Drilling control

Abstract

One method may include receiving trolley position data of a drill string before adding a section of tubing to the drill string, wherein the drill string is at least partially positioned in the borehole and supported by the drill string; receiving trolley position data of the drill string after adding the section of tubing to the drill string; and using at least a portion of the drill string and trolley position data to control the position of the drill string relative to time to land the drill bit of the drill string at the bottom of the borehole.

Description

[0001] Related applications

[0002] This application claims priority and benefit to U.S. Provisional Application No. 62 / 954,349, filed December 27, 2019, which is incorporated herein by reference. Background Technology

[0003] A resource field can be an accumulation, pool, or group of pools of one or more resources (e.g., oil, gas, petroleum, and natural gas) in a subsurface environment. A resource area may include at least one reservoir. A reservoir may be shaped in a manner capable of capturing hydrocarbons and may be covered by impermeable or sealed rock. A borehole (e.g., a borehole) may be drilled in the environment, and a well may be formed using this borehole, which can be used to produce hydrocarbons from the reservoir.

[0004] A drilling rig can be a component system operable to create a borehole in the environment, transport equipment into and out of the borehole, etc. As an example, a drilling rig may include systems that can be used to drill a borehole and obtain information about the environment, about the well, etc. A resource oil field can be an onshore oil field, an offshore oil field, or an onshore and offshore oil field. A drilling rig may include components for performing onshore and / or offshore operations. A drilling rig can be, for example, ship-based, offshore platform-based, shore-based, etc.

[0005] Oilfield planning and / or development can be carried out in one or more phases, which may include exploration phases (e.g., prospect, prospect, etc.) aimed at identifying and assessing the environment, which may include drilling one or more boreholes (e.g., one or more exploration wells, etc.). As mentioned, for production purposes, the boreholes can be drilled using a drilling rig and completed to form a production well. Summary of the Invention

[0006] A method may include receiving block position data of a drill rig before adding a section of tubing to a drill string, wherein the drill string is at least partially positioned in the borehole and supported by the drill rig; receiving the block position data of the drill rig after adding the section of tubing to the drill string; and using at least a portion of the drill rig and block position data to control the position of the drill string relative to time to land the drill bit of the drill string at the bottom of the borehole. The system may include a processor; processor-accessible memory; and processor-executable instructions stored in the memory and executable to instruct the system to: receive block position data of the drill rig before adding a section of tubing to the drill string, wherein the drill string is at least partially positioned in the borehole and supported by the drill rig; receive the block position data of the drill rig after adding the section of tubing to the drill string; and use at least a portion of the drill rig and block position data to control the position of the drill string relative to time to land the drill bit of the drill string at the bottom of the borehole. One or more computer-readable storage media may include processor-executable instructions to instruct a computing system to: receive trolley position data of a drilling rig before adding a section of tubing to the drill string, wherein the drill string is at least partially positioned in the borehole and supported by the drilling rig; receive trolley position data of the drilling rig after adding the section of tubing to the drill string; and control the position of the drill string relative to time using at least a portion of the drilling rig and trolley position data to land the drill bit of the drill string at the bottom of the borehole. Various other apparatuses, systems, methods, etc., are also disclosed.

[0007] This overview is provided to introduce a selection of concepts that will be further described in detail below. This overview is not intended to identify key or essential features of the claimed subject matter, nor is it intended to help limit the scope of the claimed subject matter. Attached Figure Description

[0008] The features and advantages of the embodiments can be more easily understood by referring to the following description in conjunction with the accompanying drawings.

