Duty Cycle Estimation From Bending Moment Magnitude

BACKGROUND

Downhole tools used in drilling oil and gas wells are subjected to extreme environmental and operational parameters. A well may be drilled vertically to a depth of several thousand feet into the earth, exposing tools to very high temperatures, pressures, and caustic fluids. In addition to vertical drilling, downhole tools may be maneuverable and configured to drill along a horizontal direction. Simultaneously, a downhole environment may expose downhole tools to significant forces while drilling comprising large bending, tensile, compression, shear, and torsional forces, along with cyclical loading such as vibration, and complex dynamic patterns such as stick-slip. Therefore, to support drilling operations in a downhole environment and follow a well plan a robust tool design controlled by a Rotary Steerable System (RSS) may be implemented.

An RSS may receive drilling parameter command updates downhole by a steering control system. In examples a steering control system may be located within the RSS or at the surface and communicatively coupled to the RSS by any means. The steering control system may send drilling parameter command updates to the RSS for monitoring and altering drilling parameters. Monitoring and altering drilling parameters is important, especially when a well plan requires an RSS to steer complex maneuvers such as a dog leg. Herein, a dog leg may broadly be defined as when an RSS steers a downhole tool from a vertical drilling direction to a horizontal direction. Dog legs may comprise a variety of parameters such as azimuth or arc length. A dog leg may be the 3D curvature of the wellbore and is created as the resultant of the average rate of change in inclination and azimuth angle.

Similarly, drilling may also comprise parameters which affect how the RSS steers the downhole tool while following the well plan. Examples of drilling parameters may comprise average steering force, side force, or pad force applied downhole, weight on Bit (WOB), Bit RPM, and Flowrate are other parameters that affect the RSS steering ability. Drilling parameters may be monitored and controlled by sending drilling parameter command updates with the steering control system. The drilling parameter command updates of the steering control system may comprise tool driving inputs. To illustrate, steering force may correspond to when altered, update the tool driving input and Duty Cycle. Herein Duty Cycle manipulates the downhole to operate to scale the average steering force based on the Duty Cycle.

Currently, there is no process for the steering control system to determine Duty Cycle applied by the RSS. It is assumed that the Duty Cycle applied by the downhole steering tool is instantaneously applied and equal to the Duty Cycle command given in the surface steering controller, which may not always be true. As such, there are limitations for the steering control system to control the RSS via one or more tool driving inputs as specified by the well plan.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some examples of the present disclosure and should not be used to limit or define the disclosure.

FIG. 1 illustrates a schematic diagram of a drilling system;

FIG. 2 illustrates an example of an information handling system;

FIG. 3 illustrates an example of a chipset;

FIG. 4 illustrates an example of a cloud based computing network;

FIG. 5 illustrates a workflow for controlling a rotary steerable system during a drilling operation;

FIG. 6 illustrates a graph for calculated bending moment data;

FIG. 7 illustrates another workflow for controlling a rotary steerable system during a drilling operation;

FIG. 8 is a graph of the determined of rotary steerable system configurations as either t₁and t₂;

FIG. 9 is a graphical representation of duty cycle comparison over time;

FIG. 10 illustrates an example of raw measurements of bending moment of bit; and

FIG. 11 is a graphical representation of wavelet analysis for denser frequency and coarser frequency.

DETAILED DESCRIPTION

Disclosed herein are systems and methods for determining s Duty Cycle in real time. Additionally, providing an updated Duty Cycle in real time and monitoring its changes to drilling parameters within the steering control system may improve effectiveness for the RSS to follow the well plan. Specifically, the application of an updated real time Duty Cycle may improve the ability for the RSS to perform and create a dog leg within a formation. To determine an iteration of the real time Duty Cycle bending moment measurements at a high frequency close to the bit may be obtained with strain gauge sensors. As a result of the operation configurations of the RSS, different frequency signatures may be determined on the bending moment data when it is generating the net nonzero resultant steering force/side force in a specific direction and when the net steering force/side force is zero in one revolution. Rule-based method, FFT (fast Fourier transform), or some supervised/unsupervised learning method may be applied to classify the time period from the bending moment data when it is generating the steering force in the direction of steering toolface and when the net steering force is zero in the direction of steering tool face. The percentage of time period for the pad force generation can be estimated as the real time Duty Cycle applied downhole. Finally, the estimated real time Duty Cycle may be transmitted to the steering control system within a drilling system.

FIG. 1 illustrates a schematic diagram of a drilling system 100 for real time Duty Cycle estimation according to the disclosure. Herein, real time may be defined as an instantaneous or near instantaneous computation, retention, an/or processing of any type of information. Real time may be within 0.01 ns-1 ns, 1 ns-1 ms, 1 ms-1 s, or 1 s-1, minute, 1 minute-1 day. Generally, the downhole tool could be any tool. The downhole tool in this example comprises a rotary steerable tool (RSS) 130 used in a bottom hole assembly (BHA) 134 to provide directional control while drilling a wellbore 102 from surface 108 of the well site down into a subterranean formation 106. For example, RSS 130 may be a “push the bit” type system that uses coordinated movement of pad pushers against wellbore 102 to urge a drill bit 122 in a particular direction. Alternatively, RSS 130 may be a “point the bit” type system that can adjust the orientation of a drill bit axis relative to a body of RSS 130 to point drill bit 122 in the desired direction. Directional drilling may result in any number of horizontal, vertical, slanted, curved, and other types of wellbore geometries and orientations to achieve a desired wellbore path. After drilling wellbore 102, portions of wellbore 102 may be lined with a tubular, metallic structure referred to as a casing 105. Although certain drawing features of FIG. 1 depict a land-based oil and gas rig, it will be appreciated that the embodiments of the present disclosure are useful with other types of rigs, such as offshore platforms or floating rigs used for subsea wells, and in any other geographical location. For example, in a subsea context, the surface may represent the floor of a seabed, and the rig floor may represent an offshore platform or floating rig over the water above the seabed.

