Patent Application
20200024901
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.
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.
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.
Referring now to
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
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
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.
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.
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
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, Tmax (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
where Ldrillpipe is the drill pipe length, τmax is the maximum shear stress, Jdrillpipe is the torsion constant of the drill pipe, Gsteel 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.
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.
