INTEGRATED MODELLING, ESTIMATION, AND CONTROL OF WEIGHT-ON-BIT AND STEERING FORCE IN DIRECTIONAL DRILLING

Abstract

Systems and methods are provided for performing directional drilling. An example method can include receiving, by a surface controller, a well plan for performing directional drilling of a wellbore; receiving, by the surface controller, an estimate for at least one drilling parameter that is based on a model of a bottom hole assembly (BHA) configured to perform directional drilling of the wellbore; and determining, by the surface controller, a steering force and a weight-on-bit (WOB) for drilling the wellbore, wherein the steering force and the WOB are based on the well plan and the estimate for the at least one drilling parameter.

Description

TECHNICAL FIELD

The present disclosure relates generally to wellbore operations and, more specifically (although not necessarily exclusively), to systems and techniques for modelling, estimating, and controlling weight-on-bit and steering force in directional drilling.

BACKGROUND

Wells can be drilled to access and produce hydrocarbons such as oil and gas from subterranean geological formations. Wellbore operations can include drilling operations, completion operations, fracturing operations, and production operations. Drilling operations may involve gathering information related to downhole geological formations of the wellbore. The information may be collected by wireline logging, logging while drilling (LWD), measurement while drilling (MWD), drill pipe conveyed logging, or coil tubing conveyed logging.

BRIEF DESCRIPTION OF THE DRAWINGS

The various advantages and features of the present technology will become apparent by reference to specific implementations illustrated in the appended drawings. A person of ordinary skill in the art will understand that these drawings only show some examples of the present technology and would not limit the scope of the present technology to these examples. Furthermore, the skilled artisan will appreciate the principles of the present technology as described and explained with additional specificity and detail through the use of the accompanying drawings in which:

FIG. 1 is a diagram of an illustrative drilling system, in accordance with aspects of the present disclosure;

FIG. 2 is a block diagram of an illustrative framework for modelling, estimating, and controlling weight-on-bit and steering force in directional drilling, in accordance with aspects of the present disclosure;

FIG. 3 is a diagram illustrating an aspect of a directional drilling model, in accordance with aspects of the present disclosure;

FIG. 4 is a flowchart of an illustrative process for modelling, estimating, and controlling weight-on-bit and steering force in directional drilling, in accordance with aspects of the present disclosure; and

FIG. 5 is a block diagram illustrating an example computing device architecture, in accordance with aspects of the present disclosure.

DETAILED DESCRIPTION

The detailed description set forth below is intended as a description of various configurations of the subject technology and is not intended to represent the only configurations in which the subject technology can be practiced. The appended drawings are incorporated herein and constitute a part of the detailed description. The detailed description includes specific details for the purpose of providing a more thorough understanding of the subject technology. However, it will be clear and apparent that the subject technology is not limited to the specific details set forth herein and may be practiced without these details. In some instances, structures and components are shown in block diagram form in order to avoid obscuring the concepts of the subject technology.

Directional drilling, or controlled steering, is used to guide drilling tools in the oil, water, and gas industries to reach resources that are not located directly below a wellhead. Directional drilling particularly provides access to reservoirs where vertical access is difficult if not impossible. In general, directional drilling refers to steering a drilling tool according to a predefined well path plan, having target coordinates and drilling constraints, created by a multidisciplinary team (e.g., reservoir engineers, drilling engineers, geo-steerers, geologists, etc.) to optimize resource collection/discovery.

Current models for directional drilling include both empirical and first-principle delay deferential equation (DDE) models. While empirical models are capable of swift operation, a lack of underlying physical principles can result in an overabundance of parameters that are characterized by uncertainty, which can complicate accurate online estimation. Further, the computational intensity that is associated with high-fidelity DDE models results in a significant burden that can make such models unsuitable for practical control applications. Additionally, current models for directional drilling fail to simultaneously account for both weight on bit (WOB) and steering force. Models that focus on steering force can yield sub-optimal performance with respect to rate of penetration as well as dogleg severity.

The disclosed technology addresses the foregoing by providing systems and techniques for modelling, estimating, and controlling weight-on-bit and steering force in directional drilling. The present disclosure provides a framework for coordinated control of WOB and steering force. In some aspects, the framework includes a high fidelity, first-principal model that is characterized by rapid computational speed and minimal uncertainty. In some configurations, the model can utilize an estimation methodology for predicting one or more drilling parameters. That is, the model is capable of reducing the uncertainty to a single drilling parameter that can be estimated based on drilling plan and revised during drilling based on sensor measurements. In some aspects, the present technology can include a model predictive controller that is configured to manage drilling controls such as WOB, steering force, and phase.

In some examples, the present technology can include a framework that simplifies the complex, nonlinear DDE model, which can reduce the state from a quantity equivalent to the number of stabilizers plus one down to a solitary state. Further, uncertainties can be consolidated into one or more drilling parameters and estimation methods can be used to determine the consolidated drilling parameter in real-time.

The present technology provides a model controller that can be used to generate an optimal drilling solution that concurrently minimizes the reference tracking error and can maximize the WOB in order to increase the rate of penetration and improve drilling efficiency.

