Dynamic adjustment of drilling parameter limits

Abstract

Methods, computing systems, and computer readable media for dynamically adjusting drilling parameters during a drilling operation. The method includes receiving drilling parameter measurements and response measurements in real-time during a drilling operation. If the response measurements are below a lower limit of a window or trending downward, the method determines a new drilling parameter value that will increase the response measurements. The method dynamically adjusts the drilling parameter value to be higher than a hole section limit while still adhering to a hard limit. When the measurements improve, the method returns the limit of the drilling parameter to the hole section limit.

Description

[0001] Cross-reference to related applications

[0002] This application claims priority to U.S. Patent Application Serial No. 63 / 199,272, filed December 17, 2020, entitled “Automatically Maintaining a Drilling Response,” the contents of which are incorporated herein by reference. Background Technology

[0003] Unless otherwise stated, this section does not describe the prior art of the claims, nor is it considered prior art.

[0004] Certain drilling parameters on the drilling rig can be directly controlled, such as the increase or decrease of block speed, pump stroke rate, and surface drill string speed or revolutions per minute (RPM). Increasing or decreasing these drilling parameters will result in a response from the equipment and the well. As examples, the response to RPM includes drill string torque; the response to changes in block speed is a change in hook load and surface weight; and the response to changes in pump stroke rate includes a change in riser pressure.

[0005] During fracture operations such as drilling, it may be desirable to keep the response within a window or range defined by upper and lower limits. For example, keeping the pressure on the drill bit within a window helps maintain full engagement and reduce wear, and also helps control bottom hole assembly (BHA) tendencies, thereby controlling the wellbore trajectory. Controlling the pressure differential when using a mud motor can help maintain full engagement of the drill bit and enhance control over the trajectory in a directional well.

[0006] Drilling parameters typically need to be kept within limits. Some drilling parameter limits are hard limits. Exceeding hard limits can damage equipment and pose health, environmental, and safety risks. As an example, a hard limit for drill string torque might be set at a value that, if exceeded, could damage the top drive or drill pipe. Other drilling parameter limits are sectional limits. A sectional limit can be a value that the team believes will provide optimal average performance when drilling in that section of the wellbore, based on experience, simulation, analysis, or some combination of the above factors. Summary of the Invention

[0007] Drilling automation and recommendation systems typically attempt to adhere to hard and well section limits in all situations. While this generally yields good performance, there are instances where exceeding certain limits may lead to better results. For example, during drilling, there are situations where certain non-hard well section limits may be temporarily exceeded to better respond to specific events or challenges. For instance, stick-slip vibrations can damage the drill bit and top drive. Mitigating stick-slip may involve reducing the pressure on the bit and increasing the RPM. However, in a given well section, the velocity may already be nearing its limit. For instance, a "overdrive" velocity of 20-25 RPM above the well section limit may be temporarily acceptable to mitigate stick-slip. This allows for faster mitigation of stick-slip events. Once the stick-slip event is successfully mitigated, the RPM can be reduced back below the well section limits.

[0008] This document discloses a method, non-transitory, tangible computer-readable storage medium, and system for dynamically adjusting drilling parameters during drilling operations. In one embodiment, the method involves receiving drilling parameter measurements and response measurements during drilling operations in real time. The method may include determining whether a response measurement is within a response window that defines a lower and upper expectation limit for the response measurement.

[0009] In some embodiments, if the response measurement is below or trending downward toward the expected lower limit of the response window, the system determines a new drilling parameter value to increase the response measurement. The system compares the new drilling parameter value with well section limits and hard limits for the drilling parameters. If the drilling parameter value is above the well section limit and below the hard limit, the system may increase the upper limit of the drilling parameter window to the new drilling parameter value. The method may also include instructions for automatically increasing the drilling parameter to a new value that increases the response measurement.

[0010] The method may also include monitoring response measurements after increasing drilling parameters to new drilling parameter values, determining that the response measurements stabilize within the response window, and resetting the upper limit of the drilling parameter window to the well section limit of the drilling parameters.

[0011] In one embodiment, the method is used to manage pressure differentials during directional drilling operations. The method may include measuring, in real time, the pressure differential across the motor of the bottom hole assembly and the drilling rate of the bottom hole assembly during the directional drilling operation. The method may include determining whether the pressure differential is within a predetermined pressure differential window, which specifies a lower limit and an upper limit for the pressure differential. If the pressure differential is below or trending downwards towards the lower limit of the predetermined pressure differential window, the system may determine a new drilling rate value that will increase the pressure differential, compare the new drilling rate value with a hard limit and a well section limit, and if the new drilling rate value is above the well section limit and below the hard limit, increase the upper limit of the drilling rate window to the new drilling rate value.

[0012] This overview introduces some concepts that will be further described in the following detailed description. Other concepts and features are described below. The claims may include concepts from other parts of this overview or specification. Attached Figure Description

[0013] The image below is not necessarily drawn to scale; dimensions may vary to help clarify or emphasize certain features.

[0014] Figure 1 An example of a system according to one embodiment is shown, which includes various management components for managing various aspects of the geological environment.

[0015] Figure 2 An example of a drilling system that can be used for drilling is shown.

[0016] Figure 3 A flowchart is shown for a method of adjusting drilling parameters.

[0017] Figure 4 A flowchart is shown for a method of adjusting the drilling rate.

[0018] Figure 5A An example of drilling response measurements and drilling parameter measurements is shown.

[0019] Figure 5B An example of drilling response measurements, drilling parameter measurements, and dynamic adjustment of drilling parameter values ​​is shown.

[0020] Figure 6 A schematic diagram of a computing system according to one embodiment is shown. Detailed Implementation

[0021] introduce

[0022] The following detailed description refers to the accompanying drawings. Wherever convenient, the same reference numerals are used in the drawings and the following description to refer to the same or similar parts. Although several embodiments and features of this disclosure are described herein, modifications, adaptations, and other implementations are possible without departing from the spirit and scope of this disclosure.

[0023] Although the terms "first," "second," etc., may be used herein to describe various elements, these terms are used to distinguish one element from another. As an example, without departing from the scope of this disclosure, a first object or step may be referred to as a second object or step, and similarly, a second object or step may be referred to as a first object or step. The first object or step and the second object or step are both objects or steps, but they are not considered to be the same object or step.

[0024] The terminology used in this description is for the purpose of describing particular embodiments and not for limitation. As used in this specification and the appended claims, the singular forms “a,” “an,” and “the” are also intended to include the plural forms unless the context clearly indicates otherwise. It should also be understood that the term “and / or” as used herein refers to and includes any possible combination of one or more of the associated listed items. It will also be understood that the terms “includes,” “including,” “comprises,” and / or “comprising,” when used in this specification, specify the presence of the stated features, integers, steps, operations, elements, and / or components, but do not exclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and / or combinations thereof. Furthermore, as used herein, depending on the context, the term “if” can be interpreted as “when,” “in,” “in response to determination,” or “in response to detection.”

[0025] Example

[0026] Figure 1 An example of system 100 is shown, which includes various management components 110 for managing various aspects of a geological environment 150 (e.g., an environment including a sedimentary basin, reservoir 151, one or more faults 153-1, one or more geological bodies 153-2, etc.). As an example, management components 110 may allow direct or indirect management of sensing, drilling, injection, extraction, etc., of the geological environment 150. Furthermore, further information about the geological environment 150 may become available as feedback 160 (e.g., optionally as input to one or more management components 110).

