Field operations framework

Abstract

A method can include receiving torque measurements with respect to time associated with a drillstring in a borehole; receiving rotational speed measurements with respect to time associated with a top drive operatively coupled to the drillstring in the borehole, where the top drive is operatively coupled to a stick-slip mitigation controller; performing an assessment of stick-slip mitigation performance of the stick-slip mitigation controller using the torque measurements and the rotational speed measurements; and adjusting operation of the stick-slip mitigation controller based at least in part on the assessment.

Description

IS24.1553-WO-PCTFIELD OPERATIONS FRAMEWORKCROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims priority to and the benefit of U.S. Provisional Patent Application No. 63 / 770,598 filed on March 12, 2025, the entirety of which is incorporated herein by reference to the extent consistent with the present disclosure.BACKGROUND

[0002] A reservoir may be a subsurface formation that may be characterized at least in part by its porosity and fluid permeability. As an example, a reservoir may be part of a basin such as a sedimentary basin. A basin may be a depression (e.g., caused by plate tectonic activity, subsidence, etc.) in which sediments accumulate. As an example, where hydrocarbon source rocks occur in combination with appropriate depth and duration of burial, a petroleum system may develop within a basin, which may form a reservoir that includes hydrocarbon fluids (e.g., oil, gas, etc.).

[0003] Drilling operations may be performed to construct a borehole according to a trajectory that penetrates a reservoir, etc., where fluid may be produced via the borehole, where fluid may be injected via the borehole, etc. As an example, one or more workflows may be performed using one or more computational frameworks, systems, etc., for one or more of analysis, acquisition, model building, control, etc., for exploration, interpretation, drilling, fracturing, production, etc.SUMMARY

[0004] A method can include receiving torque measurements with respect to time associated with a drillstring in a borehole; receiving rotational speed measurements with respect to time associated with a top drive operatively coupled to the drillstring in the borehole, where the top drive is operatively coupled to a stick-slip mitigation controller; performing an assessment of stick-slip mitigation performance of the stick-slip mitigation controller using the torque measurements and the rotational speed measurements; and adjusting operation of the stick-slip mitigation controller based at least in part on the assessment. A system can include one or more processors; memory accessible to atIS24.1553-WO-PCTleast one of the one or more processors; and processor-executable instructions stored in the memory and executable to instruct the system to: receive torque measurements with respect to time associated with a drillstring in a borehole; receive rotational speed measurements with respect to time associated with a top drive operatively coupled to the drillstring in the borehole, where the top drive is operatively coupled to a stick-slip mitigation controller; perform an assessment of stick-slip mitigation performance of the stick-slip mitigation controller using the torque measurements and the rotational speed measurements; and adjust operation of the stick-slip mitigation controller based at least in part on the assessment. One or more computer-readable storage media can include processor-executable instructions to instruct a computing system to: receive torque measurements with respect to time associated with a drillstring in a borehole; receive rotational speed measurements with respect to time associated with a top drive operatively coupled to the drillstring in the borehole, where the top drive is operatively coupled to a stick-slip mitigation controller; perform an assessment of stick-slip mitigation performance of the stick-slip mitigation controller using the torque measurements and the rotational speed measurements; and adjust operation of the stick-slip mitigation controller based at least in part on the assessment. Various other apparatuses, systems, methods, etc., are also disclosed.

[0005] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.BRIEF DESCRIPTION OF THE DRAWINGS

[0006] The following detailed description refers to the accompanying drawings. Wherever convenient Features and advantages of the described implementations may be more readily understood by reference to the following description taken in conjunction with the accompanying drawings.

[0007] Fig. 1 shows an example of a system;

[0008] Fig. 2 shows an example of a system;

[0009] Fig. 3 shows an example of a system;IS24.1553-WO-PCT

[0010] Fig. 4 shows an example of a system;

[0011] Fig. 5 shows an example of a workflow;

[0012] Fig. 6 shows example plots;

[0013] Fig. 7 shows example plots;

[0014] Fig. 8 shows example plots;

[0015] Fig. 9 shows example plots;

[0016] Fig. 10 shows an example of a method and an example of a system; and

[0017] Fig. 11 shows an example of a system.DETAILED DESCRIPTION

[0018] This description is not to be taken in a limiting sense, but rather is made merely for the purpose of describing the general principles of the implementations. The scope of the described implementations should be ascertained with reference to the issued claims.

[0019] Fig. 1 shows an example of a system 100 that includes a workspace framework 110 that may provide for instantiation of, rendering of, interactions with, etc., a graphical user interface (GUI) 120. In the example of Fig. 1, the GUI 120 may include graphical controls for computational frameworks (e.g., applications, etc.) 121, projects 122, visualization features 123, one or more other features 124, data access 125, and data storage 126.

[0020] In the example of Fig. 1 , the workspace framework 110 may be tailored to a particular geologic environment such as an example geologic environment 150. For example, the geologic environment 150 may include layers (e.g., stratification) that include a reservoir 151 and that may be intersected by a fault 153. As an example, the geologic environment 150 may be outfitted with a variety of sensors, detectors, actuators, etc. For example, equipment 152 may include communication circuitry to receive and to transmit information with respect to one or more networks 155. Such information may include information associated with downhole equipment 154, which may be equipment to acquire information, to assist with resource recovery, etc. Other equipment 156 may be located remote from a wellsite and include sensing, detecting, emitting or other circuitry. Such equipment may include storage and communicationIS24.1553-WO-PCTcircuitry to store and to communicate data, instructions, etc. As an example, one or more satellites may be provided for purposes of communications, data acquisition, etc. For example, Fig. 1 shows a satellite 170 in communication with the network 155 that may be configured for communications, noting that the satellite 170 may additionally or alternatively include circuitry for imagery (e.g., spatial, spectral, temporal, radiometric, etc.).

[0021] Fig. 1 also shows the geologic environment 150 as optionally including equipment 157 and 158 associated with a well that includes a substantially horizontal portion that may intersect with one or more fractures 159. For example, consider a well in a shale formation that may include natural fractures, artificial fractures (e.g., hydraulic fractures) or a combination of natural and artificial fractures. As an example, a well may be drilled for a reservoir that is laterally extensive. In such an example, lateral variations in properties, stresses, etc. may exist where an assessment of such variations may assist with planning, operations, etc. to develop a laterally extensive reservoir (e.g., via fracturing, injecting, extracting, etc.). As an example, the equipment 157 and / or 158 may include components, a system, systems, etc. for fracturing, seismic sensing, analysis of seismic data, assessment of one or more fractures, etc.

[0022] In the example of Fig. 1, the GUI 120 shows some examples of computational frameworks, including the DRILLPLAN, DRILLOPS, PETREL, TECHLOG, PETROMOD, ECLIPSE, PIPESIM, and INTERSECT frameworks (SLB, Houston, Texas).

[0023] The DRILLPLAN framework provides for digital well construction planning and includes features for automation of repetitive tasks and validation workflows, enabling improved quality drilling programs (e.g., digital drilling plans, etc.) to be produced quickly with assured coherency.

[0024] The DRILLOPS framework may execute a digital drilling plan and ensures plan adherence, while delivering goal-based automation. The DRILLOPS framework may generate activity plans automatically individual operations, whether they are monitored and / or controlled on the rig or in town. Automation may utilize data analysis and learning systems to assist and optimize tasks, such as, for example, setting ROP to drilling a stand. A preset menu of automatable drilling tasks may be rendered, and,IS24.1553-WO-PCTusing data analysis and models, a plan may be executed in a manner to achieve a specified goal, where, for example, measurements may be utilized for calibration. The DRILLOPS framework provides flexibility to modify and replan activities dynamically, for example, based on a live appraisal of various factors (e.g., equipment, personnel, and supplies). Well construction activities (e.g., tripping, drilling, cementing, etc.) may be continually monitored and dynamically updated using feedback from operational activities. The DRILLOPS framework may provide for various levels of automation based on planning and / or re-planning (e.g., via the DRILLPLAN framework), feedback, etc.

[0025] The PETREL framework may be part of the DELFI environment for utilization in geosciences and geoengineering, for example, to analyze subsurface data from exploration to production of fluid from a reservoir. The DELFI cognitive exploration and production (E&P) environment (SLB, Houston, Texas), referred to herein as the DELFI environment or DELFI framework, is a secure, cognitive, cloud-based collaborative environment that integrates data and workflows with digital technologies, such as artificial intelligence and machine learning.

[0026] The PETREL framework provides components that allow for optimization of various exploration, development and production operations. The PETREL framework includes seismic to simulation software components that may output information for use in increasing reservoir performance, for example, by improving asset team productivity. Through use of such a framework, various professionals (e.g., geophysicists, geologists, and reservoir engineers) may develop collaborative workflows and integrate operations to streamline processes (e.g., with respect to one or more geologic environments, etc.). Such a framework may be considered an application (e.g., executable using one or more devices) and may be considered a data-driven application (e.g., where data is input for purposes of modeling, simulating, etc.).

[0027] The TECHLOG framework may handle and process field and laboratory data for a variety of geologic environments (e.g., deepwater exploration, shale, etc.). The TECHLOG framework may structure wellbore data for analyses, planning, etc.

[0028] The PETROMOD framework provides petroleum systems modeling capabilities that may combine one or more of seismic, well, and geological informationIS24.1553-WO-PCTto model the evolution of a sedimentary basin. The PETROMOD framework may predict if, and how, a reservoir has been charged with hydrocarbons, including the source and timing of hydrocarbon generation, migration routes, quantities, and hydrocarbon type in the subsurface or at surface conditions.

[0029] The ECLIPSE framework provides a reservoir simulator (e.g., as a computational framework) with numerical solutions for fast and accurate prediction of dynamic behavior for various types of reservoirs and development schemes.

[0030] The INTERSECT framework provides a high-resolution reservoir simulator for simulation of detailed geological features and quantification of uncertainties, for example, by creating accurate production scenarios and, with the integration of precise models of the surface facilities and field operations, the INTERSECT framework may produce reliable results, which may be continuously updated by real-time data exchanges (e.g., from one or more types of data acquisition equipment in the field that may acquire data during one or more types of field operations, etc.). The INTERSECT framework may provide completion configurations for complex wells where such configurations may be built in the field, may provide detailed enhanced-oil-recovery (EOR) formulations where such formulations may be implemented in the field, may analyze application of steam injection and other thermal EOR techniques for implementation in the field, advanced production controls in terms of reservoir coupling and flexible field management, and flexibility to script customized solutions for improved modeling and field management control. The INTERSECT framework, as with the other example frameworks, may be utilized as part of the DELFI environment, for example, for rapid simulation of multiple concurrent cases. For example, a workflow may utilize one or more of the DELFI environment on demand reservoir simulation features.