FIG. 1 is a schematic diagram of a directional drilling environment, particularly showing a measurement-while-drilling (MWD) system 100, in which the present technology may be deployed. As depicted, the MWD system 100 includes a drilling platform 102 having a derrick 104 and a hoist 106 to raise and lower a drill string 108. In some examples, hoist 106 can suspend a top drive 110 (e.g., via a hook and/or swivel—not illustrated) suitable for rotating drill string 108 and lowering drill string 108 through a well head 112. In some aspects, drill string 108 may include sensors or other instrumentation for detecting and logging nearby characteristics and conditions of the wellbore and surrounding earth formation.

In operation, top drive 110 supports and rotates drill string 108 as it is lowered through well head 112. In this fashion, drill string 108 (and/or a downhole motor) can rotate a drill bit 114 coupled with a lower end of drill string 108 to create a borehole 116 through various formations. A pump 120 can circulate drilling fluid through a supply pipe 122 to top drive 110, down through an interior of drill string 108, through orifices in drill bit 114, back to the surface via an annulus around drill string 108, and into a retention pit 124. The drilling fluid can transport cuttings from wellbore 116 into retention pit 124 and can help maintain wellbore integrity. Various materials can be used for drilling fluid, including oil-based fluids and water-based fluids.

As shown, drill bit 114 forms part of a bottom hole assembly 150, which further includes drill collars (e.g., thick-walled steel pipe) that provide weight and rigidity to aid drilling processes. In some configurations, detection tools 126 and a telemetry sub 128 can be coupled to or integrated with one or more drilling collars. In some aspects, bottom hole assembly 150 may include stabilizers, shock absorbers, reamers, hole-openers, a bit sub, etc.

In some aspects, detection tools 126 may gather MWD survey data or other data and may include various types of electronic sensors, transmitters, receivers, hardware, software, and/or additional interface circuitry for generating, transmitting, and detecting signals (e.g., sonic waves, etc.), storing information (e.g., log data), communicating with additional equipment (e.g., surface equipment, processors, memory, clocks input/output circuitry, etc.), and the like. For example, detection tools 126 can measure data such as position, orientation, weight-on-bit, strains, movements, borehole diameter, resistivity, drilling tool orientation, which may be specified in terms of a tool face angle (rotational orientation), inclination angle (the slope), compass direction, and/or azimuth angle, each of which can be derived from measurements by sensors (e.g., magnetometers, inclinometers, and/or accelerometers, though other sensor types such as gyroscopes, etc.).

In some cases, telemetry sub 128 can communicate with detection tools 126 and transmits telemetry data to surface equipment (e.g., via mud pulse telemetry). For example, telemetry sub 128 can include a transmitter to modulate resistance of drilling fluid flow thereby generating pressure pulses that propagate along the fluid stream at the speed of sound to the surface. One or more pressure transducers 132 can operatively convert the pressure pulses into electrical signal(s) for a signal digitizer 134. It is appreciated that other forms of telemetry such as acoustic, electromagnetic, telemetry via wired drill pipe, and the like may also be used to communicate signals between downhole drilling tools and signal digitizer 134. Further, it is appreciated that telemetry sub 128 can store detected and logged data for later retrieval at the surface when bottom hole assembly 150 is recovered.

In some instances, digitizer 134 can convert the pressure pulses into a digital signal and sends the digital signal over a communication link to a computing system such as surface controller 137. In some aspects, surface controller 137 can include processing units to analyze collected data and/or perform other operations by executing software or instructions obtained from a local or remote non-transitory computer-readable medium. For instance, surface controller 137 can be used to implement models and/or algorithms (e.g., data-based algorithms, physics-based algorithms, machine learning algorithms, etc.) that can be used to model and control the weight-on-bit and the steering force in order to autonomously execute a drilling plan.

In some examples, surface controller 137 can include or otherwise communicate with a directional drilling model (e.g., a borehole propagation model) that can be used to determine drill string trajectory based on the configuration of bottom hole assembly 150, the pad force (e.g., lateral force or steering force), and the weight on bit (e.g., axial force). In some cases, surface controller 137 can include or otherwise communicate with a drilling parameter estimation model that can be used to estimate one or more drilling parameters (e.g., side cutting efficiency) based on the directional drilling model. In some aspects, surface controller 137 can include or otherwise communicate with a model controller that can use the well plan and the information from the directional drilling model and/or the drilling parameter estimation model to determine the weight on bit, the pad force, the inclination angle, and/or the azimuth angle for steering drill bit 114 along a trajectory that corresponds to the well plan (e.g., desired path 119).

In some aspects, surface controller 137 can modify the weight on bit, the pad force, the inclination angle, and/or the azimuth angle based on data received from detection tools 126 (e.g., measured bit position, estimated bit position, bit force, bit force disturbance, rock mechanics, etc.). That is, data received from detection tools 126 can be used to update parameters of the directional drilling model and/or the drilling parameter estimation model in order to determine updated values for the weight on bit, the pad force, the inclination angle, and/or the azimuth angle. In some configurations, surface controller 137 can include input device(s) (e.g., a keyboard, mouse, touchpad, etc.) as well as output device(s) (e.g., monitors, printers, etc.).