[0027] exist Figure 1In the example, management component 110 includes seismic data component 112, other information component 114 (e.g., well / logging data), processing component 116, simulation component 120, attribute component 130, analysis / visualization component 142, and workflow component 144. During operation, seismic data and other information provided by seismic data component 112 and other information components 114 can be input into simulation component 120.

[0028] In an exemplary embodiment, simulation component 120 may depend on entity 122. Entity 122 may include earth entities or geological objects, such as wells, surfaces, objects, reservoirs, etc. In system 100, entity 122 may include a virtual representation of an actual physical entity reconstructed for simulation purposes. Entity 122 may include entities based on data obtained through sensing, observation, etc. (e.g., seismic data component 112 and other information components 114). Entities may be characterized by one or more properties (e.g., the geometric columnar mesh entity of an earth model may be characterized by porosity properties). Such properties may represent one or more measurements (e.g., acquired data), calculations, etc.

[0029] In an exemplary embodiment, simulation component 120 may operate in conjunction with a software framework such as an object-based framework. In such a framework, entities may include entities based on predefined categories to facilitate modeling and simulation. A commercial example of an object-based framework is MICROSOFT. ® .NET ® The framework (Redmond, Washington) provides a set of extensible object classes. In .NET... ® In this framework, object classes encapsulate reusable code and related data structures. Object classes can be used to instantiate objects for use by programs, scripts, etc. As an example, a borehole class can define objects used to represent boreholes based on well data.

[0030] exist Figure 1 In the example, simulation component 120 can process information to conform to one or more attributes specified by attribute component 130, which may include an attribute library. This processing can occur before the input is passed to simulation component 120 (e.g., consider processing component 116). As an example, simulation component 120 can perform operations on input information based on one or more attributes specified by attribute component 130. In an exemplary embodiment, simulation component 120 can construct one or more models of a geological environment 150, which can be relied upon to simulate the behavior of the geological environment 150 (e.g., in response to one or more actions, whether natural or man-made). Figure 1In the example, the analysis / visualization component 142 may allow interaction with the model or model-based results (e.g., simulation results, etc.). As an example, the output from the simulation component 120 may be input to one or more other workflows, as indicated by the workflow component 144.

[0031] As an example, simulation component 120 may include one or more features of the simulator, such as ECLIPSE. TM Reservoir simulator (Schlumberger Ltd., Houston, Texas), INTERSECT TM Reservoir simulators (Schlumberger Ltd., Houston, Texas), etc. As an example, simulation components, simulators, etc., may include features for implementing one or more meshless techniques (e.g., solving one or more equations, etc.). As an example, one or more reservoirs may be simulated for one or more enhanced extraction techniques (e.g., considering thermodynamic processes such as SAGD, etc.).

[0032] In an exemplary embodiment, management component 110 may include features of commercially available frameworks, such as PETREL. ® Earthquake simulation software framework (Schlumberger Ltd., Houston, Texas). PETREL ® The framework provides components that allow for the optimization of exploration and development operations. PETREL ® The framework includes seismic simulation software components that can output information to improve reservoir performance, for example, by increasing the productivity of asset teams. By using such a framework, various professionals (e.g., geophysicists, geologists, and reservoir engineers) can develop collaborative workflows and integrate operations to streamline processes. This framework can be considered an application, and specifically a data-driven application (e.g., where data is input for modeling, simulation, and other purposes).

[0033] In an exemplary embodiment, various aspects of the management component 110 may include attachments or plugins that operate according to the specifications of the framework environment. As an example, as OCEAN... ® The commercially available framework environment (Schlumberger Ltd., Houston, Texas) allows for the integration of accessories (or plug-ins) into Petrel. ® In the framework workflow. OCEAN ® The framework environment utilizes .NET ®The tool (Microsoft Corporation, Redmond, Washington) provides a stable, user-friendly interface for efficient development. In an exemplary embodiment, various components may be implemented as accessories (or plugins) that conform to the framework environment's specifications (e.g., according to the Application Programming Interface (API) specification) and operate according to that specification.

[0034] Figure 1 An example of framework 170 is also shown, which includes a model simulation layer 180, a framework service layer 190, a framework core layer 195, and a module layer 175. Framework 170 may include commercially available OCEAN. ® The framework, in which model simulation layer 180 is commercially available OCEAN. ® The framework, in which model simulation layer 180 is commercially available using PETREL, ® Model-centric software packages, hosted by OCEAN ® Framework application. In an exemplary embodiment, PETREL ® Software can be considered a data-driven application. PETREL ® The software may include frameworks for model building and visualization.

[0035] As an example, the framework may include features for implementing one or more mesh generation techniques. As an example, the framework may include an input component for receiving information from the interpretation of one or more attributes of seismic data, at least in part based on seismic data, well logging data, image data, etc. Such a framework may include a mesh generation component that optionally incorporates other information to process the input information to generate a mesh.

[0036] exist Figure 1 In the example, the model simulation layer 180 can provide domain objects 182, act as a data source 184, provide rendering 186, and provide various user interfaces 188. Rendering 186 can provide a graphical environment where applications can display their data, while user interfaces 188 can provide a common look and feel for the application's user interface components.

[0037] As an example, domain object 182 may include entity objects, characteristic objects, and optional other objects. Entity objects can be used to geometrically represent wells, surfaces, volumes, reservoirs, etc., while characteristic objects can be used to provide characteristic values ​​as well as data versioning and display parameters. As an example, an entity object may represent a well, where characteristic objects provide log information as well as versioning information and display information (e.g., showing the well as part of the model).

[0038] exist Figure 1In the example, data can be stored in one or more data sources (or data storage devices, typically physical data storage devices), which may be located at the same or different physical sites and can be accessed via one or more networks. The model simulation layer 180 can be configured to model projects. This allows specific projects to be stored, where the stored project information can include inputs, models, results, and cases. Therefore, the user can save the project when the modeling session is complete. Later, the model simulation layer 180 can be used to access and restore the project, and it can recreate instances of the relevant domain objects.

[0039] exist Figure 1 In the example, geological environment 150 may include layers (e.g., strata) including reservoir 151 and one or more other features, such as fault 153-1, geological body 153-2, etc. As an example, geological environment 150 may be equipped with any of a variety of sensors, detectors, actuators, etc. As an example, device 152 may include communication circuitry to receive and transmit information about one or more networks 155. This information may include information associated with downhole device 154, which may be a device for acquiring information, assisting in resource recovery, etc. Other devices 156 may be located remotely from the well site and include sensing, detection, transmission, or other circuitry. Such devices may include storage and communication circuitry to store and transmit data, instructions, etc. As an example, one or more satellites may be provided for communication, data acquisition, and other purposes. As an example, Figure 1 A satellite communicating with network 155 is shown. This satellite can be configured for communication. Note that the satellite may additionally or alternatively include circuitry for imaging (e.g., spatial, spectral, temporal, radiometric measurements, etc.).

[0040] Figure 1 Geological environment 150 is also shown, which optionally includes equipment 157 and 158 associated with a well, the well including a basic horizontal portion that may intersect with one or more fractures 159. As an example, a well in a shale formation is considered, which 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 laterally extended reservoir. In such an example, lateral variations in properties, stresses, etc., may exist, and assessment of these variations may aid in planning, operations, etc., to develop the laterally extended reservoir (e.g., through fracturing, injection, extraction, etc.). As an example, equipment 157 and / or 158 may include components, systems, multiple systems, etc., for fracturing, seismic sensing, seismic data analysis, assessment of one or more fractures, etc.