The well site includes a drilling platform 110 with a support structure such as a derrick 112 erected over a wellhead 104 at the surface 108 of the well site. Derrick 112 or other support structure may include equipment for raising and lowering the drill string 116 and other tool strings using in constructing, operating, and maintaining the well. This equipment may include a traveling block 114 used for raising and lowering drill string 116 while drilling and kelly 118 to support drill string 116 as it is lowered through a rotary table 120. Drill string 116 comprises BHA 134 (which includes the RSS 130) and a tubular conveyance extending from surface 108 down into wellbore 102. The tubular conveyance supports the weight of BHA 134 for raising and lowering into the well and provides fluid and/or electrical communication between the tools and surface 108. In this example the tubular conveyance comprises a long string of drill pipe segments that may be progressively added at surface 108 throughout drilling operations in order to reach a desired depth. A pump 124 may circulate drilling fluid (i.e., mud) from a retention pit 132, through a feed pipe 126, downhole through the drill string 116, out through nozzles in a drill bit 122, and back to the surface 108 via an annulus 128 surrounding drill string 116. Rotation of drill bit 122 may be driven by rotation of the entire drill string 116 from surface 108 and/or by rotation of a downhole motor.

Drilling, particularly when using an RSS 130, introduces complex dynamics into drill string 116. Even in a relatively simple scenario of drilling a straight wellbore section, a downhole force is applied axially during drilling, referred to as weight on bit (WOB), while a drill bit is simultaneously rotated at certain revolutions per minute (RPM) to cut the formation. Torque may be applied to the drill string in the desired rotational direction while the drill bit and portions of the drill string encounter competing frictional forces against wellbore 102. Unpredictable or sporadic torsional behavior may result from this interaction, such as stick-slip. Drill string 116 is constrained to follow the deviated wellbore path drilled using RSS 130, which introduces further uncertainty into the dynamic behavior of drill string 116. RSS 130 itself introduces further complexity. For example, in a push-the-bit system, pad pushers are forcefully engaging wellbore 102 to urge drill bit 122 in a lateral direction. The movement of the pad pushers is precisely coordinated to bias in a particular direction. RSS 130 in some systems may also have a counter-rotating housing to remain geostationary while drilling. It can be appreciated that this combination of forces and dynamics while drilling cannot always be fully described with a conventional physics model.

RSS 130 and other components of BHA 134 may comprise measurement assembly 136. Measurement assembly 136 may comprise one or more sensors with transmitters and/or receivers for communicating the collected data. BHA 134, for example, may include a measurement-while drilling (MWD) system for gathering sensor data used to guide drilling and/or a logging-while-drilling (LWD) system to gather information about the formation being drilled. measurement assembly 136 may include any of a variety of dynamic sensors, including but not limited to one or more gyroscopes (i.e., gyros), accelerometers, magnetometers, speed sensors, position sensors, and vibration sensors. A gyroscopes, alternately referred to as a “gyro,” is a device that measures rotational motion. Gyros may be implemented, for example, as MEMS (microelectromechanical system) that measure angular velocity. The units of angular velocity are measured in degrees per second or revolutions per second (RPS). A magnetometer is a scientific instrument that measures the strength and/or direction of a magnetic field. Typically, magnetometers measure a magnetic field or flux density in metric units of gauss (G) or the international system (IS) unit tesla (T). An accelerometer is a sensor that measures acceleration, which is the change in speed (velocity) per unit time. Measuring acceleration makes it possible to obtain information such as object inclination and vibration, force, torque etc. Magnetometers can tell tool inclination and rotating speed. Derivative of rotation speed from gyros and magnetometers can be used for angular acceleration, thus torque and force.

Measurement assembly 136 may also be implemented for measuring downhole parameters, such as pressure, temperature, chemical analysis, and tool orientation. Measurement assembly 136 may comprise vibration sensors that directly sense vibration. In other examples, various dynamic sensors (e.g., gyroscope, accelerometer, and magnetometer) may be analyzed to identify vibrations. Further, measurement assembly 136 may capture high frequency bending moment at the drill bit (BOB) data High frequency BOB data may be from 10 Hz to 10 KHz bending moment data measured at the bit shank. Strain gauges may be used for the measurement which are positioned 120 or 180 degrees apart in the drill collar. The raw measurement of the strain gauges may be calibrated to get Bending Moment.

An information handling system 138 in direct or indirect communication with the BHA 134 may be used to gather, store, process, communicate, and analyze the data from the sensors and other inputs. Additionally, information handling system 138 may be communicatively coupled to a steering control system 150. Steering control system 150 may comprise each and every component and function of information handling system 138. Further, Steering control system 150 may also be in direct or indirect communication with BHA 134 and used to gather, store, process, communicate, and analyze the data from the sensors and other inputs and optionally implemented to control RSS 130 or other BHA 134 components. Steering control system 150 may control RSS 130 or other BHA 134 components to follow a well plan via drilling parameter command updates. Steering control system 150 may be located within BHA 134, on the surface, or comprise components both on the surface and on BHA 134. Further, a well plan may be stored in steering control system 150 or information handling system 138. A well plan may describe the planned trajectory of the well to be drilled. It has information of the Inclination, Azimuth at each Measured Depth (MD) and True Vertical Depth (TVD), and steering capability of the well to be drilled. In addition, it may comprise bit type and design, BHA design, BHA components, Tool Type (RSS, Mud Motor), and/or the like.