[0031] The aforementioned DELFI environment provides various features for workflows as to subsurface analysis, planning, construction and production, for example, as illustrated in the workspace framework 110. As shown in Fig. 1 , outputs from the workspace framework 110 may be utilized for directing, controlling, etc., one or more processes in the geologic environment 150 and, feedback 160, may be received via one or more interfaces in one or more forms (e.g., acquired data as to operational conditions, equipment conditions, environment conditions, etc.).IS24.1553-WO-PCT

[0032] As an example, a workflow may progress to a geology and geophysics (“G&G”) service provider, which may generate a well trajectory, which may involve execution of one or more G&G frameworks (e.g., consider the PETREL framework, etc.).

[0033] In the example of Fig. 1 , the visualization features 123 may be implemented via the workspace framework 110, for example, to perform tasks as associated with one or more of subsurface regions, planning operations, constructing wells and / or surface fluid networks, and producing from a reservoir.

[0034] As an example, a visualization process may implement one or more of various features that may be suitable for one or more web applications. For example, a template may involve use of the JAVASCRIPT object notation format (JSON) and / or one or more other languages / formats. As an example, a framework may include one or more converters. For example, consider a JSON to PYTHON converter and / or a PYTHON to JSON converter. Such an approach may provide for compatibility of devices, frameworks, etc., with respect to one or more sets of instructions.

[0035] As an example, visualization features may provide for visualization of various earth models, properties, etc., in one or more dimensions. As an example, visualization features may provide for rendering of information in multiple dimensions, which may optionally include multiple resolution rendering. In such an example, information being rendered may be associated with one or more frameworks and / or one or more data stores. As an example, visualization features may include one or more control features for control of equipment, which may include, for example, field equipment that may perform one or more field operations. As an example, a workflow may utilize one or more frameworks to generate information that may be utilized to control one or more types of field equipment (e.g., drilling equipment, wireline equipment, fracturing equipment, etc.).

[0036] As to a reservoir model that may be suitable for utilization by a simulator, consider acquisition of seismic data as acquired via reflection seismology, which finds use in geophysics, for example, to estimate properties of subsurface formations. As an example, reflection seismology may provide seismic data representing waves of elastic energy (e.g., as transmitted by P-waves and S-waves, in a frequency range ofIS24.1553-WO-PCTapproximately 1 Hz to approximately 100 Hz). Seismic data may be processed and interpreted, for example, to understand better composition, fluid content, extent and geometry of subsurface rocks. Such interpretation results may be utilized to plan, simulate, perform, etc., one or more operations for production of fluid from a reservoir (e.g., reservoir rock, etc.).

[0037] As an example, a model may be a simulated version of a geologic environment. As an example, a simulator may include features for simulating physical phenomena in a geologic environment based at least in part on a model or models. A simulator, such as a reservoir simulator, may simulate fluid flow in a geologic environment based at least in part on a model that may be generated via a framework that receives seismic data. A simulator may be a computerized system (e.g., a computing system) that may execute instructions using one or more processors to solve a system of equations that describe physical phenomena subject to various constraints. In such an example, the system of equations may be spatially defined (e.g., numerically discretized) according to a spatial model that that includes layers of rock, geobodies, etc., that have corresponding positions that may be based on interpretation of seismic and / or other data. A spatial model may be a cell-based model where cells are defined by a grid (e.g., a mesh). A cell in a cell-based model may represent a physical area or volume in a geologic environment where the cell may be assigned physical properties (e.g., permeability, fluid properties, etc.) that may be germane to one or more physical phenomena (e.g., fluid volume, fluid flow, pressure, etc.). A reservoir simulation model may be a spatial model that may be cell-based.

[0038] While several simulators are illustrated in the example of Fig. 1 , one or more other simulators may be utilized, additionally or alternatively. For example, consider the VISAGE geomechanics simulator (SLB, Houston Texas) or the PIPESIM network simulator (SLB, Houston Texas), etc.

[0039] As an example, a workflow may utilize one or more types of data for one or more processes (e.g., stratigraphic modeling, basin modeling, completion designs, drilling, production, injection, etc.). As an example, one or more tools may provide data that may be used in a workflow or workflows that may implement one or more frameworks (e.g., PETREL, TECHLOG, PETROMOD, ECLIPSE, etc.).IS24.1553-WO-PCT

[0040] In the example of Fig. 1 , drilling may be performed in the geologic environment 150, for example, to access the reservoir 151, which may be accessed from land or offshore. In Fig. 1 , the downhole equipment 154 may be, for example, part of a bottom hole assembly (BHA). The BHA may be used to drill a well. The downhole equipment 154 may communicate information to equipment at the surface, and may receive instructions and information from the equipment at the surface. During a well construction process, a variety of operations (such as cementing, wireline evaluation, testing, etc.) may be conducted. In such embodiments, data collected by tools and sensors and used for reasons such as reservoir characterization may be collected and transmitted.

[0041] A well may include a substantially horizontal portion (e.g., lateral portion) that may intersect with one or more fractures. For example, a well in a shale formation may pass through natural fractures, artificial fractures (e.g., hydraulic fractures), or a combination thereof. Such a well may be constructed using directional drilling techniques as described herein. However, these same techniques may be used in connection with other types of directional wells (such as slant wells, S-shaped wells, deep inclined wells, and others) and are not limited to horizontal wells.

[0042] Fig. 2 shows an example of a wellsite system 200 (e.g., at a wellsite that may be onshore or offshore). As shown, the wellsite system 200 may include a mud tank 201 for holding mud and other material (e.g., where mud may be a drilling fluid), a suction line 203 that serves as an inlet to a mud pump 204 for pumping mud from the mud tank 201 such that mud flows to a vibrating hose 206, a drawworks 207 for winching drill line or drill lines 212, a standpipe 208 that receives mud from the vibrating hose 206, a kelly hose 209 that receives mud from the standpipe 208, a gooseneck or goosenecks 210, a traveling block 211 , a crown block 213 for carrying the traveling block 211 via the drill line or drill lines 212, a derrick 214, a kelly 218 or a top drive 240, a kelly drive bushing 219, a rotary table 220, a drill floor 221, a bell nipple 222, one or more blowout preventors (BOPs) 223, a drillstring 225, a drill bit 226, a casing head 227 and a flow pipe 228 that carries mud and other material to, for example, the mud tank 201.IS24.1553-WO-PCT

[0043] In the example system of Fig. 2, a borehole 232 is formed in subsurface formations 230 by rotary drilling; noting that various example embodiments may also use one or more directional drilling techniques, equipment, etc.

[0044] As shown in the example of Fig. 2, the drillstring 225 is suspended within the borehole 232 and has a drillstring assembly 250 that includes the drill bit 226 at its lower end. As an example, the drillstring assembly 250 may be a bottom hole assembly (BHA).

[0045] The wellsite system 200 may provide for operation of the drillstring 225 and other operations. As shown, the wellsite system 200 includes the traveling block 211 and the derrick 214 positioned over the borehole 232. As mentioned, the wellsite system 200 may include the rotary table 220 where the drillstring 225 pass through an opening in the rotary table 220.

[0046] As shown in the example of Fig. 2, the wellsite system 200 may include the kelly 218 and associated components, etc., or a top drive 240 and associated components. As to a kelly example, the kelly 218 may be a square or hexagonal metal / alloy bar with a hole drilled therein that serves as a mud flow path. The kelly 218 may be used to transmit rotary motion from the rotary table 220 via the kelly drive bushing 219 to the drillstring 225, while allowing the drillstring 225 to be lowered or raised during rotation. The kelly 218 may pass through the kelly drive bushing 219, which may be driven by the rotary table 220. As an example, the rotary table 220 may include a master bushing that operatively couples to the kelly drive bushing 219 such that rotation of the rotary table 220 may turn the kelly drive bushing 219 and hence the kelly 218. The kelly drive bushing 219 may include an inside profile matching an outside profile (e.g., square, hexagonal, etc.) of the kelly 218; however, with slightly larger dimensions so that the kelly 218 may freely move up and down inside the kelly drive bushing 219.

[0047] As to a top drive example, the top drive 240 may provide functions performed by a kelly and a rotary table. The top drive 240 may turn the drillstring 225. As an example, the top drive 240 may include one or more motors (e.g., electric and / or hydraulic) connected with appropriate gearing to a short section of pipe called a quill, that in turn may be screwed into a saver sub or the drillstring 225 itself. The top driveIS24.1553-WO-PCT240 may be suspended from the traveling block 211, so the rotary mechanism is free to travel up and down the derrick 214. As an example, a top drive 240 may allow for drilling to be performed with more joint stands than a kelly / rotary table approach.

[0048] In the example of Fig. 2, the mud tank 201 may hold mud, which may be one or more types of drilling fluids. As an example, a wellbore may be drilled to produce fluid, inject fluid or both (e.g., hydrocarbons, minerals, water, etc.).

[0049] In the example of Fig. 2, the drillstring 225 (e.g., including one or more downhole tools) may be composed of a series of pipes threadably connected together to form a long tube with the drill bit 226 at the lower end thereof. As the drillstring 225 is advanced into a wellbore for drilling, at some point in time prior to or coincident with drilling, the mud may be pumped by the pump 204 from the mud tank 201 (e.g., or other source) via the lines 206, 208 and 209 to a port of the kelly 218 or, for example, to a port of the top drive 240. The mud may then flow via a passage (e.g., or passages) in the drillstring 225 and out of ports located on the drill bit 226 (see, e.g., a directional arrow). As the mud exits the drillstring 225 via ports in the drill bit 226, it may then circulate upwardly through an annular region between an outer surface(s) of the drillstring 225 and surrounding wall(s) (e.g., open borehole, casing, etc.), as indicated by directional arrows. In such a manner, the mud lubricates the drill bit 226 and carries heat energy (e.g., frictional or other energy) and formation cuttings to the surface where the mud (e.g., and cuttings) may be returned to the mud tank 201 , for example, for recirculation (e.g., with processing to remove cuttings, etc.).

[0050] The mud pumped by the pump 204 into the drillstring 225 may, after exiting the drillstring 225, form a mudcake that lines the wellbore which, among other functions, may reduce friction between the drillstring 225 and surrounding wall(s) (e.g., borehole, casing, etc.). A reduction in friction may facilitate advancing or retracting the drillstring 225. During a drilling operation, the entire drillstring 225 may be pulled from a wellbore and optionally replaced, for example, with a new or sharpened drill bit, a smaller diameter drillstring, etc. As mentioned, the act of pulling a drillstring out of a hole or replacing it in a hole is referred to as tripping. A trip may be referred to as an upward trip or an outward trip or as a downward trip or an inward trip depending on trip direction.IS24.1553-WO-PCT

[0051] As an example, consider a downward trip where upon arrival of the drill bit 226 of the drillstring 225 at a bottom of a wellbore, pumping of the mud commences to lubricate the drill bit 226 for purposes of drilling to enlarge the wellbore. As mentioned, the mud may be pumped by the pump 204 into a passage of the drillstring 225 and, upon filling of the passage, the mud may be used as a transmission medium to transmit energy, for example, energy that may encode information as in mud-pulse telemetry.