[0009] Figure 1 Examples of equipment in geological environments are shown;

[0010] Figure 2 Examples of devices and hole types are shown;

[0011] Figure 3 An example of the system is shown;

[0012] Figure 4 Examples of well site systems and computing systems are shown;

[0013] Figure 5 An example of a graphical user interface is shown;

[0014] Figure 6 An example of the method is shown;

[0015] Figure 7An example of a graphical user interface is shown;

[0016] Figure 8 Examples of methods and systems are shown;

[0017] Figure 9 An example of a method using a geograph chart is shown;

[0018] Figure 10 An example of the system is shown;

[0019] Figure 11 Examples of methods and systems are shown;

[0020] Figure 12 An example of a well-construction ecosystem including one or more systems is shown;

[0021] Figure 13 An example of a computing system is shown; and

[0022] Figure 14 Example components of the system and networked system are shown. Detailed Implementation

[0023] The following description includes the best mode currently contemplated for carrying out the described embodiments. This description should not be construed as restrictive, but rather is for the purpose of describing the general principles of the embodiments only. The scope of the described embodiments should be determined with reference to the published claims.

[0024] Figure 1 An example of geological environment 120 is shown. Figure 1 In this context, the geological environment 120 may be a sedimentary basin comprising layers (e.g., strata), including reservoir 121, and may be traversed, for example, by faults 123 (e.g., one or more faults). For example, the geological environment 120 may be equipped with any of a variety of sensors, detectors, actuators, etc. For example, device 122 may include communication circuitry to receive and transmit information about one or more networks 125. This information may include information associated with downhole device 124, which may be a device for acquiring information, assisting in resource recovery, etc. Other devices 126 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 devices may provide data for measurement, collection, communication, storage, analysis, etc. (e.g., for one or more produced resources). As an example, one or more satellites may be provided for communication, data acquisition, etc. Figure 1A satellite communicating with network 125 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.).

[0025] Figure 1 Geological environment 120 is also shown, which optionally includes well-related equipment 127 and 128, the well comprising a basic horizontal portion (e.g., a lateral portion) that may be penetrated by one or more fractures 129. For example, consider a well in a shale formation, 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 extending reservoir. In such an example, lateral variations in properties, stresses, etc., may exist, where assessment of such variations may aid in planning, operations, etc., to develop the reservoir (e.g., by fracturing, injection, extraction, etc.). As an example, equipment 127 and / or 128 may include components, a system, multiple systems, etc., for fracturing, seismic sensing, seismic data analysis, assessment of one or more fractures, injection, production, etc. As an example, equipment 127 and / or 128 may provide data for measurement, collection, communication, storage, analysis, etc., such as production data (e.g., for one or more produced resources). As an example, one or more satellites may be provided for communication, data acquisition, etc.

[0026] Figure 1 Examples of devices 170 and 180 are also shown. Such devices can be component systems suitable for geological environments 120. Although devices 170 and 180 are illustrated as land-based, various components can be adapted to offshore systems (e.g., offshore drilling rigs, etc.).

[0027] Equipment 170 includes a platform 171, a derrick 172, a crane 173, a rope 174, a traveling block assembly 175, a winch 176, and a landing 177 (e.g., a second-level platform). As an example, the rope 174 can be controlled at least partially by the winch 176, allowing the traveling block assembly 175 to travel vertically relative to the platform 171. For example, by retracting the rope 174, the winch 176 can pass the rope 174 through the crane 173 and raise the traveling block assembly 175 away from the platform 171 towards the sky; however, by allowing the rope 174 to extend, the winch 176 can pass the rope 174 through the crane 173 and lower the traveling block assembly 175 towards the platform 171. The traveling block assembly 175 carries tubing (e.g., casing), and the motion tracking of the traveling block 175 can provide an indication of how much tubing has been deployed.

[0028] The derrick can be a structure used to support a crane and a traveling block, with the traveling block at least partially operably connected to the crane via ropes. The derrick can be pyramidal in shape and provide a suitable strength-to-weight ratio. The derrick can be movable as a unit or in pieces (e.g., assembled and disassembled).

[0029] As an example, a winch may include a spool, a brake, a power source, and associated auxiliary devices. The winch can controllably reel out and retract a rope. The rope can be wound around a crane and connected to a traveling block, obtaining mechanical benefits in a "pulley block" or "pulley" manner. Reeling out and retracting the rope causes the traveling block (e.g., and anything suspended below it) to be lowered into or raised from the borehole. Reeling out can be gravity-driven, while retraction can be driven by a motor, engine, etc. (e.g., electric motor, diesel engine, etc.).