As noted above, MWD system 100 can also include a downhole controller 152 that receives instructions from surface controller 137 in order to steer bottom hole assembly 150 as drill bit 114 extends wellbore 116 along a desired path 119 (e.g., within one or more boundaries 140). The bottom hole assembly 150 includes a steering system, such as steering vanes, bent stub, or rotary steerable system (RSS), thereby together with the drill bit 114 form a directional drilling tool. Downhole controller 152 includes processors, sensors, and other hardware/software and which may communicate to components of the steering system. For instance, with a RSS, the downhole controller 152 applies a force to flex or bend a drilling shaft coupled to bottom hole assembly 150, or by steering pads on the outside of a non-rotating housing, imparts an angular deviation to control the direction traversed by drill bit 114. Downhole controller 152 can communicate real-time data with one or more components of bottom hole assembly 150 and/or surface controller 137. In this fashion, downhole controller 152 can receive real-time steering signals from surface controller 137 according to, for example, pad force (e.g., steering force) as discussed herein. It is further appreciated by those skilled in the art, the environment shown in FIG. 1 is provided for purposes of discussion only, not for purposes of limitation. The detection tools, drilling devices, and optimal trajectory control techniques discussed herein may be suitable in any number of drilling environments.

FIG. 2 is a block diagram of an illustrative framework 200 for modelling, estimating, and controlling weight-on-bit and steering force in directional drilling, in accordance with aspects of the present disclosure. In some examples, the framework 200 may include a directional drilling model 202. In some examples, directional drilling model 202 can correspond to a physics-based model that can be used to determine drill string trajectory based on bottom hole assembly (BHA) configuration 204. In some aspects, directional drilling model 202 can be configured based on a nonlinear delay differential equation (DDE) model that considers factors such as floating stabilizers and bit tilt saturation, articulated according to Equation 1, as follows:

$\begin{array}{cc}{\Theta }^{\prime }={\sum }_{i=1}^n{a}_i\left({\langle \Theta \rangle }_i-\Theta \right)+{\sum }_{i=1}^{n-1}{b}_i{F}_i+c_1\Gamma +c_{2}w\sin {\langle \Theta \rangle }_1& \left(1\right)\end{array}$

In Equation 1, θ corresponds to the bit inclination; Θ_i corresponds to the average borehole inclination between stabilizer i-1 to stabilizer i; F_i corresponds to the stabilizer contact forces; Γ corresponds to the steering force; w corresponds to the buoyant weight per unit length; a_i, b_i, c₁, and c₂ correspond to coefficients determined by the BHA configuration 204, WOB without frictional loss, and parameters with uncertainty.

In some aspects, directional drilling model 202 can be simplified by assuming a uniform borehole curvature over the length of the BHA. That is, in some examples, borehole curvature can be approximated using one or more approximation techniques (e.g., constant curvature, average angle, minimum curvature, etc.). In some instances, such an approximation for a uniform borehole curvature can be used to reduce computational cost. In some examples, directional drilling model 202 may also be implemented using a non-uniform curvature.

FIG. 3 illustrates an example in which the BHA 302 within borehole 304 has a uniform curvature 306 over the length of the BHA 302. Based on the assumption illustrated in FIG. 3, the additional states (O); Equation (1) can be eliminated using the following relationship from Equation (2):

$\begin{array}{cc}{\langle \Theta \rangle }_i=\Theta +{\Theta }^{\prime }\left(\frac{{\lambda }_i}{2}-{\sum }_{k=1}^i{\lambda }_k\right)& \left(2\right)\end{array}$

Further, the derivative of the slowing varying bit tilt, d′ can be removed.

$\begin{array}{cc}{\Theta }^{\prime }={\Theta }^{\prime }+{\psi }^{\prime }={\theta }^{\prime }& \left(3\right)\end{array}$

Further, the overall dynamics of the system can be expressed with one state, as per Equation (4):

$\begin{array}{cc}{\Theta }^{\prime }=\alpha \left({\sum }_{i=1}^{n-1}{b}_i{F}_i+c_1\Gamma +c_{2}w\sin \Theta +\overline{\alpha }\psi \right)& \left(4\right)\end{array}$

In Equation (4), α and α are a function of WOB, bit design and BHA configuration; and F_i and ψ are associated with the configuration of the BHA/wellbore contact, which can be calculated by the linear complementary problem solver at each step.

In some aspects, the bit inclination within a practical implementation is affected by factors (e.g., drilling parameters) apart from WOB and steering force. For instance, factors such as transmission loss of WOB, borehole diameter, rock hardness, bit cutter layout, bit tilt saturation angle, etc. can affect the bit inclination. In some examples, framework 200 can include a drilling parameter estimation model 206 that can be used to model such factors or drilling parameters. For instance, in some cases, empirical values of one or more drilling parameters can be incorporated into the model such that the uncertain fluctuations of the drilling parameters can be consolidated into the variability of η, which represents the generalized side cutting efficiency. In some cases, an estimation method (e.g., gradient descent and/or any other suitable estimation method) can be used to determine η.