[0041] As mentioned, system 100 can be used to execute one or more workflows. A workflow can be a process that includes many work steps. Work steps can manipulate data, such as creating new data, updating existing data, etc. As an example, one or more inputs can be manipulated, and one or more results can be created, for example, based on one or more algorithms. As an example, the system may include a workflow editor for creating, editing, executing, etc., workflows. In such an example, the workflow editor can provide selections for one or more predefined work steps, one or more custom work steps, etc. As an example, a workflow can be implemented in PETREL. ® The software can implement workflows, for example, that manipulate seismic data and seismic attributes. As an example, a workflow could be implemented in OCEAN... ® The processes that can be implemented within the framework. As an example, a workflow may include one or more work steps that access modules such as plugins (e.g., external executable code).

[0042] Figure 2 An example of a well site system 200 is shown (e.g., at a well site that may be onshore or offshore). As shown, the well site system 200 may include a mud tank 201 for containing mud and other materials (e.g., where the mud may be drilling fluid), a suction line 203 serving as the inlet of a mud pump 204 to pump mud from the mud tank 201 to the vibratory hose 206, a winch 207 for winding one or more drill ropes 212, a riser 208 for receiving mud from the vibratory hose 206, a square drill pipe hose 209 for receiving mud from the riser 208, one or more gooseneck pipes 210, a traveling block 211, and a crane 213 for carrying the traveling block 211 via one or more drill ropes 212 (e.g., see [link]). Figure 1 (the overhead crane), derrick 214 (for example, see...) Figure 1 The derrick, 218 or top drive 240, 219, rotary table 220, drill rig 221, bell joint 222, one or more blowout preventers (BOPs) 223, drill string 225, drill bit 226, casing head 227, and flow pipe 228 for transporting mud and other materials to, for example, mud tank 201.

[0043] exist Figure 2 In the example system, a borehole 232 is formed in the underground formation 230 by rotary drilling; note that various example embodiments may also use one or more directional drilling techniques, equipment, etc.

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

[0045] The well site system 200 can provide operation of the drill string 225 and other operations. As shown, the well site system 200 includes a traveling block 211 and a derrick 214 located above the borehole 232. As mentioned, the well site system 200 may include a rotary table 220 through which the drill string 225 passes.

[0046] like Figure 2 As illustrated in the example, the well site system 200 may include a crisscross drill pipe 218 and related components, or a top drive 240 and related components. Regarding the example of the crisscross drill pipe, the crisscross drill pipe 218 may be a square or hexagonal metal / alloy bar with holes drilled to serve as a mud flow path. The crisscross drill pipe 218 can be used to transmit rotational motion from the rotary table 220 via the crisscross drill pipe drive bushing 219 to the drill string 225, while allowing the drill string 225 to be lowered or raised during rotation. The crisscross drill pipe 218 may pass through the crisscross drill pipe drive bushing 219, which may be driven by the rotary table 220. As an example, the rotary table 220 may include a main bushing operatively coupled to the crisscross drill pipe drive bushing 219, such that rotation of the rotary table 220 can rotate the crisscross drill pipe drive bushing 219 and thus rotate the crisscross drill pipe 218. The square drill pipe drive bushing 219 may include an internal profile that matches the external profile (e.g., square, hexagonal, etc.) of the square drill pipe 218; however, it is slightly larger in size so that the square drill pipe 218 can move freely up and down within the square drill pipe drive bushing 219.

[0047] For an example of a top drive, top drive 240 can provide functions performed by the kauri and rotary table. Top drive 240 can rotate drill string 225. As an example, top drive 240 may include one or more motors (e.g., electric and / or hydraulic motors) connected via suitable transmissions to a short section of pipe known as a casing shaft, which can be screwed into a protective sub or the drill string 225 itself. Top drive 240 can be suspended on traveling block 211, so the rotating mechanism can move freely up and down on derrick 214. As an example, top drive 240 may allow drilling using more joint stands than the kauri / rotary table method.

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

[0049] exist Figure 2 In the example, drill string 225 (e.g., including one or more downhole tools) may consist of a series of threaded pipes forming a long tube with drill bit 226 at its lower end. When drill string 225 is advanced into the wellbore for drilling, at some point before or concurrent with drilling, mud may be pumped from mud tank 201 (e.g., or other source) via vibratory hose 206, riser 208, and squeegee hose 209 to a port of squeegee 218, or, for example, to a port of top drive 240, via mud pump 204. The mud may then flow out of the port located on drill bit 226 via channels (e.g., multiple channels) in drill string 225 (e.g., see directional arrows). As the mud exits drill string 225 via the port in drill bit 226, it may then circulate upwards through an annular region between the outer surface of drill string 225 and the surrounding walls (e.g., open hole, casing, etc.), as indicated by the directional arrows. In this way, the mud lubricates the drill bit 226 and brings heat (e.g., friction or other energy) and formation cuttings to the surface, where the mud (e.g., and cuttings) can be returned to the mud tank 201, for example, for recycling (e.g., for processing to remove cuttings, etc.).

[0050] The mud pumped into the drill string 225 by mud pump 204 forms a mud cake lining the wellbore after leaving the drill string 225. Among other functions, the mud cake reduces friction between the drill string 225 and the surrounding walls (e.g., borehole, casing, etc.). This reduction in friction facilitates the advancement or retraction of the drill string 225. During drilling operations, the entire drill string 225 can be pulled out of the wellbore and optionally replaced with, for example, a new or sharp drill bit, a smaller diameter drill string, etc. As mentioned, the act of pulling the drill string out of or back into the hole is called tripping. Depending on the direction of tripping, tripping can be called upward tripping or outward tripping, or downward tripping or inward tripping.

[0051] As an example, consider a down-running drill, where, as the drill bit 226 of the drill string 225 reaches the bottom of the wellbore, the pumping of mud begins to lubricate the drill bit 226 in order to enlarge the wellbore. As mentioned, the mud can be pumped into the channels of the drill string 225 by the mud pump 204, and while filling the channels, the mud can be used as a medium for transmitting energy, for example, energy that can encode information, as in mud pulse telemetry.

[0052] As an example, a mud pulse telemetry device may include a downhole device configured to influence pressure changes in the mud to generate acoustic waves or waves that can modulate information. In such an example, information from the downhole device (e.g., one or more modules of drill string 225) can be transmitted to a surface device, which can then relay such information to other devices for processing, control, etc.

[0053] As an example, the telemetry device can operate via energy transmission through the drill string 225 itself. For example, consider a signal generator that transmits coded energy signals to the drill string 225 and a repeater that can receive such energy and relay it for further transmission of coded energy signals (e.g., information, etc.).

[0054] As an example, drill string 225 may be equipped with telemetry device 252, which includes a rotatable drive shaft; a turbine impeller mechanically coupled to the drive shaft such that mud can cause the turbine impeller to rotate; a modulator rotor mechanically coupled to the drive shaft such that rotation of the turbine impeller causes rotation of the modulator rotor; a modulator stator mounted adjacent to or near the modulator rotor such that rotation of the modulator rotor relative to the modulator stator generates pressure pulses in the mud; and a controllable brake for selectively braking the rotation of the modulator rotor to modulate the pressure pulses. In such an example, an alternator may be coupled to the aforementioned drive shaft, wherein the alternator includes at least one stator winding electrically connected to a control circuit to selectively short-circuit the at least one stator winding to electromagnetically brake the alternator, thereby selectively braking the rotation of the modulator rotor to modulate the pressure pulses in the mud.

