housing motor can be altered to allow geo-steering operations.

18. One or more non-transitory computer-readable media storing computer-executable instructions that upon execution cause one or more processors to perform acts comprising:

estimating a torsional friction along a drillstring of a drilling system to determine an amplitude of a rotary oscillatory motion based at least partially on an oscillatory period or frequency;

transmitting a rotary control signal to the drilling system based at least partially on the amplitude of the rotary oscillatory motion when the drilling system is activated;

monitoring rotations per minute (RPM) and torque of the drilling system to determine whether a bottom hole assembly (BHA) coupled to the drillstring of the drilling system remains stationary; and

reducing the amplitude of the rotary oscillatory motion upon determining that the BHA is not stationary.

19. The one or more non-transitory computer-readable media of claim 18, wherein the acts further comprise:

validating the torsional friction, the torsional friction derived from a lookup table comprising data from a generated model of the drilling system based at least partially on a set of downhole measurements and the drilling parameters of the drilling system, the downhole measurements obtained from one or more sensors coupled to the drillstring.

20. The one or more non-transitory computer-readable media of claim 18, wherein the transmitting comprises:

transmitting the rotary control signal to a top drive coupled to the drillstring to impart torque and rotation to the drillstring, wherein torque and rotation imparted on the drillstring is transferred to the BHA and a drill bit coupled to the drill string, causing both to rotate.