In some configurations, framework 200 can include model controller 210. In some aspects, model controller 210 can correspond to a multi-output (e.g., one or more outputs) predictive controller for managing drilling controls 212 (e.g., WOB, steering force, phase, etc.). In some cases, model controller 210 can consider the boundaries of WOB and steering forces, and model controller 210 can determine drilling controls 212 for implementing well plan 208 by solving an optimization problem. In one illustrative example, model controller 210 can optimize drilling objectives by minimizing a cost function. An example of a cost function is given by Equation (5), as follows:

$\begin{array}{cc}\text{?}=w_1\frac{\text{?}{\left({\Theta }_i-\text{?}\right)}^2}{n}-W_2\frac{{\sum }_{i=1}^k{\Gamma }_i^2}{k}+w_2\frac{{\sum }_{i=1}^k{\left({\Gamma }_i-\text{?}\right)}^2}{k}& \left(5\right)\end{array}$ $\text{?}\text{indicates text missing or illegible when filed}$

For example, the cost function of Equation (5) can be minimized according to the following:

$\begin{array}{cc}\Theta \left(i+1\right)=f\left(\Theta \left(i\right),\Gamma \left(i\right),\Pi \left(i\right)\right)& \left(6\right)\end{array}$ ${\Gamma }_{\min }\le {\Gamma }_i\le {\Gamma }_{\max }$ ${\Pi }_{\min }\le {\Pi }_i\le {\Pi }_{\max }$

In Equations (5) and (6), Θ is the reference inclination; n is the number of steps for the discretized model f; k is the number of steps for the steering force; w₁, w₂, w₃ are the weighted factors; Π is the WOB; Γ_min, Γ_max are the lower and upper bound of steering force; and Π_min, Π_max are the lower and upper bound of WOB. In some examples, Equation (5) can be used to implement a framework that adheres to the well plan 208 while optimizing the WOB (e.g., resulting in a higher rate of penetration).

In some aspects, the drilling controls 212 can be used to control the drill string trajectory (e.g., borehole propagation 214) in accordance with the well plan 208. For example, the WOB can be controlled by communicating with a braking system (e.g., mechanical brake and/or electromechanical brake) that can be used to take up some of the weight of the drill string. In another example, the steering force can be controlled by sending commands to a downhole controller that is associated with a rotary steerable system (RSS) or any other type of drilling mechanism (e.g., mud motor).

In some cases, sensors (e.g., detections tools 126) can provide sensor data to drilling parameter estimation model 206. That is, downhole sensors can be used to detect real-time data associated with borehole propagation 214. The real-time sensor data can include azimuth of the wellbore, an inclination of the wellbore, a pad force measurement, a WOB measurement, a bit position, and/or any other measurement that may be obtained using a downhole sensor.

In some examples, drilling parameter estimation model 206 can use the sensor data 216 to revise and/or update estimation associated with one or more drilling parameters. For instance, drilling parameter estimation model 206 can use sensor data to estimate side cutting efficiency, which can be based on factors such as borehole diameter, rock hardness, bit cutter layout, bit tilt saturation, etc. that may be included within sensor data 216. Consequently, model controller 210 can dynamically update drilling controls 212 based on sensor data 216. That is, the WOB and/or the steering force can be adjusted based on real-time data to maintain a trajectory that is consistent with the well plan 208.

FIG. 4 illustrates an example of a process 400 for modelling, estimating, and controlling weight-on-bit and steering force in directional drilling, in accordance with aspects of the present disclosure. Although the process 400 depicts a particular sequence of operations, the sequence may be altered without departing from the scope of the present disclosure. For example, some of the operations depicted may be performed in parallel or in a different sequence that does not materially affect the function of process 400. In other examples, different components of an example device or system that implements process 400 may perform functions at substantially the same time or in a specific sequence.

At block 402, the process 400 includes receiving, by a surface controller, a well plan for performing directional drilling of a wellbore. For example, a surface controller such as surface controller 137 can include framework 200 having model controller 210. Model controller 210 can receive well plan 208 for performing directional drilling of a wellbore.

At block 404, the process 400 includes receiving, by the surface controller, an estimate for at least one drilling parameter that is based on a model of a bottom hole assembly (BHA) configured to perform directional drilling of the wellbore. For instance, surface controller 137 can include model controller 210 which can receive an estimate for at least one drilling parameter that is based on a model (e.g., directional drilling model 202) of BHA configuration 204. In some cases, the at least one drilling parameter can correspond to a side cutting efficiency parameter. In some instances, the side cutting efficiency parameter can be considered to compensate an uncertainty in at least one of a WOB transmission loss, a borehole diameter, a borehole length, a rock hardness, a bit cutter layout, a bit tilt saturation angle, a bit wear state, a drill string compression, and a friction parameter. In some aspects, the model of the BHA can be based on a uniform borehole curvature over a length of the BHA (e.g., see FIG. 3). In some examples, the borehole curvature can be approximated based on a constant curvature, an average angle, a minimum curvature, and/or any other suitable approximation technique.