[0055] exist Figure 2 In one example, the well-ground control and / or data acquisition system 262 may include circuitry to sense pressure pulses generated by the telemetry device 252, and, for example, transmit the sensed pressure pulses or information derived therefrom for processing, control, etc.

[0056] The drill string assembly 250 shown in the 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 a motor 260, and a drill bit 226. Such an assembly or module may be referred to as a tool, and the drill string may include multiple tools.

[0057] As for RSS, it relates to techniques used in directional drilling. Directional drilling involves drilling into the earth to form an skewed borehole, such that the borehole's trajectory is not vertical; instead, the trajectory deviates from the vertical along one or more sections of the borehole. As an example, consider a target located at a lateral distance from the surface location where the drilling rig might be stationed. In such an example, drilling could begin with a vertical section and then deviate from the vertical, so that the borehole aims at the target and eventually reaches it. Directional drilling can be implemented when a target is inaccessible from a vertical location on the earth's surface, when there are features on the earth that could hinder drilling or otherwise be harmful (e.g., consider salt domes), when the formation extends laterally (e.g., consider relatively thin but laterally extending reservoirs), when drilling multiple boreholes from a single surface borehole, when a decompression well is required, and so on.

[0058] One method of directional drilling involves mud motors; however, mud motors can face several challenges depending on factors such as the rate of penetration (ROP) and the transfer of weight to the drill bit due to friction (e.g., pressure on drill bit, wobble weight). A mud motor can be a positive displacement motor (PDM), which operates to drive the drill bit (e.g., in directional drilling processes). The PDM operates as drilling fluid is pumped through it, converting the hydraulic power of the drilling fluid into mechanical power to rotate the drill bit.

[0059] As an example, PDM can operate in a combined rotary mode, where surface equipment (e.g., rotary table, top drive, etc.) is used to rotate the drill string bit by rotating the entire drill string, and drilling fluid is used to rotate the drill string bit. In such an example, the surface RPM (SRPM) can be determined using surface equipment, while the downhole RPM of the mud motor can be determined using various factors related to drilling fluid flow, mud motor type, etc. As an example, in the combined rotary mode, assuming the SRPM and mud motor RPM are in the same direction, the bit RPM can be determined or estimated as the sum of the SRPM and mud motor RPM.

[0060] As an example, when the drill string is not rotating from the ground, the PDM mud motor can operate in a so-called slippery mode. In such an example, the drill bit RPM can be determined or estimated based on the mud motor's RPM.

[0061] RSS (Remote Suspension Controller) can be used in directional drilling where surface equipment rotates continuously, which can reduce slippage of steerable motors (such as PDMs). RSS can be deployed during directional drilling (such as deviated wells, horizontal wells, or extended reach wells). RSS can be designed to minimize interaction with the wellbore, which helps maintain borehole quality. RSS can be designed to apply a relatively consistent lateral force, similar to a stabilizer rotating with the drill string, or to orient the drill bit in the desired direction while rotating continuously at the same rate as the drill string.

[0062] The Logging While Drilling (LWD) module 254 can be housed in a suitable type of drill collar and may contain one or more selected types of logging tools. It should also be understood that more than one LWD and / or MWD module may be employed, for example, as shown in the Measurement While Drilling (MWD) module 256 of the drill string assembly 250. When referring to the location of an LWD module, by way of example, it may refer to the module located at the location of the LWD module 254, the MWD module 256, etc. An LWD module may include the ability to measure, process, and store information, as well as the ability to communicate with surface equipment. In the example shown, the LWD module 254 may include a seismic measurement device.

[0063] The Measurement While Drilling (MWD) module 256 can be housed in a suitable type of drill collar and may include one or more devices for measuring the characteristics of the drill string 225 and the drill bit 226. As an example, the MWD tool may include devices for generating electricity, for example, to power various components of the drill string 225. As an example, the MWD tool may include a telemetry device 252, for example, in which a turbine impeller can generate electricity through the flow of drilling mud; it should be understood that other power sources and / or battery systems may be used to power the various components. As an example, the Measurement While Drilling (MWD) module 256 may include one or more measuring devices of the following types: drill pressure measuring device, torque measuring device, vibration measuring device, impact measuring device, stick-slip measuring device, direction measuring device, and tilt measuring device.

[0064] Figure 2 Some examples of the types of holes that can be drilled are also shown. For example, consider slanted hole 272, S-shaped hole 274, deep slanted hole 276, and horizontal hole 278.

[0065] As an example, drilling operations may include directional drilling, where, for example, at least a portion of the well includes a curved axis. For example, consider defining a radius of curvature, where the inclination relative to the vertical direction can vary up to an angle between approximately 30 degrees and approximately 60 degrees, or, for example, an angle of approximately 90 degrees or possibly greater than approximately 90 degrees.

[0066] As an example, directional wells can include several shapes, each designed to meet specific operational requirements. As an example, the drilling process can be performed based on information, and when that information is passed to the drilling engineer. As an example, the inclination and / or direction can be modified based on information received during the drilling process.

[0067] As an example, borehole deviation can be achieved in part by using downhole motors and / or turbines. For example, for motors, the drill string can include a positive displacement motor (PDM).

[0068] As an example, the system can be a guideable system and include equipment for performing methods such as geological steering. As mentioned, a guideable system can be or include an RSS (Resistant Steering System). As an example, a guideable system can include a PDM (Precision Directional Drilling) or a turbine PDM located at the bottom of the drill string, with a bent sub mounted directly above the drill string. As an example, a PDM, MWD (Maintenance, Dynamic Range) device providing real-time or near-real-time data of interest (e.g., inclination, direction, pressure, temperature, actual weight on the drill bit, torque stress, etc.) and / or an LWD (Low-Dip Dynamics) device can be mounted above the PDM. For the latter, the LWD device can transmit various types of data of interest to the surface, including, for example, geological data (e.g., gamma-ray logging, resistivity, density, and sonic logging, etc.).

[0069] Linking sensors that provide real-time or near-real-time information about the wellbore trajectory with one or more logging operations, such as those characterizing formations from a geological perspective, can enable the implementation of geosteering methods. These methods can include navigating the subsurface environment, for example, along a desired route to one or more desired targets.

[0070] As an example, a drill string may include an azimuth density neutron (ADN) tool for measuring density and porosity; an MWD tool for measuring dip, azimuth, and vibration; 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 geological guidance tool that may include a motor and optional equipment for measuring and / or responding to one or more of the dip, resistivity, and gamma-ray related phenomena.

[0071] As an example, geological steering can include intentional directional control of a wellbore based on the results of downhole geological logging measurements, in a manner aimed at keeping the directional wellbore within a desired area, zone (e.g., oil-producing layer). As an example, geological steering can include guiding the wellbore to keep it within a specific portion of the reservoir, for example, to minimize gas and / or water breakthrough, and, for example, to maximize the economic production of the well including the wellbore.