[0052] As an example, mud-pulse telemetry equipment may include a downhole device configured to effect changes in pressure in the mud to create an acoustic wave or waves upon which information may modulated. In such an example, information from downhole equipment (e.g., one or more modules of the drillstring 225) may be transmitted uphole to an uphole device, which may relay such information to other equipment for processing, control, etc.

[0053] As an example, telemetry equipment may operate via transmission of energy via the drillstring 225 itself. For example, consider a signal generator that imparts coded energy signals to the drillstring 225 and repeaters that may receive such energy and repeat it to further transmit the coded energy signals (e.g., information, etc.).

[0054] As an example, the drillstring 225 may be fitted with telemetry equipment 252 that includes a rotatable drive shaft, a turbine impeller mechanically coupled to the drive shaft such that the mud may cause the turbine impeller to rotate, a modulator rotor mechanically coupled to the drive shaft such that rotation of the turbine impeller causes said modulator rotor to rotate, a modulator stator mounted adjacent to or proximate to the modulator rotor such that rotation of the modulator rotor relative to the modulator stator creates pressure pulses in the mud, and a controllable brake for selectively braking rotation of the modulator rotor to modulate pressure pulses. In such an example, an alternator may be coupled to the aforementioned drive shaft where the alternator includes at least one stator winding electrically coupled to a control circuit to selectively short the at least one stator winding to electromagnetically brake the alternator and thereby selectively brake rotation of the modulator rotor to modulate the pressure pulses in the mud.

[0055] In the example of Fig. 2, an uphole control and / or data acquisition system 262 may include circuitry to sense pressure pulses generated by telemetry equipmentIS24.1553-WO-PCT252 and, for example, communicate sensed pressure pulses or information derived therefrom for process, control, etc.

[0056] The assembly 250 of the illustrated example includes a logging-while-drilling (LWD) module 254, a measurement-while-drilling (MWD) module 256, an optional module 258, a rotary-steerable system (RSS) and / or motor 260, and the drill bit 226. Such components or modules may be referred to as tools where a drillstring may include a plurality of tools.

[0057] As to an RSS, it involves technology utilized for directional drilling.Directional drilling involves drilling into the Earth to form a deviated bore such that the trajectory of the bore is not vertical; rather, the trajectory deviates from vertical along one or more portions of the bore. As an example, consider a target that is located at a lateral distance from a surface location where a rig may be stationed. In such an example, drilling may commence with a vertical portion and then deviate from vertical such that the bore is aimed at the target and, eventually, reaches the target. Directional drilling may be implemented where a target may be inaccessible from a vertical location at the surface of the Earth, where material exists in the Earth that may impede drilling or otherwise be detrimental (e.g., consider a salt dome, etc.), where a formation is laterally extensive (e.g., consider a relatively thin yet laterally extensive reservoir), where multiple bores are to be drilled from a single surface bore, where a relief well is desired, etc.

[0058] One approach to directional drilling involves a mud motor; however, a mud motor may present some challenges depending on factors such as rate of penetration (ROP), transferring weight to a bit (e.g., weight on bit, WOB) due to friction, etc. A mud motor may be a positive displacement motor (PDM) that operates to drive a bit (e.g., during directional drilling, etc.). A PDM operates as drilling fluid is pumped through it where the PDM converts hydraulic power of the drilling fluid into mechanical power to cause the bit to rotate.

[0059] As an example, a mud motor (e.g., PDM) may be operated in different modes, which may include a rotating mode and a sliding mode. A sliding mode involves drilling with a mud motor rotating the bit downhole without rotating the drillstring from the surface; noting that the drillstring may be oscillated from the surface clockwise andIS24.1553-WO-PCTcounter-clockwise to reduce friction, etc. Such an operation may be conducted when a BHA has been fitted with a bent sub or a bent housing mud motor, or both, for directional drilling. Sliding may be used in building and controlling or adjusting hole angle. In directional drilling, pointing of a bit may be accomplished through a bent sub, which may have a relatively small angle offset from the axis of a drillstring, and a measurement device to determine the direction of offset. Without turning the drillstring as in rotary drilling (e.g., a rotating mode), the bit may be rotated with mud flow through the mud motor to drill in the direction it is pointed. With steerable motors, when a desired wellbore direction is attained, the entire drillstring may be rotated to drill straight rather than at an angle. By controlling the amount of hole drilled in the sliding mode versus the rotating mode, a wellbore trajectory may be controlled rather precisely.

[0060] As an example, a PDM may operate in a combined rotating mode where surface equipment is utilized to rotate a bit of a drillstring (e.g., a rotary table, a top drive, etc.) by rotating the entire drillstring and where drilling fluid is utilized to rotate the bit of the drillstring. In such an example, a surface RPM (SRPM) may be determined by use of the surface equipment and a downhole RPM of the mud motor may be determined using various factors related to flow of drilling fluid, mud motor type, etc. As an example, in the combined rotating mode, bit RPM may be determined or estimated as a sum of the SRPM and the mud motor RPM, assuming the SRPM and the mud motor RPM are in the same direction.

[0061] As an example, a PDM mud motor may operate in a so-called sliding mode, when the drillstring is not rotated from the surface. In such an example, a bit RPM may be determined or estimated based on the RPM of the mud motor.

[0062] An RSS may drill directionally where there is continuous rotation from surface equipment, which may alleviate the sliding of a steerable motor (e.g., a PDM). An RSS may be deployed when drilling directionally (e.g., deviated, horizontal, or extended-reach wells). An RSS may aim to minimize interaction with a borehole wall, which may help to preserve borehole quality. An RSS may aim to exert a relatively consistent side force akin to stabilizers that rotate with the drillstring or orient the bit in the desired direction while continuously rotating at the same number of rotations per minute as the drillstring.IS24.1553-WO-PCT

[0063] The LWD module 254 may be housed in a suitable type of drill collar and may contain one or a plurality of selected types of logging tools. It will also be understood that more than one LWD and / or MWD module may be employed. Where the position of an LWD module is mentioned, as an example, it may refer to a module at the position of the LWD module 254, the MWD module 256, etc. An LWD module may include capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment. In the illustrated example, the LWD module 254 may include a seismic measuring device.

[0064] The MWD module 256 may be housed in a suitable type of drill collar and may contain one or more devices for measuring characteristics of the drillstring 225 and the drill bit 226. As an example, the MWD module 256 may include equipment for generating electrical power, for example, to power various components of the drillstring 225. As an example, the MWD module 256 may include the telemetry equipment 252, for example, where the turbine impeller may generate power by flow of the mud; it being understood that other power and / or battery systems may be employed for purposes of powering various components. As an example, the MWD module 256 may include one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device.

[0065] Fig. 2 also shows some examples of types of holes that may be drilled. For example, consider a slant hole 272, an S-shaped hole 274, a deep inclined hole 276 and a horizontal hole 278.

[0066] As an example, a drilling operation may include directional drilling where, for example, at least a portion of a well includes a curved axis. For example, consider a radius that defines curvature where an inclination with regard to the vertical may vary until reaching an angle between about 30 degrees and about 60 degrees or, for example, an angle to about 90 degrees or possibly greater than about 90 degrees.

[0067] As an example, a directional well may include several shapes where each of the shapes may aim to meet particular operational demands. As an example, a drilling process may be performed on the basis of information as and when it is relayedIS24.1553-WO-PCTto a drilling engineer. As an example, inclination and / or direction may be modified based on information received during a drilling process.

[0068] As an example, deviation of a bore may be accomplished in part by use of a downhole motor and / or a turbine. As to a motor, for example, a drillstring may include a positive displacement motor (PDM).

[0069] As an example, a system may be a steerable system and include equipment to perform method such as geosteering. As mentioned, a steerable system may be or include an RSS. As an example, a steerable system may include a PDM or of a turbine on a lower part of a drillstring which, just above a drill bit, a bent sub may be mounted. As an example, above a PDM, MWD equipment that provides real time or near real time data of interest (e.g., inclination, direction, pressure, temperature, real weight on the drill bit, torque stress, etc.) and / or LWD equipment may be installed. As to the latter, LWD equipment may make it possible to send to the surface various types of data of interest, including for example, geological data (e.g., gamma ray log, resistivity, density and sonic logs, etc.).

[0070] As an example, geosteering may be employed (e.g., control of directional drilling using geological data). The coupling of sensors providing information on the course of a well trajectory, in real time or near real time, with, for example, one or more logs characterizing the formations from a geological viewpoint, may allow for implementing a geosteering method. Such a method may include navigating a subsurface environment, for example, to follow a desired route to reach a desired target or targets.

[0071] As an example, a drillstring may include an azimuthal density neutron (ADN) tool for measuring density and porosity; a MWD tool for measuring inclination, azimuth and shocks; a compensated dual resistivity (CDR) tool for measuring resistivity and gamma ray related phenomena; one or more variable gauge stabilizers; one or more bend joints; and a geosteering tool, which may include a motor and optionally equipment for measuring and / or responding to one or more of inclination, resistivity and gamma ray related phenomena.

[0072] As an example, geosteering may include intentional directional control of a wellbore based on results of downhole geological logging measurements in a mannerIS24.1553-WO-PCTthat aims to keep a directional wellbore within a desired region, zone (e.g., a pay zone), etc. As an example, geosteering may include directing a wellbore to keep the wellbore in a particular section of a reservoir, for example, to minimize gas and / or water breakthrough and, for example, to maximize economic production from a well that includes the wellbore.

[0073] Referring again to Fig. 2, the wellsite system 200 may include one or more sensors 264 that are operatively coupled to the control and / or data acquisition system 262. As an example, a sensor or sensors may be at surface locations. As an example, a sensor or sensors may be at downhole locations. As an example, a sensor or sensors may be at one or more remote locations that are not within a distance of the order of about one hundred meters from the wellsite system 200. As an example, a sensor or sensor may be at an offset wellsite where the wellsite system 200 and the offset wellsite are in a common field (e.g., oil and / or gas field).

[0074] As an example, one or more of the sensors 264 may be provided for tracking pipe, tracking movement of at least a portion of a drillstring, etc.