At block 406, the process 400 includes determining, by the surface controller, a steering force and a weight-on-bit (WOB) for drilling the wellbore, wherein the steering force and the WOB are based on the well plan and the estimate for the at least one drilling parameter. For example, surface controller 137 can implement model controller 210 and can determine drilling controls 212, which can include a steering force and a WOB for drilling the wellbore that are based on the well plan 208 and the estimate for the at least one drilling parameter received from drilling parameter estimation model 206. In some examples, the surface controller can be configured to maximize the WOB for drilling the wellbore. In some cases, the surface controller can be configured to maximize the rate of penetration for drilling the wellbore. In some configurations, the estimate for the at least one drilling parameter can be based on a gradient descent algorithm.

In some aspects, the process 400 can include receiving, by the surface controller, a revised estimate for the at least one drilling parameter that is based on the model of the BHA and on one or more sensor measurements; and determining, by the surface controller, an updated steering force and an updated WOB for drilling the wellbore, wherein the updated steering force and the updated WOB are based on the well plan and the revised estimate for the at least one drilling parameter. For instance, surface controller 137 can receive a revised estimate for the at least one drilling parameter from drilling parameter estimation model 206. The revised estimate can be based on the model of the BHA (e.g., directional drilling model 202) and sensor data 216. In some instances, the one or more sensor measurements can include at least one of an azimuth of the wellbore, an inclination of the wellbore, a pad force measurement, a WOB measurement, and a bit position.

In some examples, the process 400 can include determining, by the surface controller, a tool phase for drilling the wellbore, wherein the tool phase is based on the well plan and the estimate for the at least one drilling parameter. For instance, surface controller 137 can use model controller 210 to determine a tool phase for drilling the wellbore, and the tool phase can be based on well plan 208 and the estimate for the drilling parameter(s) received from drilling parameter estimation model 206. In some examples, the tool phase may be used to steer the drilling bit in three-dimensional space. In some cases, the tool phase can be further based on the true vertical depth (e.g., as determined based on sensor data 216).

In some aspects, the surface controller can be coupled to a rotary steering system. In some examples, the surface controller can be coupled to a mud motor.

FIG. 5 illustrates an example computing device architecture 500 which can be employed to perform various steps, methods, and techniques disclosed herein. Specifically, the techniques described herein can be implemented, at least in part, through the computing device architecture 500 in an applicable computing device, such computing device 126 and/or downhole tool 118. The various implementations will be apparent to those of ordinary skill in the art when practicing the present technology. Persons of ordinary skill in the art will also readily appreciate that other system implementations or examples are possible.

As noted above, FIG. 5 illustrates an example computing device architecture 500 of a computing device which can implement the various technologies and techniques described herein. The components of the computing device architecture 500 are shown in electrical communication with each other using a connection 505, such as a bus. The example computing device architecture 500 includes a processing unit (CPU or processor) 510 and a computing device connection 505 that couples various computing device components including the computing device memory 515, such as read only memory (ROM) 520 and random access memory (RAM) 525, to the processor 510.

The computing device architecture 500 can include a cache of high-speed memory connected directly with, in close proximity to, or integrated as part of the processor 510. The computing device architecture 500 can copy data from the memory 515 and/or the storage device 530 to the cache 512 for quick access by the processor 510. In this way, the cache can provide a performance boost that avoids processor 510 delays while waiting for data. These and other modules can control or be configured to control the processor 510 to perform various actions.

Other computing device memory 515 may be available for use as well. The memory 515 can include multiple different types of memory with different performance characteristics. The processor 510 can include any general purpose processor and a hardware or software service, such as service 1 532, service 2 534, and service 3 536 stored in storage device 530, configured to control the processor 510 as well as a special-purpose processor where software instructions are incorporated into the processor design. The processor 510 may be a self-contained system, containing multiple cores or processors, a bus, memory controller, cache, etc. A multi-core processor may be symmetric or asymmetric.

To enable user interaction with the computing device architecture 500, an input device 545 can represent any number of input mechanisms, such as a microphone for speech, a touch-sensitive screen for gesture or graphical input, keyboard, mouse, motion input, speech and so forth. An output device 535 can also be one or more of a number of output mechanisms known to those of skill in the art, such as a display, projector, television, speaker device, etc. In some instances, multimodal computing devices can enable a user to provide multiple types of input to communicate with the computing device architecture 500. The communications interface 540 can generally govern and manage the user input and computing device output. There is no restriction on operating on any particular hardware arrangement and therefore the basic features here may easily be substituted for improved hardware or firmware arrangements as they are developed.

Storage device 530 is a non-volatile memory and can be a hard disk or other types of computer readable media which can store data that are accessible by a computer, such as magnetic cassettes, flash memory cards, solid state memory devices, digital versatile disks, cartridges, random access memories (RAMs) 525, read only memory (ROM) 520, and hybrids thereof. The storage device 530 can include services 532, 534, 536 for controlling the processor 510. Other hardware or software modules are contemplated. The storage device 530 can be connected to the computing device connection 505. In one aspect, a hardware module that performs a particular function can include the software component stored in a computer-readable medium in connection with the necessary hardware components, such as the processor 510, connection 505, output device 535, and so forth, to carry out the function.