In examples steering control system 150 may be located within RSS 130 or at the surface and communicatively coupled to RSS 130 by any means. The steering control system may send drilling parameter command updates to RSS 130 for monitoring and altering drilling parameters. Steering control system 150 and information handling system 138 may comprise various spatially separated components, which may comprise various above-ground components (e.g., at a surface of the well site and/or a remote location) and/or below-ground components, such as a downhole information handling subsystem 138A. Such distributed or spatially separated components may be connected over a network or other suitable electronic communication medium. Thus, processing, storing, and/or analyzing of information may occur at different locations and times, and may occur partially downhole, partially at the surface of the well site, and/or partially at a remote location, such as another well site or a remote data processing center. Sensor data and other information processed downhole may be transmitted to surface to be recorded, observed, and/or further analyzed at the surface or remote site. Additionally, information recorded on information handling system 138 that may be disposed downhole may be stored until RSS 130 may be brought to surface 108. In some examples, the information handling system 138 may communicate with the RSS 130 through a telemetry system (e.g., mud pulse, magnetic, acoustic, wired pipe, or combinations thereof) in real-time mode. Information handling system 138 may transmit information to RSS 130 or BHA 134 and may receive as well as process information recorded by RSS 130 or BHA 134.

Any suitable technique may be used for transmitting signals from BHA 134 to information handling system 138, including, but not limited to, wired pipe telemetry, mud-pulse telemetry, acoustic telemetry, and electromagnetic telemetry. While not illustrated, BHA 134 may include a telemetry subassembly that may transmit telemetry data to information handling system 138. At information handling system 138, pressure transducers (not shown) may convert the pressure signal into electrical signals for a digitizer (not illustrated). The digitizer may supply a digital form of the telemetry signals to information handling system 138 via a communication link 140, which may be a wired or wireless link. The telemetry data may be analyzed and processed by information handling system 138.

As illustrated, communication link 140 (which may be wired or wireless, for example) may be provided that may transmit data from BHA 134 to an information handling system 138 at information handling system 138. Information handling system 138 may include a personal computer 141, a video display 142, a keyboard 144 (i.e., other input devices), and/or non-transitory computer-readable media 146 (e.g., optical disks, magnetic disks) that can store code representative of the methods described herein. In addition to, or in place of processing at surface 108, processing may occur downhole.

FIG. 2 illustrates an example information handling system 138 which may be employed to perform various steps, methods, and techniques disclosed herein. Persons of ordinary skill in the art will readily appreciate that other system examples are possible. As illustrated, information handling system 138 includes a processing unit (CPU or processor) 202 and a system bus 204 that couples various system components including system memory 206 such as read only memory (ROM) 208 and random-access memory (RAM) 210 to processor 202. Processors disclosed herein may all be forms of this processor 202. Information handling system 138 may include a cache 212 of high-speed memory connected directly with, in close proximity to, or integrated as part of processor 202. Information handling system 138 copies data from memory 206 and/or storage device 214 to cache 212 for quick access by processor 202. In this way, cache 212 provides a performance boost that avoids processor 202 delays while waiting for data. These and other modules may control or be configured to control processor 202 to perform various operations or actions. Another system memory 206 may be available for use as well. Memory 206 may include multiple different types of memory with different performance characteristics. It may be appreciated that the disclosure may operate on information handling system 138 with more than one processor 202 or on a group or cluster of computing devices networked together to provide greater processing capability. Processor 202 may include any general-purpose processor and a hardware module or software module, such as first module 216, second module 218, and third module 220 stored in storage device 214, configured to control processor 202 as well as a special-purpose processor where software instructions are incorporated into processor 202.

Processor 202 may be a self-contained computing system, containing multiple cores or processors, a bus, memory controller, cache, etc. A multi-core processor may be symmetric or asymmetric. Processor 202 may include multiple processors, such as a system having multiple, physically separate processors in different sockets, or a system having multiple processor cores on a single physical chip. Similarly, processor 202 may include multiple distributed processors located in multiple separate computing devices but working together such as via a communications network. Multiple processors or processor cores may share resources such as memory 206 or cache 212 or may operate using independent resources. Processor 202 may include one or more state machines, an application specific integrated circuit (ASIC), or a programmable gate array (PGA) including a field PGA (FPGA).

Each individual component discussed above may be coupled to system bus 204, which may connect each and every individual component to each other. System bus 204 may be any of several types of bus structures including a memory bus or memory controller, a peripheral bus, and a local bus using any of a variety of bus architectures. A basic input/output (BIOS) stored in ROM 208 or the like, may provide the basic routine that helps to transfer information between elements within information handling system 138, such as during start-up. Information handling system 138 further includes storage devices 214 or computer-readable storage media such as a hard disk drive, a magnetic disk drive, an optical disk drive, tape drive, solid-state drive, RAM drive, removable storage devices, a redundant array of inexpensive disks (RAID), hybrid storage device, or the like. Storage device 214 may include software modules 216, 218, and 220 for controlling processor 202. Information handling system 138 may include other hardware or software modules. Storage device 214 is connected to the system bus 204 by a drive interface. The drives and the associated computer-readable storage devices provide nonvolatile storage of computer-readable instructions, data structures, program modules and other data for information handling system 138. In one aspect, a hardware module that performs a particular function includes the software component stored in a tangible computer-readable storage device in connection with the necessary hardware components, such as processor 202, system bus 204, and so forth, to carry out a particular function. In another aspect, the system may use a processor and computer-readable storage device to store instructions which, when executed by the processor, cause the processor to perform operations, a method or other specific actions. The basic components and appropriate variations may be modified depending on the type of device, such as whether information handling system 138 is a small, handheld computing device, a desktop computer, or a computer server. When processor 202 executes instructions to perform “operations”, processor 202 may perform the operations directly and/or facilitate, direct, or cooperate with another device or component to perform the operations.

As illustrated, information handling system 138 employs storage device 214, which may be a hard disk or other types of computer-readable storage devices which may store data that are accessible by a computer, such as magnetic cassettes, flash memory cards, digital versatile disks (DVDs), cartridges, random access memories (RAMs) 210, read only memory (ROM) 208, a cable containing a bit stream and the like, may also be used in the exemplary operating environment. Tangible computer-readable storage media, computer-readable storage devices, or computer-readable memory devices, expressly exclude media such as transitory waves, energy, carrier signals, electromagnetic waves, and signals per se.