[0075] As an example, the system 200 may include one or more sensors 266 that may sense and / or transmit signals to a fluid conduit such as a drilling fluid conduit (e.g., a drilling mud conduit). For example, in the system 200, the one or more sensors 266 may be operatively coupled to portions of the standpipe 208 through which mud flows. As an example, a downhole tool may generate pulses that may travel through the mud and be sensed by one or more of the one or more sensors 266. In such an example, the downhole tool may include associated circuitry such as, for example, encoding circuitry that may encode signals, for example, to reduce demands as to transmission. As an example, circuitry at the surface may include decoding circuitry to decode encoded information transmitted at least in part via mud-pulse telemetry. As an example, circuitry at the surface may include encoder circuitry and / or decoder circuitry and circuitry downhole may include encoder circuitry and / or decoder circuitry. As an example, the system 200 may include a transmitter that may generate signals that may be transmitted downhole via mud (e.g., drilling fluid) as a transmission medium.

[0076] As an example, one or more portions of a drillstring may become stuck. The term stuck may refer to one or more of varying degrees of inability to move orIS24.1553-WO-PCTremove a drillstring from a bore. As an example, in a stuck condition, it might be possible to rotate pipe or lower it back into a bore or, for example, in a stuck condition, there may be an inability to move the drillstring axially in the bore, though some amount of rotation may be possible. As an example, in a stuck condition, there may be an inability to move at least a portion of the drillstring axially and rotationally.

[0077] As to the term “stuck pipe”, this may refer to a portion of a drillstring that cannot be rotated or moved axially. As an example, a condition referred to as “differential sticking” may be a condition whereby the drillstring cannot be moved (e.g., rotated or reciprocated) along the axis of the bore. Differential sticking may occur when high-contact forces caused by low reservoir pressures, high wellbore pressures, or both, are exerted over a sufficiently large area of the drillstring. Differential sticking may have time and financial cost.

[0078] As an example, a sticking force may be a product of the differential pressure between the wellbore and the reservoir and the area that the differential pressure is acting upon. This means that a relatively low differential pressure (delta p) applied over a large working area may be just as effective in sticking pipe as may a high differential pressure applied over a small area.

[0079] As an example, a condition referred to as “mechanical sticking” may be a condition where limiting or prevention of motion of the drillstring by a mechanism other than differential pressure sticking occurs. Mechanical sticking may be caused, for example, by one or more of junk in the hole, wellbore geometry anomalies, cement, keyseats or a buildup of cuttings in the annulus.

[0080] As explained, a wellsite system may include various types of equipment for handling fluid such as, for example, drilling fluid (e.g., mud). As explained, drilling fluid may provide one or more functions (e.g., lubrication, transport of cutting, etc.).

[0081] Drilling fluid may be composed of a number of liquid and / or gaseous fluids and mixtures of fluids and solids (e.g., as solid suspensions, mixtures and emulsions of liquids, gases and solids) as may be used in various operations to drill boreholes into the earth. Classifications of drilling fluids may utilize one or more types of classification schemes. For example, consider water-based mud (WBM), oil-based mud (OBM),IS24.1553-WO-PCTnonaqueous-based mud (NQBM), gaseous-based mud (e.g., pneumatic, etc.) (GBM), etc.

[0082] As explained, a drillstring may include a mud motor that is rotationally driven by flow of drilling fluid. In such a mode of drilling, the characteristics of drilling fluid may impact mud motor performance. For example, density (e.g., mud weight) may impact how much energy the mud motor may deliver to a drill bit for a given drilling fluid flow rate.

[0083] As to a stuck pipe or risk of sticking event, as explained, one or more actions may be taken. For example, consider addition of acid as a remedial action to address the stuck pipe event or to reduce the risk of a sticking event. In such an example, a number of barrels of acid may be added to drilling fluid that is circulated downhole to an annular region between a drilling string and a bore wall in an effort to “dissolve” material that is causing sticking or a risk of sticking. While addition of acid is mentioned, it may be an action within a tiered series of actions that may be taken, where, for example, each action may have associated benefits and detriments. As to detriments, these may include non-productive time (NPT), cost, further remedial actions (e.g., impact of acid on one or more additives in drilling fluid), etc. Hence, where an event occurs or a risk of an event is heightened, in an effort to maintain adherence to a plan, one or more actions may be implemented in a strategic manner to resolve the event or otherwise reduce the risk.

[0084] Fig. 3 shows an example of a wellsite system 300, specifically, Fig. 3 shows the wellsite system 300 in an approximate side view and an approximate plan view along with a block diagram of a system 370.

[0085] In the example of Fig. 3, the wellsite system 300 may include a cabin 310, a rotary table 322, drawworks 324, a mast 326 (e.g., optionally carrying a top drive, etc.), mud tanks 330 (e.g., with one or more pumps, one or more shakers, etc.), one or more pump buildings 340, a boiler building 342, an HPU building 344 (e.g., with a rig fuel tank, etc.), a combination building 348 (e.g., with one or more generators, etc.), pipe tubs 362, a catwalk 364, a flare 368, etc. Such equipment may include one or more associated functions and / or one or more associated operational risks, which may be risks as to time, resources, and / or humans.IS24.1553-WO-PCT

[0086] As shown in the example of Fig. 3, the cabin 310 may be positioned near the rig, for example, near the rig floor such that a line-of-sight view may be established between the cabin 310 and the rig floor (e.g., via an opening, a window, etc.). As shown, the cabin 310 may house equipment such as, for example, a chair 312 and a display 314. In such an example, the chair 312 may be an operator chair. As an example, the cabin 310 may include one or more doors for access thereto. As an example, the chair 312 may include a swivel base such that an operator may rotate, tilt, etc., the chair 312.

[0087] As shown in the example of Fig. 3, the wellsite system 300 may include a system 370 that includes one or more processors 372, memory 374 operatively coupled to at least one of the one or more processors 372, instructions 376 that may be, for example, stored in the memory 374, and one or more interfaces 378. As an example, the system 370 may include one or more processor-readable media that include processor-executable instructions executable by at least one of the one or more processors 372 to cause the system 370 to control one or more aspects of the wellsite system 300. In such an example, the memory 374 may be or include the one or more processor-readable media where the processor-executable instructions may be or include instructions. As an example, a processor-readable medium may be a computer-readable storage medium that is not a signal and that is not a carrier wave.

[0088] Fig. 3 also shows a battery 380 that may be operatively coupled to the system 370, for example, to power the system 370. As an example, the battery 380 may be a back-up battery that operates when another power supply is unavailable for powering the system 370. As an example, the battery 380 may be operatively coupled to a network, which may be a cloud network. As an example, the battery 380 may include smart battery circuitry and may be operatively coupled to one or more pieces of equipment via a SMBus or other type of bus.

[0089] In the example of Fig. 3, services 390 are shown as being available, for example, via a cloud platform. Such services may include data services 392, query services 394 and drilling services 396. As an example, the services 390 may be part of a system such as the system 100 of Fig. 1 (e.g., consider planning services and / or operational services). As an example, the services 390 may include one or moreIS24.1553-WO-PCTservices for directional drilling (e.g., consider a computational framework that may provide for one or more services that utilize real-time data to estimate one or more parameters, etc.).

[0090] As an example, the system 370 may be utilized to generate one or more rate of penetration drilling parameter values, which may, for example, be utilized to control one or more drilling operations.

[0091] Fig. 4 shows an example of a system 400 that includes offsite equipment 401 (e.g., remote) and onsite equipment 402 (e.g., local). As shown, the offsite equipment 401 may include a drill operations framework 410, a drill planning framework 420 and a database 430 and the onsite equipment 402 may include a controller 440 that may receive real-time data and output recommendations such as control instructions to control onsite equipment. In such an example, the drill operations framework 410 may provide for steering sheets, execution parameters, etc., and the drill planning framework 420 may provide for evaluation of steering responses and statistics. As shown, the controller 440 may output information to the drill operations framework 410 and receive information from the drill planning framework 420. The system 400 may include plan generation features for real-time plan generation during drilling operations execution phase and / or plan generation during a planning phase. The system 400 may be utilized for one or more types of drilling (e.g., rotary, mud motor, RSS, ABSS, etc.). The system 400 may operate loops, which may include at least one real-time loop that provides for control of equipment to perform drilling operations.

[0092] A system such as the system 400 may utilize various functions and constraints for generation of plans, which may provide for single or multiple target aiming. As explained, a plan may be generated that aims to provide for drilling operations for a multiwell structure. As explained, a plan may be a digital plan that may be utilized to instruct one or more controllers such as, for example, an autodriller controller, which may control one or more pieces of equipment (e.g., a drawworks, a top drive, one or more drilling fluid pumps, etc.). As an example, an autodriller may control energy delivered via one or more pieces of equipment to a drill bit where the drill bit crushes and / or cuts rock to extend a borehole. As an example, an autodriller may beIS24.1553-WO-PCTcontrolled in an effort that aims to minimize or otherwise reduce mechanical specific energy (MSE) and to maximize or otherwise increase rate of penetration (ROP).

[0093] As explained with respect to the system 100 of Fig. 1 , various computational frameworks may be utilized to perform one or more workflows, which may include planning workflows, workflows involving control of field operations, workflows in real-time or near real-time, assessment workflows (e.g., for issues, successes, etc.), etc. As explained, one or more visualization features may be provided and utilized, for example, to implement visualization processes that may be suitable for one or more web applications. As mentioned, JSON and / or one or more other languages and / or formats may be utilized.

[0094] As an example, a framework may provide for generation of performance indicators for equipment. In such an example, the framework may include various automated procedures that may, for example, respond to one or more triggers to generate performance indicators for equipment. As an example, one or more performance indicators may be utilized by one or more other frameworks. For example, consider a workflow where automated generation of one or more performance indicators may cause one or more actions by one or more other frameworks, which may provide for tasks such as, for example, planning, optimization, control of field operations, etc.

[0095] As explained, sticking may occur during one or more operations where, for one or more reasons, a drillstring, a tool string, etc., sticks in a borehole. Such sticking may occur during rotational and / or translational movement, which may be via a rig, downhole equipment, etc. A condition known as stick-slip may involve irregular movement of a drillstring or a tool string in a borehole due to it being stuck at some point and then being released. As an example, stick-slip may involve torsional vibration that may occur when a bit, a BHA, and / or a drillstring experience rotational speeds that may differ from those expected. During sticking, rotation at a bit of a drillstring may slow down or stop such that reactive torque builds up in the drillstring. Such torque may build until it reaches a point where dynamic friction exceeds static friction at the bit such that the built-up torque in the drillstring releases (e.g., slips). In such an example, the release can cause a drillstring to unwind, thereby resulting in an increase in rotationalIS24.1553-WO-PCTspeed of a bit, which may be to an excessive rotational speed that increases risk of damage (e.g., to a bit, a BHA, a drillstring, a borehole, etc.). In various instances, a drillstring may over-rotate in a clockwise direction such that rotation in a counterclockwise direction is required for adjustment to desirable levels of torque.