For clarity of explanation, in some instances the present technology may be presented as including individual functional blocks including functional blocks comprising devices, device components, steps or routines in a method embodied in software, or combinations of hardware and software.

In some examples the computer-readable storage devices, mediums, and memories can include a cable or wireless signal containing a bit stream and the like. However, when mentioned, non-transitory computer-readable storage media expressly exclude media such as energy, carrier signals, electromagnetic waves, and signals per se.

Methods according to the above-described examples can be implemented using computer-executable instructions that are stored or otherwise available from computer readable media. Such instructions can include, for example, instructions and data which cause or otherwise configure a general purpose computer, special purpose computer, or a processing device to perform a certain function or group of functions. Portions of computer resources used can be accessible over a network. The computer executable instructions may be, for example, binaries, intermediate format instructions such as assembly language, firmware, source code, etc. Examples of computer-readable media that may be used to store instructions, information used, and/or information created during methods according to described examples include magnetic or optical disks, flash memory, USB devices provided with non-volatile memory, networked storage devices, and so on.

Devices implementing methods according to these disclosures can include hardware, firmware and/or software, and can take any of a variety of form factors. Typical examples of such form factors include laptops, smart phones, small form factor personal computers, personal digital assistants, rackmount devices, standalone devices, and so on. Functionality described herein also can be embodied in peripherals or add-in cards. Such functionality can also be implemented on a circuit board among different chips or different processes executing in a single device, by way of further example.

The instructions, media for conveying such instructions, computing resources for executing them, and other structures for supporting such computing resources are example means for providing the functions described in the disclosure.

In the foregoing description, aspects of the application are described with reference to specific examples thereof, but those skilled in the art will recognize that the application is not limited thereto. Thus, while illustrative examples of the application have been described in detail herein, it is to be understood that the disclosed concepts may be otherwise variously embodied and employed, and that the appended claims are intended to be construed to include such variations, except as limited by the prior art. Various features and aspects of the above-described subject matter may be used individually or jointly. Further, examples can be utilized in any number of environments and applications beyond those described herein without departing from the broader spirit and scope of the specification. The specification and drawings are, accordingly, to be regarded as illustrative rather than restrictive. For the purposes of illustration, methods were described in a particular order. It should be appreciated that in alternate examples, the methods may be performed in a different order than that described.

Where components are described as being “configured to” perform certain operations, such configuration can be accomplished, for example, by designing electronic circuits or other hardware to perform the operation, by programming programmable electronic circuits (e.g., microprocessors, or other suitable electronic circuits) to perform the operation, or any combination thereof.

The various illustrative logical blocks, modules, circuits, and algorithm steps described in connection with the examples disclosed herein may be implemented as electronic hardware, computer software, firmware, or combinations thereof. To clearly illustrate this interchangeability of hardware and software, various illustrative components, blocks, modules, circuits, and steps have been described above generally in terms of their functionality. Whether such functionality is implemented as hardware or software depends upon the particular application and design constraints imposed on the overall system. Skilled artisans may implement the described functionality in varying ways for each particular application, but such implementation decisions should not be interpreted as causing a departure from the scope of the present application.

The techniques described herein may also be implemented in electronic hardware, computer software, firmware, or any combination thereof. Such techniques may be implemented in any of a variety of devices such as general purposes computers, wireless communication device handsets, or integrated circuit devices having multiple uses including application in wireless communication device handsets and other devices. Any features described as modules or components may be implemented together in an integrated logic device or separately as discrete but interoperable logic devices. If implemented in software, the techniques may be realized at least in part by a computer-readable data storage medium comprising program code including instructions that, when executed, performs one or more of the method, algorithms, and/or operations described above. The computer-readable data storage medium may form part of a computer program product, which may include packaging materials.

The computer-readable medium may include memory or data storage media, such as random access memory (RAM) such as synchronous dynamic random access memory (SDRAM), read-only memory (ROM), non-volatile random access memory (NVRAM), electrically erasable programmable read-only memory (EEPROM), FLASH memory, magnetic or optical data storage media, and the like. The techniques additionally, or alternatively, may be realized at least in part by a computer-readable communication medium that carries or communicates program code in the form of instructions or data structures and that can be accessed, read, and/or executed by a computer, such as propagated signals or waves.

Other aspects of the disclosure may be practiced in network computing environments with many types of computer system configurations, including personal computers, hand-held devices, multi-processor systems, microprocessor-based or programmable consumer electronics, network PCs, minicomputers, mainframe computers, and the like. Embodiments may also be practiced in distributed computing environments where tasks are performed by local and remote processing devices that are linked (either by hardwired links, wireless links, or by a combination thereof) through a communications network. In a distributed computing environment, program modules may be located in both local and remote memory storage devices.

In the above description, terms such as “upper,” “upward,” “lower,” “downward,” “above,” “below,” “downhole,” “uphole,” “longitudinal,” “lateral,” and the like, as used herein, shall mean in relation to the bottom or furthest extent of the surrounding wellbore even though the wellbore or portions of it may be deviated or horizontal. Correspondingly, the transverse, axial, lateral, longitudinal, radial, etc., orientations shall mean orientations relative to the orientation of the wellbore or tool.