[0072] Refer again Figure 2Well site system 200 may include one or more sensors 264 operatively coupled to control and / or data acquisition system 262. As an example, one or more sensors may be located at a surface location. As an example, one or more sensors may be located at a downhole location. As an example, one or more sensors may be located at one or more remote locations not within a distance on the order of approximately 100 meters from well site system 200. As an example, one or more sensors may be located at a branch well site, where well site system 200 and the branch well site are located in a common oil field (e.g., an oil field and / or a gas field).

[0073] As an example, one or more sensors 264 can be provided to track the movement of pipes, track the movement of at least a portion of the drill string, etc.

[0074] As an example, well site system 200 may include one or more sensors 264 that can sense and / or transmit signals to fluid conduits, such as drilling fluid conduits (e.g., drilling mud conduits). For example, in well site system 200, one or more sensors 264 may be operatively coupled to a portion of riser 208 through which mud flows. As an example, downhole tools may generate pulses that can travel through the mud and be sensed by one or more of the one or more sensors 264. In such an example, the downhole tool may include associated circuitry, such as encoding circuitry, that can encode the signal, for example, to reduce the need for transmission. As an example, surface circuitry may include decoding circuitry to decode encoded information transmitted at least partially via mud pulse telemetry. As an example, surface circuitry may include encoder circuitry and / or decoder circuitry, and downhole circuitry may include encoder circuitry and / or decoder circuitry. As an example, well site system 200 may include a transmitter capable of generating signals that can be transmitted downhole via mud (e.g., drilling fluid) as a transmission medium.

[0075] As an example, one or more portions of the drill string may become stuck. The term "stuck" can refer to one or more different degrees of inability to move or remove the drill string from the borehole. As an example, in a stuck situation, it may be possible to rotate the drill string or lower it into the borehole, or, for example, in a stuck situation, it may be impossible to move the drill string axially in the borehole, although there may be some degree of rotation. As an example, in a stuck situation, it may be impossible to move at least a portion of the drill string axially and rotationally.

[0076] The term "stuck" refers to a portion of the drill string that cannot rotate or move axially. For example, a condition known as "differential pressure jamming" can be a situation where the drill string cannot move along the axis of the borehole (e.g., rotate or reciprocate). Differential pressure jamming occurs when high contact forces, caused by low reservoir pressure, high borehole pressure, or both, are applied over a sufficiently large drill string area. Differential pressure jamming is time-consuming and costly.

[0077] As an example, adhesion can be the product of the pressure difference between the wellbore and the reservoir and the area over which the pressure difference acts. This means that applying a relatively low pressure difference (δp) over a large working area can be just as effective in preventing pipe jamming as applying a higher pressure difference over a small area.

[0078] As an example, a condition known as "mechanical jamming" can be one where the movement of the drill string is restricted or prevented by a mechanism other than pressure differential jamming. Mechanical jamming can be caused by, for example, one or more types of debris in the wellbore, wellbore geometry anomalies, cement, keyways, or drill cuttings buildup in the annulus.

[0079] Figure 3 An embodiment of a method for dynamically adjusting drilling parameters during drilling operations is illustrated. In one embodiment, the method includes, in block 302, receiving drilling parameter measurements in real time during drilling operations. As used herein, drilling parameters refer to parameters that can vary directly or indirectly and produce a measurable response. Drilling parameters can be used on surface equipment, downhole tools, or both. The measured drilling parameters can be drilling rates, surface drill string rotation speeds, jack speeds, pump stroke rates, etc., or combinations of different measured drilling parameters.

[0080] The method may also include, in block 304, receiving response measurements during drilling operations. As mentioned, the response is a numerical change caused by variations in drilling parameters. Examples include changes in drill string torque in response to changes in RPM. Another example is a change in the pressure differential across the motor in response to changes in the rate of drilling (ROP). Response measurements can be, for example, drill string torque, hook load, drilling pressure, pressure differential, or a combination thereof.

[0081] The method may include, in box 306, determining whether a response measurement is within a response window that defines an expected lower limit and an expected upper limit for the response measurement. When the response measurement is within the response window, the method may include continuously monitoring drilling parameters and the response. In response to determining that the response measurement is below the expected lower limit, the method may include taking a corrective action to bring the response measurement back into the window. In some embodiments, if the method determines that the response measurement is trending downward toward the expected lower limit of the response window, the method may trigger a corrective action even when the response measurement is still within the response window.

[0082] In one embodiment, the method includes determining the rate of change of the response measurement and estimating the amount of time required for a change in the drilling parameters to affect the response measurement. In such an embodiment, the method can trigger a change in the drilling parameters while allowing sufficient time for it to affect the response measurement and keep it within the response window.

[0083] In one embodiment, the method includes averaging the response measurements over a period of time to smooth the response measurements and remove noise from them. Other methods for reducing or eliminating noise from the response measurements may also be used. In this document, decisions made using measurements can refer to decisions made using the original measurement itself or smoothed, processed, or cleansed measurement data.

[0084] The method may include, in block 308, determining a new drilling parameter value that will increase the response measurement, in response to determining that the response measurement is below the expected lower limit of the response window or trending downward. The method may also include, in block 310, comparing the new drilling parameter value with well section limits, and in block 312, comparing the new drilling parameter value with hard limits.

[0085] If the new drilling parameter values ​​are below the well section limits and hard limits, the method may include taking no additional action. In one embodiment, it may include considering other drilling parameter values. In another embodiment, it may include continuing to monitor drilling parameters and response measurements. In one embodiment, it may include changing the drilling parameters to the new values, or providing instructions to the driller to change the drilling parameters without adjusting the limits on the drilling parameters. In such embodiments, drilling operations can continue with the new drilling parameters while still operating within the well section limits and hard limits.

[0086] In another scenario, drilling parameter values ​​may exceed hard limits. In such embodiments, the method may include searching for different drilling parameters that could affect the response. The method may include increasing the upper limit of the drilling parameter window to a new drilling parameter value, but only up to the level of the hard limit. For example, the system may determine that a new RPM value 'a' will help mitigate stick-slip conditions, where the interval limit for RPM is 'b', the hard limit is 'c', and a > c and a > b. In this case, the system may increase the RPM limit above the interval limit 'b' to the hard limit 'c', rather than the larger RPM value 'a'.

[0087] In block 314, the drilling parameter value may be above the well section limit and below the hard limit. In this case, the method may include, as in block 316, increasing the upper limit of the drilling parameter window to the new drilling parameter value. In some cases, the method may include automatically increasing the drilling parameter to the new drilling parameter value, which will increase the response measurement. For example, an autonomous drilling system may increase the drilling parameter value. In another embodiment, the method includes increasing the upper limit of the drilling parameter window and notifying the driller of the change in the upper limit. The method may also provide the driller with a suggestion to use the new drilling parameter value.

[0088] This method can also provide the driller with suggested interpretations. For example, the system can provide the driller with a message indicating that the response measurement is outside the response window or has a downward trend, and that using new drilling parameter values ​​can mitigate the downward trend or bring the response measurement back into the window.

[0089] The method may also include monitoring response measurements after increasing drilling parameters to new drilling parameter values. The method may include determining whether the response measurements stabilize within a response window, and, in response, resetting the upper limit of the drilling parameter window to the well section limit of the drilling parameters. In such an embodiment, the well section limit can still be considered a preferred limit for the drilling parameters, and the method may default back to the well section limit once the response measurements return to an acceptable range. Once the response measurements return to the response window, Figure 3 The method can be restarted, with the system monitoring drilling parameter measurements and response measurements as described above.