To enable user interaction with information handling system 138, an input device 222 represents 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. Additionally, input device 222 may take in data from measurement assembly 136, discussed above. An output device 224 may also be one or more of a number of output mechanisms known to those of skill in the art. In some instances, multimodal systems enable a user to provide multiple types of input to communicate with information handling system 138. Communications interface 226 generally governs and manages the user input and system output. There is no restriction on operating on any particular hardware arrangement and therefore the basic hardware depicted may easily be substituted for improved hardware or firmware arrangements as they are developed.

As illustrated, each individual component described above is depicted and disclosed as individual functional blocks. The functions these blocks represent may be provided through the use of either shared or dedicated hardware, including, but not limited to, hardware capable of executing software and hardware, such as a processor 202, that is purpose-built to operate as an equivalent to software executing on a general-purpose processor. For example, the functions of one or more processors presented in FIG. 2 may be provided by a single shared processor or multiple processors. (Use of the term “processor” should not be construed to refer exclusively to hardware capable of executing software.) Illustrative embodiments may include microprocessor and/or digital signal processor (DSP) hardware, read-only memory (ROM) 308 for storing software performing the operations described below, and random-access memory (RAM) 310 for storing results. Very large-scale integration (VLSI) hardware embodiments, as well as custom VLSI circuitry in combination with a general-purpose DSP circuit, may also be provided.

The logical operations of the various methods, described below, are implemented as: (1) a sequence of computer implemented steps, operations, or procedures running on a programmable circuit within a general use computer, (2) a sequence of computer implemented steps, operations, or procedures running on a specific-use programmable circuit; and/or (3) interconnected machine modules or program engines within the programmable circuits. Information handling system 138 may practice all or part of the recited methods, may be a part of the recited systems, and/or may operate according to instructions in the recited tangible computer-readable storage devices. Such logical operations may be implemented as modules configured to control processor 202 to perform particular functions according to the programming of software modules 216, 218, and 220.

In examples, one or more parts of the example information handling system 138, up to and including the entire information handling system 138, may be virtualized. For example, a virtual processor may be a software object that executes according to a particular instruction set, even when a physical processor of the same type as the virtual processor is unavailable. A virtualization layer or a virtual “host” may enable virtualized components of one or more different computing devices or device types by translating virtualized operations to actual operations. Ultimately however, virtualized hardware of every type is implemented or executed by some underlying physical hardware. Thus, a virtualization computer layer may operate on top of a physical computer layer. The virtualization computer layer may include one or more virtual machines, an overlay network, a hypervisor, virtual switching, and any other virtualization application.

FIG. 3 illustrates an example information handling system 138 having a chipset architecture that may be used in executing the described method and generating and displaying a graphical user interface (GUI). Information handling system 138 is an example of computer hardware, software, and firmware that may be used to implement the disclosed technology. Information handling system 138 may include a processor 202, representative of any number of physically and/or logically distinct resources capable of executing software, firmware, and hardware configured to perform identified computations. Processor 202 may communicate with a chipset 300 that may control input to and output from processor 202. In this example, chipset 300 outputs information to output device 224, such as a display, and may read and write information to storage device 214, which may include, for example, magnetic media, and solid-state media. Chipset 300 may also read data from and write data to RAM 210. Bridge 302 for interfacing with a variety of user interface components 304 may be provided for interfacing with chipset 300. User interface components 304 may include a keyboard, a microphone, touch detection and processing circuitry, a pointing device, such as a mouse, and so on. In general, inputs to information handling system 138 may come from any of a variety of sources, machine generated and/or human generated.

Chipset 300 may also interface with one or more communication interfaces 226 that may have different physical interfaces. Such communication interfaces may include interfaces for wired and wireless local area networks, for broadband wireless networks, as well as personal area networks. Some applications of the methods for generating, displaying, and using the GUI disclosed herein may include receiving ordered datasets over the physical interface or be generated by the machine itself by processor 202 analyzing data stored in storage device 214 or RAM 210. Further, information handling system 138 receives inputs from a user via user interface components 304 and executes appropriate functions, such as browsing functions by interpreting these inputs using processor 202.

In examples, information handling system 138 may also include tangible and/or non-transitory computer-readable storage devices for carrying or having computer-executable instructions or data structures stored thereon. Such tangible computer-readable storage devices may be any available device that may be accessed by a general purpose or special purpose computer, including the functional design of any special purpose processor as described above. By way of example, and not limitation, such tangible computer-readable devices may include RAM, ROM, EEPROM, CD-ROM or other optical disk storage, magnetic disk storage or other magnetic storage devices, or any other device which may be used to carry or store desired program code in the form of computer-executable instructions, data structures, or processor chip design. When information or instructions are provided via a network, or another communications connection (either hardwired, wireless, or combination thereof), to a computer, the computer properly views the connection as a computer-readable medium. Thus, any such connection is properly termed a computer-readable medium. Combinations of the above should also be included within the scope of the computer-readable storage devices.

Computer-executable instructions include, for example, instructions and data which cause a general-purpose computer, special purpose computer, or special purpose processing device to perform a certain function or group of functions. Computer-executable instructions also include program modules that are executed by computers in stand-alone or network environments. Generally, program modules include routines, programs, components, data structures, objects, and the functions inherent in the design of special-purpose processors, etc. that perform particular tasks or implement particular abstract data types. Computer-executable instructions, associated data structures, and program modules represent examples of the program code means for executing steps of the methods disclosed herein. The particular sequence of such executable instructions or associated data structures represents examples of corresponding acts for implementing the functions described in such steps.

In additional examples, methods 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. Examples 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.