The term “coupled” is defined as connected, whether directly or indirectly through intervening components, and is not necessarily limited to physical connections. The connection can be such that the objects are permanently connected or releasably connected. The term “outside” refers to a region that is beyond the outermost confines of a physical object. The term “inside” indicates that at least a portion of a region is partially contained within a boundary formed by the object. The term “substantially” is defined to be essentially conforming to the particular dimension, shape or another word that substantially modifies, such that the component need not be exact. For example, substantially cylindrical means that the object resembles a cylinder, but can have one or more deviations from a true cylinder.

The term “radially” means substantially in a direction along a radius of the object, or having a directional component in a direction along a radius of the object, even if the object is not exactly circular or cylindrical. The term “axially” means substantially along a direction of the axis of the object. If not specified, the term axially is such that it refers to the longer axis of the object.

Although a variety of information was used to explain aspects within the scope of the appended claims, no limitation of the claims should be implied based on particular features or arrangements, as one of ordinary skill would be able to derive a wide variety of implementations. Further and although some subject matter may have been described in language specific to structural features and/or method steps, it is to be understood that the subject matter defined in the appended claims is not necessarily limited to these described features or acts. Such functionality can be distributed differently or performed in components other than those identified herein. The described features and steps are disclosed as possible components of systems and methods within the scope of the appended claims.

Moreover, claim language reciting “at least one of” a set indicates that one member of the set or multiple members of the set satisfy the claim. For example, claim language reciting “at least one of A and B” means A, B, or A and B.

Statements of the Disclosure Include

Statement 1: A method comprising: receiving, by a surface controller, a well plan for performing directional drilling of a wellbore; receiving, by the surface controller, an estimate for at least one drilling parameter that is based on a model of a bottom hole assembly (BHA) configured to perform directional drilling of the wellbore; and determining, by the surface controller, a steering force and a weight-on-bit (WOB) for drilling the wellbore, wherein the steering force and the WOB are based on the well plan and the estimate for the at least one drilling parameter.

Statement 2: The method of Statement 1, further comprising: receiving, by the surface controller, a revised estimate for the at least one drilling parameter that is based on the model of the BHA and on one or more sensor measurements; and determining, by the surface controller, an updated steering force and an updated WOB for drilling the wellbore, wherein the updated steering force and the updated WOB are based on the well plan and the revised estimate for the at least one drilling parameter.

Statement 3: The method of Statement 2, wherein the one or more sensor measurements include at least one of an azimuth of the wellbore, an inclination of the wellbore, a pad force measurement, a WOB measurement, and a bit position.

Statement 4: The method of any of Statements 1 to 3, wherein the model of the BHA is based on a borehole curvature over a length of the BHA.

Statement 5: The method of Statement 4, wherein the borehole curvature is approximated to be a uniform borehole curvature.

Statement 6: The method of any of Statements 1 to 5, wherein the at least one drilling parameter corresponds to a side cutting efficiency parameter.

Statement 7: The method of Statement 6, wherein the side cutting efficiency parameter is based on at least one of a WOB transmission loss, a borehole diameter, a borehole length, a rock hardness, a bit cutter layout, a bit tilt saturation angle, a bit wear state, a drill string compression, and a friction parameter.

Statement 8: The method of any of Statements 1 to 7, wherein the surface controller is configured to maximize the WOB for drilling the wellbore.

Statement 9: The method of any of Statements 1 to 8, wherein the steering force and the WOB are determined to maximize a rate of penetration.

Statement 10: The method of any of Statements 1 to 9, further comprising: determining, by the surface controller, a tool phase for drilling the wellbore, wherein the tool phase is based on the well plan and the estimate for the at least one drilling parameter.

Statement 11: The method of any of Statements 1 to 10, wherein the estimate for the at least one drilling parameter is based on a gradient descent algorithm.

Statement 12: The method of any of Statements 1 to 11, wherein the surface controller is coupled to a rotary steering system.

Statement 13: The method of any of Statements 1 to 12, wherein the surface controller is coupled to a mud motor.

Statement 14: An apparatus comprising at least one memory; and at least one processor coupled to the at least one memory, wherein the at least one processor is configured to perform operations in accordance with any one of Statements 1 to 13.

Statement 15: An apparatus comprising means for performing operations in accordance with any one of Statements 1 to 13.

Statement 16: A non-transitory computer-readable medium comprising instructions that, when executed by an apparatus, cause the apparatus to perform operations in accordance with any one of Statements 1 to 13.

Statement 17: A method comprising: receiving a model of a bottom hole assembly (BHA) configured to perform directional drilling of a wellbore; receiving one or more sensor measurements from one or more downhole sensors in the wellbore; and determining an estimate for at least one drilling parameter based on the model of the BHA and the one or more sensor measurements.

Statement 18: The method of Statement 17, further comprising: storing the one or more sensor measurements in a historical measurement database.

Statement 19: The method of any of Statements 17 to 18, further comprising: accessing a historical measurement database that includes one or more historical sensor measurements obtained while performing directional drilling of one or more wellbores using the BHA, wherein the estimate for the at least one drilling parameter is further based on at least one historical sensor measurement from the historical measurement database.