[0090] In some embodiments, the method may include gradually increasing the upper limit of a drilling parameter window to a new drilling parameter value. For example, it may be desirable to smoothly increase the drilling parameters over a period of time. In such embodiments, the method may generate transition values ​​for the drilling parameter window that gradually transition the upper limit of the drilling parameter window to the new drilling parameter value. Similarly, when response measurements recover and stabilize within the response window, the method may generate transition values ​​for the drilling parameter window to gradually transition the drilling parameter window back to the well section limits of the drilling parameters.

[0091] While the example above describes the method in conjunction with a single drilling parameter, it should be understood that the method can be extended to multiple drilling parameters. In such an embodiment, the method may include determining new drilling parameter values ​​for multiple drilling parameters that, when combined, will increase the response measurement. The method may include comparing the drilling parameter values ​​of one or more of this set of drilling parameters with their respective well section limits and hard limits. As described, for drilling parameter values ​​that are above the well section limit and below the hard limit, the method may include increasing the upper limit of the drilling parameter window with their respective drilling parameter values.

[0092] In such an embodiment, the system may prioritize drilling parameter values ​​that are above the well section limit but below the hard limit. For example, if a particular drilling parameter value is above both the well section limit and the hard limit, the method may look for different parameters to adjust. In another embodiment, the method includes adjusting all drilling parameter values ​​associated with the response measurement while adhering to the hard limits as described above.

[0093] In one embodiment, the method includes minimizing deviations from well section limits. For example, multiple drilling parameters may influence response measurements. In such an embodiment, new drilling parameter values ​​can be determined for each drilling parameter affecting the response measurements. The system can determine new drilling parameter values ​​that return the response measurements to the response window while minimizing deviations from well section limits. For example, the method may include applying a cost function to find drilling parameter values ​​that minimize the difference between the new drilling parameter value and the well section limits. This approach facilitates the selection of new drilling parameter values ​​that will return the response measurements to the response window while maintaining the benefits of adhering to or remaining as close as possible to well section limits.

[0094] As noted above, the method may also include displaying a drilling parameter window created using the new drilling parameter values ​​via a calculation system. The calculation system may be part of a control system and allow the driller to adjust the drilling parameters within the drilling parameter window. In another embodiment, the control system in autonomous mode adjusts the rig operation to perform drilling operations within the drilling parameter window created using the new drilling parameter values.

[0095] As discussed above, Figure 3 The method described can be successfully applied to a range of scenarios where specific drilling parameters can be used to adjust response measurements. Figure 4 This illustrates a specific implementation of the method for a particular response measurement. Figure 4 Provided by way of examples, and without limiting the applicability of a wider range of methods to different problems with different drilling parameters and different drilling responses.

[0096] exist Figure 4In a specific example, the method includes, in box 402, measuring the rate of drilling (ROP) in real time during a directional drilling operation. The method may also include, in box 404, measuring the pressure difference across a motor that is part of a bottom hole assembly (BHA) in real time during a directional drilling operation. The method may include, in box 406, determining whether the pressure difference is within a predetermined pressure difference window, which specifies a lower limit and an upper limit for the pressure difference. In response to determining that the pressure difference is below the lower limit of the predetermined pressure difference window or trending downwards towards the predetermined pressure difference window, the method may include, in box 408, determining a new ROP value that will increase the pressure difference. The method may also include, in box 410, comparing the new ROP value to a well section limit for the ROP, and in box 412, comparing the new ROP value to a hard limit for the ROP.

[0097] The method may include, in box 414, determining whether the new ROP is above the well section limit and below the hard limit. In response to the new ROP value being above the well section limit and below the hard limit, the method may include, in box 416, increasing the upper limit of the ROP window to the new ROP value.

[0098] As discussed, if the new ROP value is higher than both the well section limit and the hard limit, the method may include setting the new ROP value to the hard limit and increasing the upper limit of the ROP window to the hard limit. In one embodiment, if the new ROP value is equal to or lower than both the well section limit and the hard limit, the method may include increasing the ROP without changing the upper limit of the ROP window.

[0099] In some embodiments, the method includes automatically increasing the ROP to a new ROP value that will increase the pressure differential. The method may also include providing the driller with notification of the ROP increase and an explanation of the increase. In another embodiment, the method may include providing the driller with an instruction to increase the ROP and providing the driller with an updated ROP window.

[0100] While the above example describes updating the upper bound of the ROP window, a similar process can be used to update the lower bound of the ROP window. For example, the method could include determining a minimum ROP different from the well section limit and also providing an updated lower bound for the ROP window. In some embodiments, the ROP window (or more generally, drilling parameters) may include only the upper bound. As used herein, the ROP window (or drilling parameter window) includes cases where only one of the upper and lower bounds is provided.

[0101] In some embodiments, after the ROP increases and the ROP window is updated with new limits, the method includes monitoring the pressure differential after the ROP increases to the new ROP value and determining whether the pressure differential stabilizes within a predetermined pressure differential window. In response to pressure differential stabilization, the method may include resetting the upper limit of the ROP window to the well section limit of the ROP.

[0102] Such as combination Figure 3 More generally, other parameters can be associated with the pressure differential. In some embodiments, the method includes identifying new values ​​for drilling parameters other than ROP that will increase the pressure differential, and for these additional drilling parameters, comparing the new values ​​with their well section limits and hard limits. As described above in conjunction with ROP, the upper limit of the window for these additional drilling parameters can also be increased to the corresponding new value of the additional drilling parameter.

[0103] Figure 5A An example of the pressure difference and ROP relationship described above is shown. Figure 5A and 5B Example measurements are shown on a time-depth graph, where time values ​​(e.g., 18:37:30) and depth values ​​(e.g., 12237) are along the y-axis. The x-axis shows multiple sets of values ​​along the time-depth values. From left to right, Figure 5A The pressure difference measurement 502 and the ROP measurement 504 are shown.

[0104] The rightmost figure shows the ROP measurement value 504. In the illustrated embodiment, this includes the ROP limit 522, shown as a solid black line. As shown, the ROP limit 522 can simply be the maximum value. In other embodiments, the ROP limit 522 can also be specified to define the ROP window. Figure 5A and 5B As shown, the ROP limit 522 can be varied.

[0105] The illustrated embodiment shows the original ROP 520 as a thick dashed line. The illustrated embodiment shows the driller closely following the ROP limit 522. As shown, continuing drilling according to the ROP parameters specified by the original ROP 520 results in the original pressure difference 510 shown in the pressure difference measurement 502. In the illustrated embodiment, although using the original ROP 520 parameters results in close adherence to the ROP limit 522, the original pressure difference 510 is often outside the pressure difference window specified by the pressure difference limit 512.

[0106] Figure 5B The same example is shown, but with the addition of dynamic adjustment of ROP drilling parameters as described here. Trigger 505 represents a method for determining whether the response measurement is within the response window or trending downwards. Figure 5BAs shown, trigger 505 can be a value between, for example, -0.1 and 1.1. In the illustrated embodiment, when the ROP value is high, trigger 505 causes an adjustment to the ROP value, and when the ROP value is low, trigger 505 causes the system to revert to the well section limit.

[0107] Figure 5B The response of trigger 505 to a new pressure difference 514 is shown. In this example, the pressure difference limit 512 represents the response window of the pressure difference. Figure 5B In this context, pressure differential limit 512 represents the lower and upper limits of the pressure differential within a specific well section. Although the illustrated embodiment shows pressure differential limit 152 as a static value, pressure differential limit 512 can vary in different wells or in different sections of the same well.