FIG. 4 illustrates an example of one arrangement of resources in a computing network 400 that may employ the processes and techniques described herein, although many others are of course possible. As noted above, an information handling system 138, as part of their function, may utilize data, which includes files, directories, metadata (e.g., access control list (ACLS) creation/edit dates associated with the data, etc.), and other data objects. The data on the information handling system 138 is typically a primary copy (e.g., a production copy). During a copy, backup, archive or other storage operation, information handling system 138 may send a copy of some data objects (or some components thereof) to a secondary storage computing device 404 by utilizing one or more data agents 402.

A data agent 402 may be a desktop application, website application, or any software-based application that is run on information handling system 138. As illustrated, information handling system 138 may be disposed at any rig site (e.g., referring to FIG. 1) or repair and manufacturing center. Data agent 402 may communicate with a secondary storage computing device 404 using communication protocol 408 in a wired or wireless system. Communication protocol 408 may function and operate as an input to a website application. In the website application, field data related to pre- and post-operations, generated DTCs, notes, and the like may be uploaded. Additionally, information handling system 138 may utilize communication protocol 408 to access processed measurements, operations with similar DTCs, troubleshooting findings, historical run data, and/or the like. This information is accessed from secondary storage computing device 404 by data agent 402, which is loaded on information handling system 138.

Secondary storage computing device 404 may operate and function to create secondary copies of primary data objects (or some components thereof) in various cloud storage sites 406A-N. Additionally, secondary storage computing device 404 may run determinative algorithms on data uploaded from one or more information handling systems 138, discussed further below. Communications between the secondary storage computing devices 404 and cloud storage sites 406A-N may utilize REST protocols (Representational state transfer interfaces) that satisfy basic C/R/U/D semantics (Create/Read/Update/Delete semantics), or other hypertext transfer protocol (“HTTP”)-based or file-transfer protocol (“FTP”)-based protocols (e.g., Simple Object Access Protocol).

In conjunction with creating secondary copies in cloud storage sites 406A-N, the secondary storage computing device 404 may also perform local content indexing and/or local object-level, sub-object-level or block-level deduplication when performing storage operations involving various cloud storage sites 406A-N. Cloud storage sites 406A-N may further record and maintain DTC code logs for each downhole operation or run, map DTC codes, store repair and maintenance data, store operational data, and/or provide outputs from determinative algorithms that are run at cloud storage sites 406A-N. In examples, computing network 400 may be communicatively coupled to measurement assembly 136 (e.g., referring to FIG. 1). Information handling system 138 described herein may be operable to interface with measurement assembly 134 for measuring high frequency BOB data or raw count of the signal from the strain gauges.

FIG. 5 illustrates workflow 500 for controlling RSS 130 during a drilling operation (e.g., referring to FIG. 1). In examples, workflow 500 may be performed on information handling system 138 and/or steering control system 150. In block 502, high frequency BOB data may be obtained with strain gauges, as previously described. In other examples, downhole Weight on Bit (WOB) or Torque on Bit (TOB) may be additionally obtained with strain sensors. Obtaining BOB, WOB, or TOB data may occur while RSS 130 drills vertically, horizontally, or into a dogleg. In block 504 BOB data from block 502 may be implemented for classification of RSS 130. Specifically, the time periods that RSS 130 is in a neutral or a geostationary configuration. A neutral configuration may be used to drill relatively straight and stable. Whereas in a geostationary configuration may be used to control and change direction to follow more detailed requirements of a well plan such as a dogleg. In examples each neutral or geostationary configurations may comprise its own time frame and be determined using classification techniques described below. For each classification, BOB, raw count of the strain gauge sensors, WOB, or TOB data may be implemented. Higher frequency data greater than 100 Hz may be beneficial. BOB data of different time periods for geostationary and neutral configuration may be shown.

In block 506 the duty cycle applied downhole may be calculated in real-time. In examples, BOB data may be analyzed to classify the data into different configurations of operation and identify their corresponding time periods. The classification may be performed using rules-based techniques developed from the understanding of the magnitude and frequency signature of the BOB measurements based on physical understanding of the process described below. If RSS 130 is operating in a neutral configuration bending moment may be calculated by:

$\begin{matrix} M_{θ} = M_{0} \cos ((w_{c} - w_{p}) t_{1} + \emptyset_{2}) & Equation (1) \end{matrix}$

Herein, M_θ represents bending moment, M₀represents the maximum bending moment value measured by the strain gauge sensors, w_crepresents frequency of the drill collar, w_pfrequency of the pad force, t₁is the total time during a neutral RSS configuration, and Ø₂is the initial angle between the sensor and the direction of the pad force. Equation (1) ignores other frequencies in the data during the neutral configurations which may be the result of fluctuating pad force within a revolution, gravity, and Toolface. In addition, there might be nonlinearity between the pad force direction and the plane of bending, which may also introduce additional frequency components in the real case. In comparison to neutral during the geostationary configuration, the pad force direction is primarily constant since w_p=0 is expected in geostationary configuration during operation, the measured bending moment by the strain gauges will be the function of the collar RPM and is given by:

$\begin{matrix} M_{θ} = M_{0} \cos (w_{c} t_{2} + \emptyset_{1}) & Equation (2) \end{matrix}$

Herein, Ø₁represents the initial angle between the sensor tool face and the direction of the bending and t₂is the total time during a geostationary RSS configuration.