[0030] As an example, a crane may include a set of pulleys (e.g., grooved sheaves) located at or near the top of the derrick or mast, through which ropes pass. A traveling block may include a set of grooved sheaves that can move up and down within the derrick or mast via ropes passing through the grooved sheaves of the traveling block and the crane. The crane, traveling block, and ropes can form a pulley system for the derrick or mast that allows the handling of heavy loads (e.g., drill string, pipe, casing, liner, etc.) from or into the borehole. For example, the rope diameter can be approximately one to five centimeters, such as steel cable. By using a set of grooved sheaves, such a rope can carry a heavier load than a rope as a single strand can support.

[0031] As an example, a derrickman can be a member of the drilling team working on a platform attached to a derrick or mast. The derrick may include a platform on which the derrickman can stand. As an example, such a platform might be approximately 10 meters or higher above the drill rig. In an operation known as Take-Out-of-Hole (TOH), the derrickman may wear a safety harness that allows him to reach out from the work platform (e.g., a second platform) to access the pipe located at or near the center of the derrick or mast, throw a rope around the pipe, and pull it back to its storage location (e.g., a fingerboard, for example, until it may be desired to return the pipe to the borehole). As an example, the drilling rig may include automated pipe handling equipment, allowing the derrickman to control the machine rather than physically moving the pipe.

[0032] As an example, tripping in and out of the borehole can refer to the action of pulling equipment out of the borehole and / or placing equipment into the borehole. As an example, equipment may include a drill string that can be pulled out of the well and / or placed or replaced in the well. As an example, tripping in and out of the tubing may be performed when the drill bit has become dull or has ceased effective drilling and needs replacement. As an example, tripping in and out of the borehole that pulls equipment out of the borehole may be referred to as a pull-out well (POOH), and tripping in and out of the borehole that sends equipment into the borehole may be referred to as a feed-in well (RIH).

[0033] Figure 2 An example of a well site system 200 (e.g., a well site located onshore or offshore) is shown. As illustrated, 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 towing one or more drill lines 212 by a winch, 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 transporting the traveling block 211 via one or more drill lines 212 (see example...). Figure 1 (Heavy crane 173), derrick 214 (see, for example) Figure 1 The derrick 172), prism 218 or top drive 240, prism drive bushing 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.

[0034] 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.

[0035] like Figure 2 As 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 bottomhole assembly (BHA).

[0036] The well site system 200 provides 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 described above, the well site system 200 may include a rotary table 220 through which the drill string 225 passes.

[0037] like Figure 2As 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 (e.g., square, hexagonal, etc.) that matches the external profile of the square drill pipe 218; but 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.

[0038] Regarding the top drive example, top drive 240 provides functionality 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 in turn be screwed into a protective joint or drill string 225 itself. Top drive 240 may be suspended on traveling block 211, thus allowing the rotating mechanism to move freely up and down on derrick 214. As an example, top drive 240 may allow drilling with more joints than the kauri / rotary table method.

[0039] 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.).

[0040] exist Figure 2In the example, drill string 225 (e.g., including one or more downhole tools) may consist of a series of pipes threaded together to form a long tube, with drill bit 226 located at the lower end of the long tube. When drill string 225 is advanced into the borehole for drilling, at some point before or concurrent with drilling, mud may be pumped from mud tank 201 (e.g., or other source) via lines 206, 208, and 209 to a port on kelly 218, or, for example, to a port on top drive 240, via pump 204. The mud may then flow out of the port 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 on drill bit 226, it may then circulate upwards through an annular region between the outer surface of drill string 225 and the surrounding wall (e.g., open well borehole, casing, etc.), as indicated by the directional arrows. In this way, the mud lubricates the drill bit 226 and carries 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.).