[0108] like Figure 5B As shown, when the new pressure differential 514 is consistently below the pressure differential limit 512, or decreases towards the lower limit of the pressure differential limit 512, trigger 505 has a high value, triggering adjustments to the ROP value and ROP limit 522. When the new pressure differential 514 measurement stabilizes or tends to rise, the system can deactivate trigger 505, and the ROP limit 522 and recommended ROP parameters return to the well section limits. The sensitivity of trigger 505 to changes can be adjusted to reduce the likelihood that trigger 505 is activated in response to noise or fluctuations at or near the pressure differential limit 512.

[0109] ROP measurement value 504 shows the new ROP value 524 and the original ROP limit 522. (Compared to...) Figure 5A Compared to the embodiment shown, the new ROP 524 value does not closely adhere to ROP limit 522. However, Figure 5B This illustrates how dynamic adjustment of the ROP limit 522 results in a new pressure differential 514 value, which is higher than... Figure 5A The situation shown is more within the window defined by the pressure difference limit 512.

[0110] In the illustrated embodiment, the driller or system frequently changes the new ROP 524 in the well section to control the new pressure differential 514. When trigger 505 is activated (high), the system can relax the ROP limit 522. In one embodiment, the system relaxes the ROP limit 522 by 50 feet per hour.

[0111] For clarity, Figure 5BThe new ROP limit is not shown; however, in the illustrated embodiment, the new ROP limit is dynamically increased to a well section limit above the ROP (represented by ROP limit 522) but below a hard limit above which operating the ROP would result in risks to safety, equipment, or the well. This approach strikes a balance between protecting safety and equipment (by adhering to hard limits) and utilizing the team's expertise (by defaulting to well section limits), while still maintaining the flexibility to respond appropriately to events such as a new pressure differential 514 falling outside the differential pressure limit, to provide more consistent results providing response measurements within a specified window.

[0112] The method described herein can be implemented as a set of instructions stored in memory and executed by a processor. The computer system can be part of a drilling system. In some embodiments, the computer system can be as follows: Figure 2 This is part of the drilling system shown. The drilling system may include a drilling rig control system that communicates with the drilling rig equipment. In one embodiment, a computer system may be part of the drilling rig control system. In another embodiment, the computer system may be separate from the drilling rig control system and communicate with the drilling rig control system using a software interface.

[0113] As discussed, the computer system can receive drilling parameter measurements and response measurements in real time during drilling operations. The computer system can determine whether the response measurement is within a response window that defines a lower and upper expected limit for the response measurement. In response to determining that the response measurement is below the expected lower limit, or trending downwards towards the expected lower limit, the computer system can determine a new drilling parameter value that will increase the response measurement.

[0114] The computer system can compare new drilling parameter values ​​with well section limits and hard limits for those values. If the drilling parameter value is above the well section limit but below the hard limit, the computer system can increase the upper limit of the drilling parameter window to the new drilling parameter. The computer system can also increase the drilling parameter itself (or instruct the driller to do so) to a value equal to or below the updated upper limit. This method can be used to dynamically adjust drilling parameter values ​​that define the acceptable values ​​window for drilling parameters, and it can also be used to update the drilling parameters themselves.

[0115] In some embodiments, the methods disclosed herein may be performed by a computing system. Figure 6An example of such a computing system 600 according to some embodiments is shown. The computing system 600 may include a computer or a computer system 601A, which may be a standalone computer system 601A or an arrangement of distributed computer systems. The computer system 601A includes one or more analysis modules 602 configured to perform various tasks according to some embodiments, such as one or more methods disclosed herein. To perform these different tasks, the analysis modules 602 execute independently or in coordination with one or more processors 604 connected to one or more storage media 606. The processor 604 is also connected to a network interface 607 to allow the computer system 601A to communicate with one or more additional computer systems and / or computing systems, such as 601B, 601C and / or 601D, via a data network 609. (Note that computer systems 601B, 601C and / or 601D may or may not share the same architecture as computer system 601A and may be located in different physical locations. For example, computer systems 601A and 601B may be located in a processing facility while communicating with one or more computer systems, such as 601C and / or 601D, located in one or more data centers and / or in different countries on different continents.)

[0116] The processor may include a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array or other control or computing device.

[0117] Storage medium 606 can be implemented as one or more computer-readable or machine-readable storage media. Note that, although in Figure 6 In the example embodiments, storage medium 606 is depicted as being within computer system 601A; however, in some embodiments, storage medium 606 may be distributed within and / or across multiple internal and / or external chassis of computing system 601A and / or additional computing systems. Storage medium 606 may include one or more different forms of memory, including semiconductor memory devices such as dynamic or static random access memory (DRAM or SRAM), erasable and programmable read-only memory (EPROM), electrically erasable and programmable read-only memory (EEPROM) and flash memory, magnetic disks such as fixed, floppy, and removable disks, other magnetic media including magnetic tape, and discs such as CDs or digital video discs (DVDs), BLURAY, etc. ®Optical discs or other types of optical storage or other types of storage devices. Note that the instructions discussed above may be provided on a single computer-readable or machine-readable storage medium, or on multiple computer-readable or machine-readable storage media distributed across a large system that may have multiple nodes. Such computer-readable or machine-readable storage media are considered part of an article (or manufactured article). An article or manufactured article may refer to any single or multiple manufactured components. One or more storage media may be located in a machine that executes the machine-readable instructions, or at a remote site from which machine-readable instructions can be downloaded via a network for execution.

[0118] In some embodiments, computing system 600 includes one or more drilling control modules 608. In an example of computing system 600, computer system 601A includes a drilling control module 608. In some embodiments, a single drilling control module may be used to perform aspects of one or more embodiments of the methods disclosed herein. In other embodiments, multiple drilling control modules may be used to perform aspects of the methods disclosed herein.

[0119] It should be understood that computing system 600 is merely an example of a computing system, and computing system 600 may have more or fewer components than shown, and can be combined. Figure 6 The accessories not shown in the example embodiments, and / or the computing system 600 may have Figure 6 Different configurations or arrangements of the components shown. Figure 6 The various components shown can be implemented in hardware, software, or a combination of hardware and software, including one or more signal processing and / or application-specific integrated circuits.

[0120] Furthermore, the steps in the processing methods described herein can be implemented by operating one or more functional modules in an information processing apparatus, such as a general-purpose processor or a dedicated chip, such as an ASIC, FPGA, PLD, or other suitable device. These modules, combinations of these modules, and / or their combinations with general-purpose hardware are included within the scope of this disclosure.

[0121] Computational interpretations, models, and / or other interpretative aids can be refined iteratively; this concept applies to the methods discussed herein. This can include the use of feedback loops executed on an algorithmic basis, such as in a computing device (e.g., Figure 6 The computing system 600), and / or through user manual control, allows the user to determine whether a given step, action, template, model, or set of curves has become accurate enough to evaluate the subsurface three-dimensional geological structure under consideration.

[0122] in conclusion

[0123] The embodiments disclosed in this disclosure help to explain the concepts described herein. This description is not exhaustive and does not limit the claims to the precise embodiments disclosed. Modifications and variations to the precise embodiments in this disclosure remain within the scope of the claims.