FIG. 6 illustrates the measured bending moment data 600 from block 502 (e.g., referring to FIG. 5). Bending moment data 600 illustrates two configurations of operation of RSS 130 which may be inferred from the frequency and magnitude of the bending moment data. In the example, the first 15 seconds of the data has two different frequencies, a lower frequency and a higher frequency component and a higher magnitude, which is a characteristic of neutral configuration 602 and the later 45 seconds data has just a high frequency component which is a characteristic of the geostationary configuration 604. Bending moment data may be classified in block 504 into neutral or geostationary configuration of operation and their time corresponding time period may be calculated. Additionally, FIG. 6 illustrates time period for neutral configuration 602 t₁and time period for geostationary configuration 604 t₂. Referring to block 506, real time Duty Cycle may be calculated with time period for neutral configuration 602 t₁and time period for geostationary configuration 604 t₂in:

$\begin{matrix} real time Duty Cycle = \frac{t_{2}}{t_{1} + t_{2}} \times 100 & Equation (3) \end{matrix}$

Referring back to FIG. 5, once real time Duty Cycle is determined it may be transmitted from information handling system 138 (e.g., referring to FIG. 1) to the steering control system 150 via any method. Duty Cycle set point may be generated from steering control system 150 or by a directional driller based on the current steering capability and the well plan. Herein a direction driller is an operator and may be able to operate RSS 130 (e.g., referring to FIG. 1) or interpret a well plan. For example, if the current steering capability is too low and the well plan indicates it must be increased to match the steering capability, as such control system 150 may increase Duty Cycle set point. In block 508, steering control system 150 or information handling system 138 may compare real time Duty Cycle with Duty Cycle set point. This comparison may be iterated for every new Duty Cycle set point.

During the comparison, error between real time Duty Cycle and Duty Cycle set point may be calculated. Based on the error, the actual steering capability of RSS 130 may be estimated by steering control system 150 and a new Duty Cycle set point may be generated and applied to meet the well plan. Steering control system 150 may be configured to minimize the error between the dogleg severity (DLS) generated by the tool and the dogleg severity (DLS) defined by the well plan. In the case of model based steering control system, the error real time Duty Cycle and Duty Cycle set point may be used to update the steering model. The updated steering model may be used to make the prediction of the DLS for the current steering inputs (Inclination, Azimuth, Steering Toolface, Steering Duty Cycle, WOB, RPM etc.), and run optimization algorithm to search the parameter space that minimize the error between the current DLS and the well plan. Similarly, the drilling parameter may also be obtained using model free methods for which the real time Duty Cycle or the error between the real time Duty Cycle and the Duty Cycle set point may be an input for optimization. Steering control system 150 may transmit one or more drilling parameter command updates to the RSS 130 to meet the well plan set point. One or more drilling parameter command updates may be in the form of altering or updating drilling parameters such as Weight on Bit (WOB), rotations per minute RPM, or drilling flowrate of the mud, and/or the like. Furthermore, if any dysfunction to the required Duty Cycle set point is not generated downhole, drilling parameters such as Weight on Bit (WOB), rotations per minute RPM, or drilling flowrate may be changed via drilling parameter command updates from steering control system 150 to achieve the require steering performance.

As such, steering control system 150 or information handling system 138 may update the RSS 130 via drilling parameter command updates. As a result, the well plan may be maintained to an improved accuracy of 0.01-0.1%, 0.1-99%, or 99-99.9%. In examples, workflow 500 may be an effective workflow, but additional workflows may be viable.

For example, FIG. 7 illustrates workflow 700 for controlling RSS 130 during a drilling operation (e.g., referring to FIG. 1). In examples, workflow 700 may be performed on information handling system 138 and/or steering control system 150. In block 702, high frequency BOB data may be obtained with strain gauges, as previously described. In other examples, downhole Weight on Bit (WOB) or Torque on Bit (TOB) may be additionally obtained with strain sensors. Obtaining BOB, WOB, or TOB data may occur while RSS 130 drills vertically, horizontally, or into a dogleg. FIG. 8 illustrates example BOB data 800 and RSS data 802. Herein RSS data 802 may be any data generated from RSS 130 (e.g., referring to FIG. 1). In block 704 BOB data from block 702 may be implemented for classification of RSS 130 configuration. Specifically, classification of one or more time periods for which RSS 130 (e.g., referring to FIG. 1) is in either a neutral or a geostationary configuration. Classification for one or more time periods may be performed by a rule based method or machine learning method.

Under rule-based methods rules using the magnitude and frequency of the bending moment may be used to identify if a section of the data is for the neutral or geostationary configuration. The identification may analyze the BOB, WOB, and/or TOB data per revolution of BHA 134 or by taking the data from a small-time window. Herein, a time window may be 1 ms-10 ms, 10 ms-1 s, or 1 s-1 minute. A first rule may be that under a neutral configuration of RSS 130, most of the magnitude data is either all positive or all negative except for a few revolutions in the middle where transitions from all positive to all negative. In addition, there will be two frequencies present, one frequency is close to the frequency of the bit rotation and another frequency is equal to the frequency of the relative motion of the pad force to the drill collar. A second rule may be that under geostationary configuration, magnitude of the bending moment changes from positive to negative with approximately half of the number of BOB, WOB, and/or TOB data points in the positive half and half of the data in the negative half, and the frequency of the data is equal to or very close to the frequency of the drill collar rotation. The first or second rules may be defined to classify the neutral and geostationary configuration of RSS 130. In addition to rule-based methods, machine learning may also classify one or more time periods.

Under machine learning methods classification method may be based on a machine learning algorithm such as neural networks or tree-based methods. The trained model may be used for the classification of real-time BOB data. Feature engineering may be performed on BOB WOB, and/or TOB data to convert a real time stream of BOB data to machine learning parameter. Herein, feature engineering may convert BOB, WOB, and/or TOB data to more usable features comprising average magnitude, maximum magnitude, minimum magnitude, and/or dominant frequencies of the data identified as one or more periods. Machine learning parameters may comprise average magnitude, max, min, SD, dominant frequencies, and/or the like. In addition, in some embodiments, unsupervised learning may be used with two classes. In other examples, unsupervised learning may be implemented to classify BOB data. Upon classifying the BOB data, the time frames for each neutral configuration and geostationary configuration may be determined.