[0096] In severe instances, stick-slip can result in non-productive time (NPT), which may involve failure of a downhole motor, twist-off, damage to a drill bit, etc. In a twist-off scenario, there may be a parting or breaking of a drillstring downhole due to fatigue or excessive torque. As to parting, a portion of a drillstring may twist-off such that it becomes detached from another portion of the drillstring. For example, one or more BHA components (e.g., drilling jars, shock tools, mud motors, roller reamers, stabilizers, drill collars, PBLs, heavy weight drill pipe (HWDP), drill pipe (DP), etc.) may detach or twist such that future risk of detachment is elevated.

[0097] Stick-slip motion of a BHA may be classified, for example, into one or more classes. For example, stick-slip may be classified as extreme, self-sustained oscillations of a lowest torsional mode (e.g., a pendulum mode). Such a motion may be characterized by finite time intervals during which a bit is non-rotating and a drillpipe section is twisted by a rotary table or a top drive. When the drillstring torque reaches a certain level (e.g., as may be determined by the static friction resistance of a BHA), the BHA may break free and speed up to more than twice the nominal speed before it slows down and again comes to a complete stop. Such motion can represent a large cyclic stress in drillpipe that can lead to fatigue problems. In addition, a high bit speed level in a slip phase can induce severe axial and lateral vibrations in a BHA, which can be damaging to one or more connections. Drilling with stick-slip motion can lead to excessive bit wear and also a reduction in ROP. Frequency analysis of the driving torque associated with torsional drillstring vibrations, in particular stick-slip oscillations, reveals a large number of torsional drillstring resonances. Sharpness of a curve at a drillstring resonance frequency may indicate there is little damping of torsional drillstring vibrations (see, e.g., Halsey, G. W., Kyllingstad, A., and A. Kylling. "Torque Feedback Used to Cure Slip-Stick Motion." Paper presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, October 1988. doi:IS24.1553-WO-PCThttps: / / doi.org / 10.2118 / 18049-MS, which is incorporated by reference herein in its entirety).

[0098] Stick-slip can generate torsional waves travelling from the bottom of a drillstring back to the surface which may be registered in top drive torque readings, which may show oscillations in different degrees of magnitude. Minimum and maximum torque values may be captured from filtered torque data and a difference determined using these two values. As an example, a so-called surface stick slip index (SSSI) may be determined by dividing the difference of the maximum and minimum torque values by a moving average torque (e.g., times 2) over a constant selected time period.

[0099] Potential concerns regarding such an approach of determining the SSSI include: (1) the variable reference torque at the denominator; and (2) a fixed time period. SSSI is a fractional value with both numerator and denominator changing whereby values of both numerator and denominator at the time have to be known to determine the magnitude of oscillation. Using a moving average torque over a selected time period to calculate the SSSI may not be an ideal way of representation of stick-slip when encountering different formations where average torque may be different for the same amount of magnitude (Max Torque-Min Torque) of an oscillation. Additionally, the aforementioned SSSI approach uses a sliding time window of selected time period to determine the maximum and minimum torque values. Such an approach may not be efficient to use a fixed time period as oscillation time period may vary substantially with hole depth or string length. A fixed time period may have to use an unnecessarily large value to be long enough to cover the cycle.

[0100] As an example, stick-slip mitigation control may be improved through use of a surface torque oscillation performance index (STOPI), which may be a fractional value to indicate magnitude and severity of surface torque fluctuations of a drilling rig, whose numerator is the difference between a computed maximum surface torque value and a minimum one in a dynamically specified time period, and denominator that is a configurable constant torque value (e.g., a top drive rated torque). As an example, STOPI may be computed in real time, updated in a preset short time period and reported to an external display. In such an approach, the denominator may be a constant reference torque, and a varying time window may correspond to a fundamentalIS24.1553-WO-PCTfrequency of a drillstring so as to provide a more responsive and current control approach to mitigation of stick-slip. The aforementioned STOPI approach provides a reasonable manner for a human drilling operator or a computer controller to visualize or otherwise determine whether stick-slip oscillations are occurring, which may be a basis for mitigation via human and / or machine interventions.

[0101] Fig. 5 shows a block diagram of an example of a workflow 500, which may operate according to supervisory control 502 and / or local control 504. The workflow 500 may provide for improved control of a drillstring with respect to stick-slip, for example, using the aforementioned STOPI approach, where STOPI is an index. As shown, an acquisition block 510 can provide for acquisition of raw torque measurements, for example, as a torque present value (RawTrqPv), which may be acquired from a VFD related to a top drive, a torque sub located between a top drive 15 and a drillstring, etc. In such an example, torque present value (RawTrqPv) data may be filtered per a filter block 520, which may implement, for example, a low pass filter or a band pass filter. As an example, one or more cutoff frequencies may be predetermined fixed values. As an example, if formations to be drilled for a borehole are known as fairly constant, a low pass filter may be applied, otherwise, for example, a band pass filter may be applied.

[0102] As an example, in the workflow 500, parameters of a drillstring length (e.g., hole depth) and drillstring properties may be acquired by an acquisition block 530, which may provide for acquisition from the local control 504 and / or the supervisory control 502 (e.g., at one or more higher levels of a hierarchical control network).

[0103] As shown in the example of Fig. 5, the workflow 500 may implement a computation block 540 for computing a length of a moving window by estimating a fundamental oscillation time period T1 utilized for oscillating a drillstring (e.g., via a top drive). As an example, one or more techniques may be used to derive a fundamental time period T1 (see, e.g., Kyllingstad, A., and G. W. Halsey. “A Study of Slip / Stick Motion of the Bit.” SPE Drill Eng 3 (1988): 369-373. doi: https: / / doi.org / 10.2118 / 16659-PA, incorporated herein in its entirety). U.S. Patent No. 10,782,197 B2 is incorporated herein by reference in its entirety, which includes examples of equations that may be utilized for establishing a time interval T for a moving window.IS24.1553-WO-PCT

[0104] As an example, the workflow 500 may establishes a time interval T for a moving window where a factor alpha (a) may be utilized as a safety factor, for example, set between 1.0 and 2.0 to help ensure that a moving window covers a full cycle of oscillation at the time. As an example, based on T, a length of a moving window can be determined by dividing a control system sampling time AT with T. As an example, such a window length may be rounded to be an integer. As an example, an equation such as T - aT1 may be utilized.

[0105] As shown, the workflow 500 may include a sort block 550 for sorting a stored torque value array (e.g., with the size of window length) to obtain the largest values p (e.g., p max.) and lowest values q (e.g., q min.), where p and q are integers equal to or larger than 1. In such an approach, a subtraction block 560 may subtract an average of the q values from an average of the p values derived from the sorted torque value array. In such an approach, the difference between the two resulting average values provides an amplitude of torsional fluctuations.

[0106] As shown, the workflow 500 may include a division block 570 to divide the resulting difference value (amplitude of torsional fluctuations) by selected constant reference torque values per a block 565. In such an example, a default setting may be a rated torque of a top drive. As an example, reference torque values may be or include off-bottom torque, at-bottom torque, etc. As an example, off-bottom torque may be measured by rotating off bottom (ROffB), which is where pipe rotates without axial movement, such as rate of penetration or tripping, and there is no weight on bit (WOB) or torque on bit (TOB) because the bit is not engaged with a formation. At-bottom torque may be measured by rotating on bottom (ROnB), which is where pipe rotates without axial movement, such as rate of penetration or tripping, but weight on bit (WOB) and torque on bit (TOB) are present because bit is engaged with a formation. As an example, a selection of reference torque may be dependent on availability and choice of rig personnel. As shown in the workflow 500, the quotient of the division from the division block 570 may be a STOPIc value 575, which may be a surface torque oscillation performance index value. As an example, the STOPIc value may be limited per a limitation block 580, for example, between a maximum value per a maximum block 577 and a minimum value per a minimum block 579.IS24.1553-WO-PCT

[0107] As shown, a polling or average computation block 582 may provide for output of a STOPIavg per a block 584 and / or output of a STOPIc per a block 586. In such an example, the workflow 500 may include an output block 590 that may provide for displaying one or more values, trends, control actions, etc., an external display such as a HMI or a computer screen. As an example, as to a display update time, the workflow 500 may decide whether to utilize a polling technique or an average value for the purpose of display, control action, etc.

[0108] As an example, a STOPIc computation may be enabled or disabled. As an example, when disabled, operation may be based on one or more preset conditions (e.g., bit not at bottom, TD speed setpoint changes, drilling controller off, etc.) where, for example, a null value or a high mark integer value may be assigned to STOPI for logging (e.g., data archiving, etc.), which may clarify the disabled status without being misleading. As an example, the workflow 500 may be implemented as part of a rig control system (RCS).

[0109] As an example, a controller may be operable to mitigate risk of stick-slip. As to mitigation by a human operator, such an operator may need to first identify a type of downhole vibration that may be occurring. For example, consider watching for symptoms of stick-slip, such as a sudden decrease in rate of penetration, a large torque envelope in a torque signal, or, in severe cases, top drive stalling. An experienced operator may overlook one or more of such symptoms for an extended period of time, which may increase risk of stick-slip damage.

[0110] As to a human operator response that may aim to mitigate stick-slip, consider manually decreasing weight on bit (WOB) and then increasing rotary speed of the drillstring (e.g., surface RPM). Such a process may be repeated until stick-slip is sufficiently mitigated, for example, to a point where normal drilling operation can resume.

[0111] As an example, a framework may provide for automatic detection of one or more indicators for stick-slip. Such a framework may be integrated (e.g., embedded) into a controller or otherwise operatively coupled thereto. As an example, a framework may provide for stick-slip mitigation in an automated manner where one or more control actions are performed responsive to detection of one or more indicators of stick-slip.IS24.1553-WO-PCT

[0112] As an example, a framework may provide for computation of an indicator for stick-slip mitigation, which may be implemented by one or more control systems. For example, consider implementation by a DrillSync Oscillator controller application (SLB, Houston, Texas). The DrillSync Oscillator controller application may enable higher performance via automated oscillation in a manner that increases productivity by optimizing sliding ROP and that provides accurate angle and direction control. For example, such a controller application may provide for synchronizing surface and downhole parameters, increasing drilling efficiency, improving equipment use, and delivering data analytics aimed at enhancing performance and reducing well construction time. As an example, for slide drilling, friction between drillpipe and a borewall may have an impact on ROP. In such an example, the DrillSync Oscillator controller application may automate oscillation control to decrease friction, for example, without changing downhole toolface (TF). Such an approach may enhance weight transfer to a drill bit, resulting in higher ROP while slide drilling. In addition, the DrillSync Oscillator controller application may provide an orient function that enables a directional driller (e.g., human and / or machine) to attain a desired toolface (TF), providing added versatility and precision in one or more drilling operations.