Statement 20: An apparatus comprising at least one memory; and at least one processor coupled to the at least one memory, wherein the at least one processor is configured to perform operations in accordance with any one of Statements 17 to 19.

Statement 21: An apparatus comprising means for performing operations in accordance with any one of Statements 17 to 19.

Statement 22: A non-transitory computer-readable medium comprising instructions that, when executed by an apparatus, cause the apparatus to perform operations in accordance with any one of Statements 17 to 19.

Claims

1. A system comprising: a memory; andone or more processors coupled to the memory, the one or more processors being configured to: receive, by a surface controller, a well plan for performing directional drilling of a wellbore;receive, by the surface controller, an estimate for at least one drilling parameter that is based on a model of a bottom hole assembly (BHA) configured to perform directional drilling of the wellbore; anddetermine, by the surface controller, a steering force and a weight-on-bit (WOB) for drilling the wellbore, wherein the steering force and the WOB are based on the well plan and the estimate for the at least one drilling parameter.

2. The system of claim 1, wherein the one or more processors are further configured to: receive, by the surface controller, a revised estimate for the at least one drilling parameter that is based on the model of the BHA and on one or more sensor measurements; anddetermine, by the surface controller, an updated steering force and an updated WOB for drilling the wellbore, wherein the updated steering force and the updated WOB are based on the well plan and the revised estimate for the at least one drilling parameter.

3. The system of claim 2, wherein the one or more sensor measurements include at least one of an azimuth of the wellbore, an inclination of the wellbore, a pad force measurement, a WOB measurement, and a bit position.

4. The system of claim 1, wherein the model of the BHA is based on a borehole curvature over a length of the BHA.

5. The system of claim 1, wherein the at least one drilling parameter corresponds to a side cutting efficiency parameter.

6. The system of claim 5, wherein the side cutting efficiency parameter is estimated to consider an uncertainty in at least one of a WOB transmission loss, a borehole diameter, a borehole length, a rock hardness, a bit cutter layout, a bit tilt saturation angle, a bit wear state, a drill string compression, and a friction parameter.

7. The system of claim 1, wherein the surface controller is configured to optimize the WOB for drilling the wellbore.

8. The system of claim 1, wherein the steering force and the WOB are determined to maximize a rate of penetration.

9. The system of claim 1, wherein the one or more processors are further configured to: determine, by the surface controller, a tool phase for drilling the wellbore, wherein the tool phase is based on the well plan and the estimate for the at least one drilling parameter.

10. The system of claim 1, wherein the estimate for the at least one drilling parameter is based on a gradient descent algorithm.

11. The system of claim 1, wherein the surface controller is coupled to a rotary steering system.

12. The system of claim 1, wherein the surface controller is coupled to a mud motor.

13. A computer-implemented method comprising: receiving, by a surface controller, a well plan for performing directional drilling of a wellbore;receiving, by the surface controller, an estimate for at least one drilling parameter that is based on a model of a bottom hole assembly (BHA) configured to perform directional drilling of the wellbore; anddetermining, by the surface controller, a steering force and a weight-on-bit (WOB) for drilling the wellbore, wherein the steering force and the WOB are based on the well plan and the estimate for the at least one drilling parameter.

14. The computer-implemented method of claim 13, further comprising: receiving, by the surface controller, a revised estimate for the at least one drilling parameter that is based on the model of the BHA and on one or more sensor measurements; anddetermining, by the surface controller, an updated steering force and an updated WOB for drilling the wellbore, wherein the updated steering force and the updated WOB are based on the well plan and the revised estimate for the at least one drilling parameter.

15. The computer-implemented method of claim 14, wherein the one or more sensor measurements include at least one of an azimuth of the wellbore, an inclination of the wellbore, a pad force measurement, a WOB measurement, and a bit position.

16. The computer-implemented method of claim 13, wherein the at least one drilling parameter corresponds to a side cutting efficiency parameter.

17. The computer-implemented method of claim 16, wherein the side cutting efficiency parameter is based on at least one of a WOB transmission loss, a borehole diameter, a borehole length, a rock hardness, a bit cutter layout, a bit tilt saturation angle, a bit wear state, a drill string compression, and a friction parameter.

18. The computer-implemented method of claim 13, wherein the surface controller is configured to maximize the WOB for drilling the wellbore.

19. The computer-implemented method of claim 13, further comprising: determining, by the surface controller, a tool phase for drilling the wellbore, wherein the tool phase is based on the well plan and the estimate for the at least one drilling parameter.

20. A non-transitory computer-readable medium having instructions stored thereon which, when executed by a computer or processor, cause the computer or the processor to: receive, by a surface controller, a well plan for performing directional drilling of a wellbore;receive, by the surface controller, an estimate for at least one drilling parameter that is based on a model of a bottom hole assembly (BHA) configured to perform directional drilling of the wellbore; anddetermine, by the surface controller, a steering force and a weight-on-bit (WOB) for drilling the wellbore, wherein the steering force and the WOB are based on the well plan and the estimate for the at least one drilling parameter.