In block 706, time frames for each neutral and geostationary classification may be determined. FIG. 8 is a graph of the determined of RSS 130 configurations as either t₁and t₂, where t₁is the time when RSS is in neutral configuration, and t₂is the time when RSS is in geostationary configuration. When there is a switch is the RSS configuration, for example from neutral configuration to geostationary configuration, time for that geostationary configuration is initialized at zero. From zero time may be added until the switch to neutral configuration. In examples, t₁and t₂are cumulative summations of time. As such, t₁and t₂may be estimated continuously.

The determined t₁and t₂may be implemented for further use in block 708. Referring back to FIG. 7, in block 708 the real time Duty Cycle may be calculated and compared to Duty Cycle set point. In examples, classifications from block 704 and time frames from block 706 may be used in Equation (3), provided above. In the Equation (3), a sliding window of the BOB data may be used in real time for estimation of the real time Duty Cycle. The length of window is determined by the configuration of the RSS motor control system (not illustrated). It should be greater than or equal to the time configured in the motor control system of RSS 130 for generating a Duty Cycle set point by changing its configuration of operation. Duty cycle set point may be generated from steering control system 150 or by a directional driller based on the current steering capability and the well plan. For example, if the current steering capability is too low and the well plan indicates it must be increased to match the steering capability, as such control system 150 may increase Duty Cycle set point.

Once Duty Cycle set point and real time Duty Cycle are determined, they both may be transmitted from information handling system 138 (e.g., referring to FIG. 1) to the steering control system 150 or vice versa via any method. Steering control system 150 or information handling system 138 may compare real time Duty Cycle with Duty Cycle set point. This comparison may be iterated for every new Duty Cycle set point.

During the comparison, an error between real time Duty Cycle and Duty Cycle set point may be calculated. Based on the error, the actual steering capability of RSS 130 may be estimated by steering control system 150 and a new Duty Cycle set point may be generated and applied to meet the well plan.

In examples, Steering control system 150 or information handling system 138 may obtain drilling parameter command updates by the error between real time Duty Cycle and Duty Cycle set point. FIG. 9 is a graphical representation of the comparison between real time Duty Cycle and Duty Cycle set point over time. FIG. 9 represents example BOB Data 902, real time Duty Cycle 904, and Duty Cycle set point 906. Herein the example product of Duty Cycle set point may predict implemented classification and estimation of a real time Duty Cycle using a rules-based method.

Based on the comparison, the actual steering capability of RSS 130 may be estimated by steering control system 150 and a well plan set point for the new Duty Cycle set point that may be applied to meet the well plan. Steering control system 150 may run an optimization algorithm to minimize the error between the dogleg severity (DLS) generated by the tool and the dog leg severity (DLS) defined by the well plan. In the case of model based steering control system, the error in the real time Duty Cycle may be used to update the steering model. The updated steering model may be used to make the prediction of the DLS for the current steering inputs (Inclination, Azimuth, Steering Toolface, Steering Duty Cycle, WOB, RPM etc.), and run to search the parameter space that minimize the error between the current DLS and the well plan. Similarly, the drilling parameter may also be obtained using model free methods for which the real time Duty Cycle or the error between the real time Duty Cycle and the Duty Cycle set point may be an input for optimization. Steering control system 150 may transmit one or more drilling parameter command updates to RSS 130 to meet the well plan set point. One or more drilling parameter command updates may be in the form of altering or updating drilling parameters. Furthermore, if for any reason the required Duty Cycle is not achieved downhole, drilling parameters such as Weight on Bit (WOB), rotations per minute RPM, or Flow may be changed via drilling parameter command updates from steering control system 150 to achieve the require steering performance. In blocks 710, 712, and/or 714 steering control system 150 may update RSS 130 to follow a well plan and match the well plan set point via drilling parameter command updates.

In examples, one of or any number of combinations of blocks 710, 712, or 714 may be performed. Steering control system 150 may be disposed on the surface and RSS 134 for blocks 710 and 712 may be performed. In block 710, the error from block 708 may be transmitted to the surface for steering control system 150 (e.g., referring to FIG. 1). Steering control system 150 may adjust some drilling parameters via drilling parameter command updates based on the error. Additionally, steering control system 150 may also generate alerts downhole to notify updates about the error between the real time Duty Cycle and Duty Cycle set point on steering control system 150 at the surface.

In block 712 steering control system 150 (e.g., referring to FIG. 1) may be located downhole on BHA 134. Control system 150 may adjust some drilling parameters via drilling parameter command updates based at least on the error from block 708. Additionally, steering control system 150 may tune some internal controls parameters to minimize the error. Internal control parameters may comprise gains or filter coefficients of steering control system 150. If the steering control system 150 is configuration based, then the model may also be updated using the real time Duty Cycle. In block 714, steering control system 150 may also send the error from block 708 to the downhole RSS motor control system (not illustrated). The RSS motor control system may be a component of RSS 130 and responsible for generating the required real time Duty Cycle downhole based on the Duty Cycle set point. Based on the error, the RSS motor control system may tune its internal control parameters like controller gains and model in to minimize the error between the real time Duty Cycle and the Duty Cycle set point.

For blocks 710, 712, and 714, an example of a drilling parameter command update may be forming a new Duty Cycle set point. Further, drilling parameter command updates may further comprise updating WOB, RPM, and flowrate. In addition, the Duty Cycle may be multiplied with the actual pad force or side force to get the actual steering force which may be provided as feedback to the steering control system 150. The pad force estimation may be made using hydraulics calculation or from the bending moment. As a result, the well plan may be maintained to an improved accuracy of 0.01-0.1%, 0.1-99%, or 99-99.9%.

In other examples, wavelet analysis may be performed. For example, FIG. 10 illustrates an example of raw BOB data 1002, as discussed in block 702 (e.g., referring to FIG. 7) expressed as (ft-lb) along the Y axis and time in minutes along the X axis. FIG. 10 shows the Range of the time along the X axis as 18:13-18:20 and the average Bob data 1002 point as 1193.28 (ft-lb). As observed in FIG. 10, BOB frequency may change over time. Specifically, there may be two main frequencies, a higher frequency and a lower frequency. The higher frequency and lower frequency may be utilized in wavelet analysis.