[0113] The aforementioned DrillSync Oscillator controller application may offer angle- or torque-based control options for oscillating drillpipe to improve weight transfer to a drill bit and for orienting one or more downhole motors for drilling in a desired direction. As an example, a driller may also have an ability to set oscillating and orienting RPM. As an example, the DrillSync Oscillator controller application may automatically calibrate and orient a top drive in a desired direction, streamlining drilling processes and improving overall efficiency.

[0114] In a slide drilling mode (e.g., sliding mode, etc.), stick-slip vibration may not be detected as a top drive may be operating in an oscillating manner where rotations in clockwise and counter-clockwise directions are utilized, which may be less than a few rotations in each of those opposing directions. As explained, stick-slip vibration may arise from a drillstring acting as a torsional spring during rotary drilling where the drillstring stores energy and releases the stored energy. In general, in a slide drilling mode, energy tends to be dissipated rather than stored due oscillating rotationsIS24.1553-WO-PCTof a top drive, which are relatively limited in number of rotations (e.g., or fractions of a rotation in clockwise and counter-clockwise directions). For example, consider an approach that causes energy storage followed by energy release as a top drive oscillates.

[0115] As an example, one or more types of a surface-controlled rotary drilling software plug-in / add-on for mitigating stick-slip vibrations while rotary drilling may be utilized. Such a controller application may help to protect downhole tools by reducing excessive and erratic torsional vibration. Such an approach may help to maintain a more consistent torque across sections of a drillstring, lessening wear and tear on a bit and other downhole equipment, increasing ROP, and limiting bit trips. Such an approach may provide for longer, uninterrupted bit runs.

[0116] As an example, a controller application may integrate relatively seamlessly into an AC variable frequency drive (VFD) control system, for example, to control a top drive motor or motors. As an example, such a controller application may be integrated into a standalone HMI or operated from an existing HMI. As an example, such a controller application may provide for modifying speed loop gains in a top drive controller (VFD), for example, in an effort to match characteristics of a top drive motor to stiffness of drillpipe. As an example, a controller application may provide a relatively high-speed data historian, for example, consider sampling at a rate of approximately 200 times / sec.

[0117] As an example, a framework may provide for control of one or more modes of drilling. For example, consider a framework that may provide for control in a sliding mode and for control in a rotary mode. In such an example, one or more features of the framework may be enabled or disabled. As an example, a method may include automatically enabling and / or disabling one or more features responsive to a transition between one mode and another mode. For example, consider enabling a stick-slip feature responsive to a transition from a sliding mode to a rotary mode and disabling a stick-slip feature responsive to a transition from a rotary mode to a sliding mode. In such an example, a method may include automatically enabling and / or disabling a sliding mode feature and / or a rotary mode feature, such as, for example, a feature of the DrillSync Oscillator controller application, a feature of one or more typesIS24.1553-WO-PCTof controller applications, etc. As explained, where drilling may be performed in multiple modes, a framework may provide for orchestrating controller features in an automated manner. As an example, torque (e.g., downhole and / or surface) measurements may be acquired in one or more modes where in various instances measurements in one mode may be relevant or informative as to control of drilling in another mode or, for example, during running-in-hole (RIH) and / or pulling-out-of-hole (POOH).

[0118] Various approaches to mitigation of stick-slip have been mentioned, some of which may utilize an index, which may be a performance index (e g., SSSI). As an example, a performance index (PI) may be a key performance index (KPI), which may be a particular type of performance index associated with tracking a certain type of performance. Stick-slip mitigation Pls (or KPIs) tend to concentrate on looking at the existence of stick-slip vibration and the severity of the stick-slip vibration. This can pose a substantial challenge to an operator where it is unknown if the stick-slip vibration severity is low because: (1) there is actually no stick-slip condition existing downhole; or (2) the stick-slip vibration system is actually effective, and it is mitigating the downhole stick-slip vibration.

[0119] As an example, a controller, which may be a controller application, may provide for computation of a performance index that may be referred to as a mitigated stick-slip index (MSSI). Such an index may take into consideration effort contributed by a stick-slip mitigation controller in conjunction with a stick-slip severity indicator. In such an example, the index may correlate how much a stick-slip mitigation controller has been able to reduce downhole stick-slip vibration. In such an example, the stick-slip mitigation controller may be effectively optimized, which may include tailoring control action for particular scenarios. In such an example, in scenarios where a stick-slip controller may lack effectiveness, a controller may provide for taking one or more alternative approaches to stick-slip mitigation, which may involve human and / machine control action.

[0120] As an example, a control application may provide for computation of SSSI, STOPI, MSSI, and / or one or more other indexes. As an example, a control application, which may be a computational framework, may provide for utilization of multiple indexes to improve one or more field operations.IS24.1553-WO-PCT

[0121] As an example, a framework may provide for determining effectiveness of a stick-slip mitigation controller, for example, consider determining degree by which such a controller effectively reduced downhole stick slip vibration. As an example, such a framework may combine a stick-slip severity index (e.g., STOPI) with a determined effort that a stick-slip mitigation controller puts on a drillstring.

[0122] As an example, a framework may provide for determining effort that a stick-slip mitigation controller put on a drillstring via detection of changes and / or fluctuations on top drive RPM. For example, when there is no detection of change in top drive RPM (e.g., according to one or more metrics, thresholds, etc.), this may indicate that there was no effort performed on a drillstring to mitigate stick-slip vibration (e.g., which may be the case when a stick-slip mitigation controller is disabled or turned off). Whereas, for example, when a stick-slip mitigation controller is turned on, a framework may provide for detection of one or more fluctuations in top drive RPM, which may be, for example, directly proportional to an effort or efforts exerted by the top drive (e.g., a VFD, etc.) to mitigate downhole stick-slip vibration.

[0123] As an example, a framework may provide for acquiring top drive RPM effort using one or more techniques described with respect to the workflow 500 of Fig.5; however, through use of a top drive RPM signal. In such an example, an index may be referred to as a surface RPM oscillation performance index (SROPI).

[0124] As an example, a framework may provide for computation and utilization of STOPI and SROPI, which may be indicators that can be normalized between 0 percent and 100 percent. As an example, a framework may compute a difference between SROPI (e.g., stick-slip mitigation controller effort) and STOPI (e.g., stick-slip severity index) to arrive at the aforementioned MSSI metric. Such a metric may be a performance indicator that shows how much stick-slip has been mitigated using a current stick-slip mitigation controller.

[0125] Fig. 6 shows example plots 600 of various values with respect to time during field operations, which may be rendered to a display as part of one or more graphical user interfaces (GUIs). As shown, the values can include torque values, RPM values and MSSI values, along with STOPI, SROPI, and MSSI values. As shown, given torque values, a framework may determine that stick-slip is present, for example, asIS24.1553-WO-PCTSTOPI may be greater than zero (e.g., or a threshold, etc.). As shown with respect to RPM values (e.g., top drive RPM), mitigation control actions may be absent as top drive RPM is relatively constant (e.g., within one or more limits, etc.). However, as shown in the top drive RPM values with respect to time, at some point in time, effort is made to mitigate the detected stick-slip, as indicated by SROPI values being greater than zero (e.g., or a threshold, etc.). As to the MSSI, which depends on STOPI and SROPI, various negative values indicate that stick-slip is present and that effort has not been expended by top drive RPM control to mitigate stick-slip; whereas, a trending upward toward zero and positive values of MSSI, indicates that effort has been expended via top drive RPM control to mitigate stick-slip. As some point in time, STOPI becomes relatively constant with respect to time, indicating that stick-slip is not occurring.Correspondingly, a reason why may be detected from the SROPI values being greater than zero, indicating that top drive RPM is being controlled in an appropriate manner to mitigate stick-slip. As shown, MSSI, being the difference between SROPI and STOPI tends to stabilize to a relatively constant value that is positive, meaning that SROPI is greater than STOPI and that stick-slip is not occurring due to effective mitigation of stick-slip via control of top drive RPM.

[0126] In the example of Fig. 6, the plots 600 may provide an indication of when stick-slip mitigation control is disabled or enabled. As an example, such an indication may be utilized as feedback to a stick-slip mitigation controller for more effective control, for example, to more expeditiously call for control of top drive RPM to mitigate stick-slip.

[0127] As shown in the example of Fig. 6, if there was a stick-slip condition and the stick-slip mitigation controller was turned off, this will result in negative MSSI values. In such an approach, the more negative the value is the more severe is the stick-slip vibration. Further, where a stick-slip mitigation controller is turned on and able to effectively mitigate stick-slip, then this will result in more positive MSSI values. In such an approach, the more positive the value is the more effective is the stick slip mitigation controller’s ability to damp vibration.

[0128] Fig. 7 shows example plots 700 of various values with respect to time during field operations, which may be rendered to a display as part of one or more graphical user interfaces (GUIs). As shown, the values can include torque values, RPMIS24.1553-WO-PCTvalues and MSSI values, along with STOPI, SROPI, and MSSI values. As shown, given torque values, a framework may determine that stick-slip is present, for example, as STOPI may be greater than zero (e.g., or a threshold, etc.). As shown with respect to RPM values (e.g., top drive RPM), mitigation control actions may be present as top drive RPM is changing (e.g., within one or more limits, etc.).

[0129] In the example of Fig. 7, as shown in the top drive RPM values with respect to time, at some point in time, mitigation control actions are halted, as indicated by SROPI values being approximately zero (e.g., or a threshold, etc.). In such an example, this may occur responsive to a lack of stick-slip being indicated by torque values via STOPI values being approximately zero. As to the MSSI, which depends on STOPI and SROPI, various MSSI values indicate that stick-slip is present and that effort is or has been expended by top drive RPM control to mitigate stick-slip but not damping stick-slip vibration as the MSSI values may be hovering around zero; whereas, a settling to a null value (e.g., approximately zero), indicates that effort has been halted via top drive RPM control to mitigate stick-slip, for example, because stick-slip, itself, has dissipated (e.g., vibrations damped). In such an example, a stick-slip mitigation controller may be tailored to handle scenarios such as those in the initial time period of the plots 700 of Fig. 7. For example, control actions that may be futile in damping vibration, for one or more reasons, may be wasteful and may themselves result in unnecessary wear and tear on equipment.