[0041] The mud pumped into the drill string 225 by pump 204 forms a mud cake lining the borehole after leaving the drill string 225. Among other functions, this mud cake reduces friction between the drill string 225 and the surrounding walls (such as the borehole and casing). This reduced 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 borehole and optionally replaced with, for example, a new or sharp drill bit, a smaller diameter drill string, etc. As described above, the act of pulling the drill string out of or back into the well is called tripping. Depending on the direction of tripping, tripping can be called upward tripping or outward tripping, or downward tripping or inward tripping.

[0042] As an example, consider a down-running drill, where when the drill bit 226 of the drill string 225 reaches the bottom of the borehole, mud is pumped to lubricate the drill bit 226 for drilling purposes to enlarge the borehole. As described above, the mud can be pumped by pump 204 into the channels of the drill string 225, and while filling the channels, the mud can be used as a transmission medium for energy, for example, energy that can encode information, as in mud pulse telemetry.

[0043] As an example, a mud pulse telemetry device may include downhole equipment 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 equipment (e.g., one or more modules of drill string 225) can be transmitted to a surface unit, which can then relay such information to other equipment for processing, control, etc.

[0044] 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.).

[0045] As an example, drill string 225 may be equipped with telemetry device 252, which includes a rotatable drive shaft; a turbine cam mechanically coupled to the drive shaft so that the drilling mud can rotate the turbine cam; a regulator rotor mechanically coupled to the drive shaft so that rotation of the turbine cam can rotate the regulator 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 drilling mud; and a controllable brake for selectively braking the rotation of the modulator rotor to modulate the pressure pulses. In such an example, an AC generator may be coupled to the aforementioned drive shaft, wherein the AC generator includes at least one stator winding electrically coupled to a control circuit to selectively short-circuit the at least one stator winding to electromagnetically brake the AC generator, thereby selectively braking the rotation of the modulator rotor to modulate the pressure pulses in the drilling mud.

[0046] exist Figure 2 In one example, the well-ground control and / or data acquisition system 262 may include circuitry for sensing pressure pulses generated by the telemetry device 252, for example, transmitting the sensed pressure pulses or information obtained therefrom for processing, control, etc.

[0047] The component 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 a component or module may be referred to as a tool, wherein the drill string may include multiple tools.

[0048] 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 ground 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 is aimed at the target and eventually reaches it. Directional drilling can be implemented where a target is inaccessible from a vertical location on the earth's surface, where the earth's reservoir is a substance that may obstruct drilling or is otherwise harmful (e.g., consider salt domes), where the formation extends laterally (e.g., consider relatively thin but laterally extending reservoirs), where multiple boreholes are drilled from a single surface borehole, where a decompression well is required, and so on.

[0049] 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.

[0050] As an example, PDM can operate in a combined rotary mode, where surface equipment is used to rotate the drill string bit (e.g., rotary table, top drive) by rotating the entire drill string, and where drilling fluid is used to rotate the drill string bit. In such an example, the surface RPM (SRPM or surface_RPM) can be determined using the 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.

[0051] 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.

[0052] RSS (Rotating Surface Steering) can be used for directional drilling where it rotates continuously from surface equipment, mitigating slippage of steerable motors (e.g., PDM). RSS can be deployed during directional drilling (such as deviated, horizontal, 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 relatively consistent lateral forces, 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.

[0053] 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 used, for example, as shown in module 256 of 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 LWD module 254, module 256, etc. An LWD module may include capabilities for measuring, processing, and storing information, as well as for communicating with surface equipment. In the example shown, LWD module 254 may include seismic surveying equipment.

[0054] 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 drill string 225 and drill bit 226. As an example, MWD tool 254 may include devices for generating electricity, for example, to power various components of drill string 225. As an example, MWD tool 254 may include telemetry device 252, for example, where a turbine cam can be powered by the flow of mud; it should be understood that other power and / or battery systems may be used to power various components. As an example, 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.

[0055] Figure 2 Examples of drillable hole types are also shown. For example, consider inclined hole 272, S-shaped hole 274, deep inclined hole 276, and horizontal hole 278.