For example, FIG. 11 illustrates wavelet analysis for higher frequency 1102 and lower frequency 1104. Using Wavelet Analysis, or other frequency analysis tools, the duration of higher frequency 1102 and lower frequency 1104 may be utilized to calculate real time Duty Cycle. To illustrate, the summation of higher frequency 1102 may be t₁and the summation of lower frequency 1104 may be t₂. Further, t₁and t₂may be used in Equation (4) to calculate moving average of Duty Cycle. Equivalently, while in active drilling, t₁+t₂in Equation (3) may be replaced by the time window T in which the data are being analyzed.

The methods and systems described above are an improvement over current technology in the method and systems herein. In effect, a method for estimating actual Duty Cycle may be applied downhole by the steering control system in real time. Downhole measurements such as BOB data produced by strain gauge sensor in various forms may be implemented. Further, real time Duty Cycle may be implemented to update Duty Cycle and send drilling parameter command updates to make real time steering decisions.

The systems and methods for using a distributed acoustic system in a subsea environment may include any of the various features of the systems and methods disclosed herein, including one or more of the following statements. Additionally, the systems and methods for an acoustic tool in a downhole environment may include any of the various features of the systems and methods disclosed herein, including one or more of the following statements.

Statement 1. A method comprising disposing a bottom hole assembly (BHA) comprising a Rotary Steerable System (RSS) into a borehole; obtaining a bending at a drill bit (BOB) data with a measurement assembly disposed on the BHA; classifying the BOB data into a neutral RSS configuration or a geostationary RSS configuration; determining t₁based at least on the neutral RSS configuration, wherein t₁is a total time during a neutral RSS configuration; determining t₂based at least on the neutral RSS configuration, wherein t₂is the total time during a geostationary RSS configuration; and calculating a real time Duty Cycle based at least on t₁and t₂.

Statement 2. The method of statement 1, further comprising generating a Duty Cycle set point based on a current steering capability and a well plan.

Statement 3. The method of statement 2, wherein generating the Duty Cycle set point further comprises a directional driller.

Statement 4. The method of statements 2 or 3, further comprising comparing the real time Duty Cycle with the Duty Cycle set point to form an error.

Statement 5. The method of statement 4, further comprising forming drilling parameter command updates based at least on the error.

Statement 6. The method of statement 5, further comprising transmitting the drilling parameter command updates to at least the RSS.

Statement 7. The method of statement 6, further comprising updating at least the RSS with the drilling parameter command updates.

Statement 8. The method of statement 7, wherein the drilling parameter command updates is an update to a weight on bit, rotation per minute of the BHA, or a flowrate.

Statement 9. The method of statements 1-8, further comprising calculating real time Duty Cycle with at least:

$real time Duty Cycle = \frac{t_{2}}{t_{1} + t_{2}} \times 100.$

Statement 10. The method of statements 1-9 further comprising obtaining Weight on Bit data or Torque on Bit data with measurement assembly disposed on the BHA.

Statement 11. A system comprising a bottom hole assembly (BHA) comprising a Rotary Steerable System (RSS) disposed into a borehole; and a steering control system a configured to: obtain a bending of a drill bit (BOB) data with a measurement assembly disposed on the BHA; classify the BOB data into a neutral RSS configuration or a geostationary RSS configuration; determine t₁based at least on the neutral RSS configuration, wherein t₁is the total time during a neutral RSS configuration; determine t₂based at least on the neutral RSS configuration, wherein t₂is the total time during a geostationary RSS configuration; and determine a real time Duty Cycle based at least on t₁and t₂.

Statement 12. The system of statement 1, wherein the steering control system is further configured to generate a Duty Cycle set point based on a current steering capability and a well plan.

Statement 13. The system of statement 12, wherein generating the Duty Cycle set point further comprises a directional driller.

Statement 14. The system of statements 12 or 13, wherein the steering control system is further configured to compare the real time Duty Cycle with the Duty Cycle set point to form an error.

Statement 15. The system of statement 14, wherein the steering control system is further configured to form drilling parameter command updates based at least on the error.

Statement 16. The system of statement 15, wherein the steering control system is further configured to transmit the drilling parameter command updates to at least the RSS.

Statement 17. The system of statement 16, wherein the steering control system is further configured to update at least the RSS with the drilling parameter command updates.

Statement 18. The system of statement 17, wherein the drilling parameter command updates is an update to a weight on bit, rotation per minute of the BHA, or a flowrate.

Statement 19. The system of statements 11-18, wherein the steering control system is further configured to calculate real time Duty Cycle with at least:

$real time Duty Cycle = \frac{t_{2}}{t_{1} + t_{2}} \times 100.$

Statement 20. The system of statements 11-19 wherein the steering control system is further configured to obtain Weight on Bit data or Torque on Bit data with measurement assembly disposed on the BHA.

The preceding description provides various examples of the systems and methods of use disclosed herein which may contain different method steps and alternative combinations of components. It should be understood that, although individual examples may be discussed herein, the present disclosure covers all combinations of the disclosed examples, including, without limitation, the different component combinations, method step combinations, and properties of the system. It should be understood that the compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods may also “consist essentially of” or “consist of” the various components and steps. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the elements that it introduces.

For the sake of brevity, only certain ranges are explicitly disclosed herein. However, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.

Therefore, the present examples are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular examples disclosed above are illustrative only, and may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although individual examples are discussed, the disclosure covers all combinations of all of the examples. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. It is therefore evident that the particular illustrative examples disclosed above may be altered or modified and all such variations are considered within the scope and spirit of those examples. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

Duty Cycle Estimation From Bending Moment Magnitude

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