[0130] As an example, one or more machine learning models may be trained using data. In such an example, feature engineering may be employed whereby a feature may be an index or features may be indexes. For example, consider an approach where feature engineering involves using one or more of STOPI, SROPI, and MSSI as one or more features. In such an example, as explained, MSSI inherently includes STOPI and SROPI, hence MSSI may be a feature that is an index that depends inherently on one or more other indexes. As an example, an aim of feature engineering may be to provide robust performance of a trained machine learning model in a manner whereby a machine learning model may be trained, re-trained, etc., using a limited amount of data where, for example, such data may be relevant data. As an example, feature engineering may provide for training a machine learning model usingIS24.1553-WO-PCTdata from a particular rigsite for drilling a particular borehole. For example, consider an approach where a stick-slip mitigation controller is implemented at a rigsite and various metrics computed where data and / or metrics may be utilized to train a machine learning model whereby the resulting trained machine learning model may be utilized in a control workflow for controlling field operations at the rigsite. In such an example, data and / or data-based metrics (e.g., indexes) may be for a particular section of a borehole, a particular formation, a particular type of drilling mode (e.g., rotary, slide, etc.), etc. In such an example, a machine learning model-based approach may be readily adapted to a section, a formation, a drilling mode, etc., through a limited set of initial data for the section, the formation, the drilling mode, etc., with resulting robust performance, achieved at least in part through feature engineering that utilizes one or more data-based metrics (e.g., indexes) as features.

[0131] As to the nature of feature engineering, consider an image recognition neural network to identify dogs and cats in images. In such an example, an engineered feature may be a ratio of a distance between eyes and a distance from eyes to end of nose. Such an engineered feature does not exist by itself as a single type of image characteristic; rather, it is the result of feature engineering, which may be a complex process that generates a trained machine learning model with enhanced performance and, for example, a demand for less training data. As explained, as to control of equipment at a field site, particularly for drilling, data may be limited and demand for human oversight substantial, which may weigh against implementation of automation, at least at a fully autonomous level. In such scenarios, where feature engineering can deliver a more robust machine learning model with lesser data demands, control may be possible at a more autonomous level (e.g., a higher level of automation). As an example, a framework may provide for training and implementation of one or more machine learning models for control of one or more field operations with reduced occurrence of stick-slip and / or improved mitigation of stick-slip if it does occur.

[0132] Fig. 8 shows example plots 800 of RPM, torque and MSSI values with respect to time from a field trial, which may be rendered to a display as part of one or more graphical user interfaces (GUIs).IS24.1553-WO-PCT

[0133] Fig. 9 shows two sets of example plots 910 and 920 of RPM, torque and MSSI values with respect to time from field trials, which may be rendered to a display as part of one or more graphical user interfaces (GUIs).

[0134] As an example, a controller may utilize a multi-index approach to handling of stick-slip. In such an example, the controller may provide for improved utilization of mechanical energy, electric energy, etc. As an example, a controller may provide for a reduction in emissions from field operations where stick-slip may be suitably mitigated.

[0135] As an example, a controller may provide for control that can reduce wear, risk, etc., of downhole equipment and / or surface equipment. For example, consider reduced risk of downhole twist-off and reduced risk of top drive wear.

[0136] Fig. 10 shows an example of a method 1000 and an example of a system 1090. As shown, the method 1000 may include a reception block 1010 for receiving torque measurements with respect to time associated with a drillstring in a borehole; a reception block 1020 for receiving rotational speed measurements with respect to time associated with a top drive operatively coupled to the drillstring in the borehole, where the top drive is operatively coupled to a stick-slip mitigation controller; a performance block 1030 for performing an assessment of stick-slip mitigation performance of the stick-slip mitigation controller using the torque measurements and the rotational speed measurements; and an adjustment block 1040 for adjusting operation of the stick-slip mitigation controller based at least in part on the assessment.

[0137] Fig. 10 also shows various computer-readable media (CRM) blocks 1011, 1021 , 1031 , and 1041. Such blocks may include instructions that are executable by one or more processors, which may be one or more processors of a computational framework, a system, a computer, etc. A computer-readable medium may be a computer-readable storage medium that is not a signal, not a carrier wave and that is non-transitory. For example, a computer-readable medium may be a physical memory component that may store information in a digital format.

[0138] In the example of Fig. 10, a system 1090 includes one or more information storage devices 1091, one or more computers 1092, one or more networks 1095 and instructions 1096. As to the one or more computers 1092, each computer may include one or more processors (e.g., or processing cores) 1093 and memory 1094 for storingIS24.1553-WO-PCTthe instructions 1096, for example, executable by at least one of the one or more processors. As an example, a computer may include one or more network interfaces (e.g., wired or wireless), one or more graphics cards, a display interface (e.g., wired or wireless), etc. The system 1090 may be specially configured to perform one or more portions of the method 1000 of Fig. 10.

[0139] As an example, a computational framework may include a solver, which may be implemented via executable instructions. For example, consider a computational framework that includes a processor and memory accessible to the processor where executable instructions may be stored in the memory and accessed for execution by the processor to cause the computational framework to perform one or more actions. Such a computational framework may include one or more interfaces for receipt of information and / or for output of information, which may include values of parameters, an instruction, etc. As an example, a computational framework may be part of a controller. As an example, a computational framework may be part of a system.

[0140] As an example, various systems, methods, etc., may implement one or more ML models. As to types of ML models, consider one or more of a support vector machine (SVM) model, a k-nearest neighbors (KNN) model, an ensemble classifier model, a neural network (NN) model, etc. As an example, a machine learning model may be a deep learning model (e.g., deep Boltzmann machine, deep belief network, convolutional neural network, stacked auto-encoder, etc.), an ensemble model (e.g., random forest, gradient boosting machine, bootstrapped aggregation, AdaBoost, stacked generalization, gradient boosted regression tree, etc.), a neural network model (e.g., radial basis function network, perceptron, back-propagation, Hopfield network, etc.), a regularization model (e.g., ridge regression, least absolute shrinkage and selection operator, elastic net, least angle regression), a rule system model (e.g., cubist, one rule, zero rule, repeated incremental pruning to produce error reduction), a regression model (e.g., linear regression, ordinary least squares regression, stepwise regression, multivariate adaptive regression splines, locally estimated scatterplot smoothing, logistic regression, etc.), a Bayesian model (e.g., naive Bayes, average on-dependence estimators, Bayesian belief network, Gaussian naive Bayes, multinomialIS24.1553-WO-PCTnaive Bayes, Bayesian network), a decision tree model (e.g., classification and regression tree, iterative dichotomiser 3, C4.5, C5.0, chi-squared automatic interaction detection, decision stump, conditional decision tree, M5), a dimensionality reduction model (e.g., principal component analysis, partial least squares regression, Sammon mapping, multidimensional scaling, projection pursuit, principal component regression, partial least squares discriminant analysis, mixture discriminant analysis, quadratic discriminant analysis, regularized discriminant analysis, flexible discriminant analysis, linear discriminant analysis, etc.), an instance model (e.g., k-nearest neighbor, learning vector quantization, self-organizing map, locally weighted learning, etc.), a clustering model (e.g., k-means, k-medians, expectation maximization, hierarchical clustering, etc.), etc.

[0141] As an example, a system may utilize one or more recurrent neural networks (RNNs). One type of RNN is referred to as long short-term memory (LSTM), which may be a unit or component (e.g., of one or more units) that may be in a layer or layers. A LSTM component may be a type of artificial neural network (ANN) designed to recognize patterns in sequences of data, such as time series data. When provided with time series data, LSTMs take time and sequence into account such that an LSTM may include a temporal dimension. For example, consider utilization of one or more RNNs for processing temporal data from one or more sources, optionally in combination with spatial data. Such an approach may recognize temporal patterns, which may be utilized for making predictions (e.g., as to a pattern or patterns for future times, etc.).

[0142] As an example, the TENSORFLOW framework (Google LLC, Mountain View, California) may be implemented, which is an open-source software library for dataflow programming that includes a symbolic math library, which may be implemented for machine learning applications that may include neural networks. As an example, the CAFFE framework may be implemented, which is a DL framework developed by Berkeley Al Research (BAIR) (University of California, Berkeley, California). As another example, consider the SCIKIT platform (e.g., scikit-learn), which utilizes the PYTHON programming language. As an example, a framework such as the APOLLO Al framework may be utilized (APOLLO. Al GmbH, Germany). As an example, a framework such as the PYTORCH framework (PyTorch Foundation) may be utilized.IS24.1553-WO-PCT

[0143] As an example, a training method may include various actions that may operate on a dataset to train a ML model. As an example, a dataset may be split into training data and test data where test data may provide for evaluation. A method may include cross-validation of parameters and best parameters, which may be provided for model training.

[0144] The TENSORFLOW framework may run on multiple CPUs and GPUs (with optional CUDA (NVIDIA Corp., Santa Clara, California) and SYCL (The Khronos Group Inc., Beaverton, Oregon) extensions for general-purpose computing on graphics processing units (GPUs)). TENSORFLOW is available on 64-bit LINUX, MACOS (Apple Inc., Cupertino, California), WINDOWS (Microsoft Corp., Redmond, Washington), and mobile computing platforms including ANDROID (Google LLC, Mountain View, California) and IOS (Apple Inc.) operating system-based platforms.

[0145] TENSORFLOW computations may be expressed as stateful dataflow graphs; noting that the name TENSORFLOW derives from the operations that such neural networks perform on multidimensional data arrays. Such arrays may be referred to as “tensors”.

[0146] As an example, a method can include receiving torque measurements with respect to time associated with a drillstring in a borehole; receiving rotational speed measurements with respect to time associated with a top drive operatively coupled to the drillstring in the borehole, where the top drive is operatively coupled to a stick-slip mitigation controller; performing an assessment of stick-slip mitigation performance of the stick-slip mitigation controller using the torque measurements and the rotational speed measurements; and adjusting operation of the stick-slip mitigation controller based at least in part on the assessment. In such an example, performing can include computing a metric indicative of stick-slip using the torque measurements and computing a metric indicative of stick-slip mitigation controller effort using the rotational speed measurements. For example, consider performing that includes identifying one or more time periods of effective stick-slip mitigation controller effort, identifying one or more time periods of ineffective stick-slip mitigation controller effort, and / or subtracting one of the metrics from the other one of the metrics. As an example, adjusting may include adjusting a stick-slip mitigation controller based on identifying.IS24.1553-WO-PCT

[0147] As an example, a stick-slip mitigation controller can include a slide drilling mode for slide drilling. In such an example, the slide drilling can utilize a downhole mud motor on the drillstring to rotate a drill bit on the drillstring where, for example, for slide drilling, the top drive operates to oscillate a top portion of the drillstring operatively coupled to the top drive. As an example, a method may include, responsive to a transition to a slide drilling mode, automatically disabling one or more features of a stick-slip mitigation controller, and, responsive to a transition from the slide drilling mode to a rotary drilling mode, automatically enabling the one or more features of the stickslip mitigation controller.