[0124] Similarly, the described steps need not be performed in the same order or with the same degree of separation as discussed. Various steps may be appropriately omitted, repeated, combined, or separated. Therefore, this disclosure is not limited to the embodiments described above, but is defined by the appended claims in the full scope of their equivalents. In the above description and the following claims, unless otherwise stated, the term "execution" and variations thereof will be interpreted as relating to any operation of program code or instructions on the apparatus, whether compiled, interpreted, or run using other techniques.

[0125] Unless the phrase “means for…” is used explicitly in conjunction with the associated function, the subsequent claims do not invoke section 112(f).

Claims

1. A method for dynamically adjusting drilling parameters during drilling operations, comprising: During directional drilling operations, the pressure difference across the motor of the bottom hole assembly is measured in real time. During directional drilling operations, the drilling rate of the bottom hole components is measured in real time; Determine whether the pressure difference is within the predetermined pressure difference window of the specified lower and upper pressure difference limits; In response to determining that the pressure difference is below or trending downward toward the lower limit of a predetermined pressure difference window: Determine a new drilling rate value that will increase the pressure differential; Compare the new drilling rate value with the well section limit for drilling rate; Compare the new drilling rate value with the hard limit on drilling rate; and In response to a new drilling rate value that is higher than the well section limit but lower than the hard limit, the upper limit of the drilling rate window is increased to the new drilling rate value.

2. The method of claim 1, further comprising automatically increasing the drilling rate to a new drilling rate value that will increase the pressure differential.

3. The method according to claim 1, further comprising: Monitor the pressure differential after increasing the drilling rate to the new drilling rate value; Determine whether the pressure differential is stable within the predetermined pressure differential window; and In response to the pressure difference stabilizing within a predetermined pressure window, the upper limit of the drilling rate window is reset to the well section limit of the drilling rate.

4. The method of claim 1, further comprising, in response to determining that the pressure difference is below or trending downward toward the lower limit of the predetermined pressure difference window: Identify new values ​​for one or more additional drilling parameters that will increase the pressure differential; Compare the new values ​​of one or more additional drilling parameters with the well section limits of one or more additional drilling parameters; Compare the new values ​​of one or more additional drilling parameters with the hard limits of one or more additional drilling parameters; and In response to a new value for one or more additional drilling parameters that is higher than the well section limit of one or more additional drilling parameters and lower than the hard limit of one or more additional drilling parameters, the upper limit of the window for one or more additional drilling parameters is increased to the new value of one or more additional drilling parameters.

5. A non-transitory, tangible computer-readable storage medium comprising instructions for dynamically adjusting drilling parameters during drilling operations, the instructions comprising: Receive drilling parameter measurements in real time during drilling operations; Receive response measurements in real time during drilling operations; Determine whether the response measurement is within the response window, which defines the expected lower and upper limits of the response measurement; The response is determined to be below the expected lower bound of the response window or trending downward toward the expected lower bound of the response window. Determine new drilling parameter values ​​that will increase the response measurements; Compare the new drilling parameter values ​​with the well section limits of the drilling parameters; Compare the new drilling parameter values ​​with the hard limits of the drilling parameter values; and In response to the drilling parameter value being higher than the well section limit but lower than the hard limit, the upper limit of the drilling parameter window is increased to the new drilling parameter value.

6. The non-transitory, tangible computer-readable storage medium of claim 5, further comprising instructions for automatically increasing drilling parameters to new drilling parameter values ​​that will increase the response measurement.

7. The non-transitory, tangible computer-readable storage medium of claim 5, further comprising instructions for: After adding drilling parameters to the new drilling parameter values, monitor the response measurements; Determine whether the response measurement is stable within the response window; and In response to the response measurement stabilizing within the response window, the upper limit of the drilling parameter window is reset to the well section limit of the drilling parameters.

8. The non-transitory, tangible computer-readable storage medium of claim 7, further comprising instructions for generating one or more transition values ​​for a drilling parameter window to gradually transition the drilling parameter window back to the well section limit of the drilling parameters.

9. The non-transitory, tangible computer-readable storage medium of claim 5, further comprising instructions for responding to determining that the response measurement is below or trending downward toward the expected lower limit of the response window: To determine multiple new drilling parameter values ​​for multiple drilling parameters that have increased response measurements; For one or more of multiple drilling parameters, compare multiple new drilling parameter values ​​with well section limits for multiple drilling parameters; For one or more of a plurality of drilling parameters, the plurality of new drilling parameter values ​​are compared with the hard limits of the plurality of drilling parameters; In response to the plurality of drilling parameter values ​​being higher than the well section limit of the plurality of drilling parameters and lower than the hard limit of the plurality of drilling parameters, the upper limit of the drilling parameter window of the plurality of drilling parameters is increased to the new drilling parameter value.

10. The non-transitory, tangible computer-readable storage medium of claim 9, wherein the response measurement includes one or more of drill string torque, hook load, drill pressure, and pressure differential.

11. The non-transitory, tangible computer-readable storage medium of claim 9, wherein the drilling parameters are one or more of drilling rate, surface drill string speed, pulley speed, and pump stroke rate.

12. The non-transitory, tangible computer-readable storage medium of claim 9, wherein determining a plurality of new drilling parameter values ​​includes selecting values ​​for the new drilling parameter values ​​that minimize the difference between the new drilling parameter values ​​and the well section limits of the plurality of drilling parameters.

13. The non-transitory, tangible computer-readable storage medium of claim 9, wherein the control system displays a drilling parameter window created using new drilling parameter values ​​on a display for the driller, and allows the driller to adjust multiple drilling parameters within the drilling parameter window.

14. The non-transitory, tangible computer-readable storage medium of claim 5, wherein the control system in autonomous mode adjusts drilling rig operations to perform drilling operations within a drilling parameter window created using new drilling parameter values.

15. A system for dynamically adjusting drilling parameters during drilling operations, the system comprising: Bottom-of-well components; Drilling rig control system; A computer system including one or more processors and storage devices, the computer system including instructions for: Receive drilling parameter measurements in real time during drilling operations; Receive response measurements in real time during drilling operations; Determine whether the response measurement is within the response window, which defines the expected lower and upper limits of the response measurement; The response is determined to be below the expected lower bound of the response window or trending downward toward the expected lower bound of the response window. Determine new drilling parameter values ​​that will increase the response measurements; Compare the new drilling parameter values ​​with the well section limits of the drilling parameters; Compare the new drilling parameter values ​​with the hard limits of the drilling parameter values; and In response to the drilling parameter value being higher than the well section limit but lower than the hard limit, the upper limit of the drilling parameter window is increased to the new drilling parameter value.

16. The system of claim 15, wherein the computer system is a component of the drilling rig control system.

17. The system of claim 15, wherein the computer system is separate from the drilling rig control system and is connected to the drilling rig control system via an interface communication.

18. The system of claim 15, further comprising instructions for automatically increasing drilling parameters to new drilling parameter values ​​that will increase the response measurement.

19. The system of claim 15, further comprising instructions for: After adding drilling parameters to the new drilling parameter values, monitor the response measurements; Determine whether the response measurement is stable within the response window; and In response to the response measurement stabilizing within the response window, the upper limit of the drilling parameter window is reset to the well section limit of the drilling parameters.

20. The system of claim 19, further comprising instructions for generating one or more transition values ​​for a drilling parameter window to gradually transition the drilling parameter window back to the well section limit of the drilling parameters.

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