[0056] As an example, the drill string may include an azimuth density neutron (ADN) tool for measuring density and porosity; a MWD tool for measuring dip, azimuth, and impact; a compensated dual resistivity (CDR) tool for measuring resistivity and gamma-ray related phenomena; one or more variable gauge stabilizers; one or more bend subs; and a geological steering tool that may include a motor and optional equipment for measuring and / or responding to one or more of dip, resistivity, and gamma-ray related phenomena.

[0057] As an example, geological steering may include intentional directional control of boreholes based on downhole geological logging measurements, aimed at keeping directional boreholes within desired areas, formations (e.g., pay zones), etc. As another example, geological steering may include guiding boreholes to keep them within specific portions of a reservoir, for example, to minimize gas and / or water breakthroughs, and, for example, to maximize economic production from the well including the borehole.

[0058] Refer again Figure 2 The well site system 200 may include one or more sensors 264 operatively coupled to a control and / or data acquisition system 262. As an example, the one or more sensors may be located at a surface location. As an example, the one or more sensors may be located at a downhole location. As an example, the 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 the well site system 200. As an example, the one or more sensors may be located at an offset well site, where the well site system 200 and the offset well site are located in a common oil field (e.g., an oil field and / or a gas field).

[0059] As an example, one or more sensors 264 may be provided for tracking the tube, tracking the movement of at least a portion of the drill string, etc.

[0060] As an example, system 200 may include one or more sensors 266 capable of sensing and / or transmitting signals to fluid conduits, such as drilling fluid conduits (e.g., drilling mud conduits). For example, in system 200, one or more sensors 266 may be operatively coupled to a portion of a riser 208 through which mud flows. As an example, a downhole tool may generate pulses that can 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 encoding circuitry, that can encode signals, 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, 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.

[0061] 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. For example, in a stuck situation, it may be possible to rotate the drill string or lower it back 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. For example, in a stuck situation, at least a portion of the drill string may be unable to move axially and rotationally.

[0062] The term "stuck pipe" refers to a portion of the drill string that cannot rotate or move axially. As an example, "differential sticking" can occur when the drill string cannot move along the borehole axis (e.g., rotate or reciprocate). Differential sticking occurs when high contact forces, caused by low reservoir pressure, high wellbore pressure, or both, are applied over a sufficiently large drill string area. Differential sticking can have time and financial costs.

[0063] As an example, the sticking force can be the product of the pressure differential between the wellbore and the reservoir and the area over which the pressure differential acts. This means that applying a relatively low pressure differential (Δp) over a large working area is just as effective in sticking the tubing as applying a high pressure differential over a small area.

[0064] As an example, a condition known as "mechanical jamming" can be one in which the movement of the drill string is restricted or prevented by a mechanism other than differential pressure jamming. Mechanical jamming can be caused by, for example, one or more types of debris in the well, abnormal borehole geometry, cement, keyways, or drill cuttings buildup in the annulus.

[0065] Figure 3 An example of system 300 is shown, which includes various devices for evaluation 310, planning 320, engineering 330, and operation 340. For example, drilling workflow framework 301, seismic simulation framework 302, technical data framework 303, and drilling framework 304 can be implemented to perform one or more processes, such as evaluating formation 314, evaluating process 318, generating trajectory 324, verifying trajectory 328, establishing constraints 334, designing equipment and / or processes at least in part based on constraints 338, performing drilling 344, and evaluating drilling and / or formation 348.

[0066] exist Figure 3 In the example, the earthquake simulation framework 302 may be, for example, the PETREL framework (Schlumberger, Houston, Texas), and the technical data framework 303 may be, for example, the TECHLOG framework (Schlumberger, Houston, Texas).

[0067] As an example, the framework may include entities, which may include earth entities, geological objects, or other objects such as wells, surfaces, reservoirs, etc. Entities may include virtual representations of actual physical entities reconstructed for one or more purposes such as evaluation, planning, engineering, operation, etc.