[0148] As an example, in the presence of stick-slip, a stick-slip mitigation controller can control a top drive by changing rotational speed of the top drive. In such an example, changing rotational speed of the top drive can include changing rotational speed while rotating in a clockwise direction and / or can include changing rotational speed of the top drive while rotating in a counter-clockwise direction. As an example, changing rotational speed of a top drive may include changing rotational speed while rotating in a clockwise direction, where, a counter-clockwise direction and the clockwise direction provide oscillations to a top portion of a drillstring during drilling.

[0149] As an example, a method may include training a machine learning model based at least in part on an assessment. For example, consider training a machine learning model based at least in part on adjusting.

[0150] As an example, a method may include developing, training and / or implementing a machine learning model that includes one or more engineered features. For example, consider one or more engineered features that may include a metric indicative of stick-slip that depends on torque and a metric indicative of stick-slip mitigation controller effort that depends on rotational speed.

[0151] As an example, a system can include one or more processors; memory accessible to at least one of the one or more processors; and processor-executable instructions stored in the memory and executable to instruct the system to: receive torque measurements with respect to time associated with a drillstring in a borehole; receive rotational speed measurements with respect to time associated with a top drive operatively coupled to the drillstring in the borehole, where the top drive is operativelyIS24.1553-WO-PCTcoupled to a stick-slip mitigation controller; perform an assessment of stick-slip mitigation performance of the stick-slip mitigation controller using the torque measurements and the rotational speed measurements; and adjust operation of the stick-slip mitigation controller based at least in part on the assessment.

[0152] As an example, one or more computer-readable storage media can include processor-executable instructions to instruct a computing system to: receive torque measurements with respect to time associated with a drillstring in a borehole; receive rotational speed measurements with respect to time associated with a top drive operatively coupled to the drillstring in the borehole, where the top drive is operatively coupled to a stick-slip mitigation controller; perform an assessment of stick-slip mitigation performance of the stick-slip mitigation controller using the torque measurements and the rotational speed measurements; and adjust operation of the stick-slip mitigation controller based at least in part on the assessment.

[0153] As an example, a computer program product that may include computerexecutable instructions to instruct a computing system to perform one or more methods such as one or more of the methods described herein (e.g., in part, in whole and / or in various combinations).

[0154] In some embodiments, a method or methods may be executed by a computing system. Fig. 11 shows an example of a system 1100 that may include one or more computing systems 1101-1, 1101-2, 1101 -3 and 1101 -4, which may be operatively coupled via one or more networks 1109, which may include wired and / or wireless networks. As shown, the system 1100 may include one or more other components 1108.

[0155] As an example, a system may include an individual computer system or an arrangement of distributed computer systems. In the example of Fig. 11 , the computer system 1101-1 may include one or more modules 1102, which may be or include processor-executable instructions, for example, executable to perform various tasks (e.g., receiving information, requesting information, processing information, simulation, outputting information, etc.).

[0156] As an example, a module may be executed independently, or in coordination with, one or more processors 1104, which is (or are) operatively coupled toIS24.1553-WO-PCTone or more storage media 1106 (e.g., via wire, wirelessly, etc.). As an example, one or more of the one or more processors 1104 may be operatively coupled to at least one of one or more network interface 1107. In such an example, the computer system 1101-1 may transmit and / or receive information, for example, via the one or more networks 1109 (e.g., consider one or more of the Internet, a private network, a cellular network, a satellite network, etc.). As shown, one or more other components 1108 may be included in the computer system 1101-1.

[0157] As an example, the computer system 1101-1 may receive from and / or transmit information to one or more other devices, which may be or include, for example, one or more of the computer systems 1101 -2, etc. A device may be located in a physical location that differs from that of the computer system 1101-1. As an example, a location may be, for example, a processing facility location, a data center location (e.g., server farm, etc.), a rig location, a wellsite location, a downhole location, etc.

[0158] As an example, a processor may be or include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, or another control or computing device.

[0159] As an example, the storage media 1106 may be implemented as one or more computer-readable or machine-readable storage media. As an example, storage may be distributed within and / or across multiple internal and / or external enclosures of a computing system and / or additional computing systems.

[0160] As an example, a storage medium or storage media may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories, magnetic disks such as fixed, floppy and removable disks, other magnetic media including tape, optical media such as compact disks (CDs) or digital video disks (DVDs), BLUERAY disks, or other types of optical storage, or other types of storage devices.IS24.1553-WO-PCT

[0161] As an example, a storage medium or media may be located in a machine running machine-readable instructions, or located at a remote site from which machine-readable instructions may be downloaded over a network for execution.

[0162] As an example, various components of a system such as, for example, a computer system, may be implemented in hardware, software, or a combination of both hardware and software (e.g., including firmware), including one or more signal processing and / or application specific integrated circuits.

[0163] As an example, a system may include a processing apparatus that may be or include a general-purpose processors or application specific chips (e.g., or chipsets), such as ASICs, FPGAs, PLDs, or other appropriate devices.

[0164] As an example, a device may be a mobile device that includes one or more network interfaces for communication of information. For example, a mobile device may include a wireless network interface (e.g., operable via IEEE 802.11, ETSI GSM, BLUETOOTH, satellite, etc.). As an example, a mobile device may include components such as a main processor, memory, a display, display graphics circuitry (e.g., optionally including touch and gesture circuitry), a SIM slot, audio / video circuitry, motion processing circuitry (e.g., accelerometer, gyroscope), wireless LAN circuitry, smart card circuitry, transmitter circuitry, GPS circuitry, and a battery. As an example, a mobile device may be configured as a cell phone, a tablet, etc. As an example, a method may be implemented (e.g., wholly or in part) using a mobile device. As an example, a system may include one or more mobile devices.

[0165] As an example, a system may be a distributed environment, for example, a so-called “cloud” environment where various devices, components, etc. interact for purposes of data storage, communications, computing, etc. As an example, a device or a system may include one or more components for communication of information via one or more of the Internet (e.g., where communication occurs via one or more Internet protocols), a cellular network, a satellite network, etc. As an example, a method may be implemented in a distributed environment (e.g., wholly or in part as a cloud-based service).

[0166] As an example, information may be input from a display (e.g., consider a touchscreen), output to a display or both. As an example, information may be output toIS24.1553-WO-PCTa projector, a laser device, a printer, etc. such that the information may be viewed. As an example, information may be output stereographically or holographically. As to a printer, consider a 2D or a 3D printer. As an example, a 3D printer may include one or more substances that may be output to construct a 3D object. For example, data may be provided to a 3D printer to construct a 3D representation of a subterranean formation. As an example, layers may be constructed in 3D (e.g., horizons, etc.), geobodies constructed in 3D, etc. As an example, holes, fractures, etc., may be constructed in 3D (e.g., as positive structures, as negative structures, etc.).

[0167] Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the examples. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures.Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures.

Claims

IS24.1553-WO-PCTCLAIMSWhat is claimed is:

1. A method comprising:receiving torque measurements with respect to time associated with a drillstring in a borehole;receiving rotational speed measurements with respect to time associated with a top drive operatively coupled to the drillstring in the borehole, wherein the top drive is operatively coupled to a stick-slip mitigation controller;performing an assessment of stick-slip mitigation performance of the stick-slip mitigation controller using the torque measurements and the rotational speed measurements; andadjusting operation of the stick-slip mitigation controller based at least in part on the assessment.

2. The method of claim 1 , wherein the performing comprises computing a metric indicative of stick-slip using the torque measurements and computing a metric indicative of stick-slip mitigation controller effort using the rotational speed measurements.

3. The method of claim 2, wherein the performing further comprises identifying one or more time periods of effective stick-slip mitigation controller effort.

4. The method of claim 2, wherein the performing further comprises identifying one or more time periods of ineffective stick-slip mitigation controller effort.

5. The method of claim 4, wherein the adjusting comprises adjusting the stick-slip mitigation controller based on the identifying.

6. The method of claim 2, wherein the performing further comprises subtracting one of the metrics from the other one of the metrics.IS24.1553-WO-PCT7. The method of claim 1 , wherein the stick-slip mitigation controller comprises a slide drilling mode for slide drilling.

8. The method of claim 7, wherein the slide drilling utilizes a downhole mud motor on the drillstring to rotate a drill bit on the drillstring.

9. The method of claim 7, wherein, for slide drilling, the top drive operates to oscillate a top portion of the drillstring operatively coupled to the top drive.

10. The method of claim 7, wherein, responsive to a transition to the slide drilling mode, one or more features of the stick-slip mitigation controller are automatically disabled, and wherein, responsive to a transition from the slide drilling mode to a rotary drilling mode, the one or more features of the stick-slip mitigation controller are automatically enabled.

11. The method of claim 1 , wherein, in the presence of stick-slip, the stick-slip mitigation controller controls the top drive by changing rotational speed of the top drive.

12. The method of claim 11 , wherein the changing rotational speed of the top drive comprises changing rotational speed while rotating in a clockwise direction.

13. The method of claim 11 , wherein the changing rotational speed of the top drive comprises changing rotational speed while rotating in a counter-clockwise direction.

14. The method of claim 13, wherein the changing rotational speed of the top drive further comprises changing rotational speed while rotating in a clockwise direction, wherein, the counter-clockwise direction and the clockwise direction provide oscillations to a top portion of the drillstring during drilling.IS24.1553-WO-PCT15. The method of claim 1, further comprising training a machine learning model based at least in part on the assessment.

16. The method of claim 15, further comprising training the machine learning model based at least in part on the adjusting.

17. The method of claim 15, wherein the machine learning model comprises one or more engineered features.

18. The method of claim 17, wherein the one or more engineered features comprise a metric indicative of stick-slip that depends on torque and a metric indicative of stick-slip mitigation controller effort that depends on rotational speed.

19. A system comprising:one or more processors;memory accessible to at least one of the one or more processors; and processor-executable instructions stored in the memory and executable to instruct the system to:receive torque measurements with respect to time associated with a drillstring in a borehole;receive rotational speed measurements with respect to time associated with a top drive operatively coupled to the drillstring in the borehole, wherein the top drive is operatively coupled to a stick-slip mitigation controller;perform an assessment of stick-slip mitigation performance of the stickslip mitigation controller using the torque measurements and the rotational speed measurements; andadjust operation of the stick-slip mitigation controller based at least in part on the assessment.

20. One or more computer-readable storage media comprising processor-executable instructions to instruct a computing system to:IS24.1553-WO-PCTreceive torque measurements with respect to time associated with a drillstring in a borehole;receive rotational speed measurements with respect to time associated with a top drive operatively coupled to the drillstring in the borehole, wherein the top drive is operatively coupled to a stick-slip mitigation controller;perform an assessment of stick-slip mitigation performance of the stick-slip mitigation controller using the torque measurements and the rotational speed measurements; andadjust operation of the stick-slip mitigation controller based at least in part on the assessment.

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