[0068] As an example, the framework can be implemented within or operationally connected to the DELFI Cognitive Exploration and Production (E&P) environment (Schlumberger, Houston, Texas), a secure, cognitive, cloud-based collaborative environment that integrates data and workflows with digital technologies such as artificial intelligence and machine learning. As an example, such an environment can provide operations involving one or more frameworks.

[0069] As an example, various aspects of the workflow may be automated, partially automated, or manually performed, such as through interaction between a human user and a software application executed using hardware (e.g., local and / or remote). As an example, the workflow may be cyclical and may include, as an example, four phases, such as an evaluation phase (e.g., see evaluation device 310), a planning phase (e.g., see planning device 320), an engineering phase (e.g., see engineering device 330), and an execution phase (e.g., see operation device 340). As an example, the workflow may begin at one or more phases and may proceed to one or more other phases (e.g., sequentially, in parallel, cyclically, etc.).

[0070] As an example, a workflow may include consideration of the well trajectory, including an accepted well engineering plan and formation assessment. Such a workflow can then pass control to the drilling service provider, who can implement the well engineering plan, establish safe and efficient drilling, maintain well integrity, and report progress and operating parameters (e.g., see boxes 344 and 348). As an example, operating parameters, encountered formations, and data collected during drilling (e.g., using logging-while-drilling or measurement-while-drilling techniques) can be returned to the geological service provider for evaluation. As an example, the geological service provider can then reassess the well trajectory or one or more other aspects of the well engineering plan, and in some cases, and possibly within predetermined constraints, adjust the well engineering plan based on actual drilling parameters (e.g., based on field-obtained data, etc.).

[0071] According to specific embodiments, post-drilling inspections can be performed regardless of whether the well is fully drilled or partially completed (e.g., see evaluation box 318). As an example, post-drilling inspections may include checking drilling performance. As an example, post-drilling inspections may also include reporting drilling performance (e.g., to one or more relevant engineering, geology, or G&G service providers).

[0072] The various activities of a workflow can be performed sequentially and / or out of order (e.g., partially based on information from templates, nearby wells, etc., to fill any gaps in information that will be provided by another service provider). As an example, performing one activity may affect the outcome or basis of another activity, thus potentially requiring changes to one or more workflow activities, work products, etc., manually or automatically. As an example, a server could allow information to be stored on a central database accessible to various service providers, where changes can be sought through communication with the appropriate service provider, changes can be implemented automatically, or they may otherwise appear as recommendations to relevant service providers. This approach can be considered a holistic approach to oil well workflows compared to sequential, fragmented methods.

[0073] As an example, various actions of the workflow can be repeated multiple times during the drilling process. For instance, in one or more automated systems, feedback from the drilling service provider can be provided in real-time or near real-time, and data acquired during drilling can be fed to one or more other service providers, who can adjust a segment of their workflow accordingly. Such adjustments can permeate the workflow, for example, automatically, because dependencies may exist in other areas of the workflow. In some embodiments, cyclical processes can be performed additionally or alternatively after a drilling objective is achieved, such as completing a section of the borehole, and / or after completing the entire borehole, or on a daily, weekly, monthly, etc. basis.

[0074] A well plan may include determining the path (e.g., trajectory) of a well that extends to the reservoir, for example, to economically produce fluids, such as hydrocarbons, from the reservoir. A well plan may include selecting drilling and / or completion components that can be used to implement the well plan. As an example, various constraints may be imposed as part of the well plan, which affect the well design. As an example, such constraints may be imposed based at least in part on known geology of the subsurface area, the presence (e.g., actual and / or planned) of one or more other wells in an area (e.g., considering collision avoidance). As an example, one or more constraints may be imposed based at least in part on the characteristics of one or more tools, components, etc. As an example, one or more constraints may be based at least in part on factors associated with drilling time and / or risk tolerance.

[0075] As an example, a system can allow for the reduction of waste, for instance, as defined by LEAN. In the context of LEAN, consider one or more of the following types of waste: transport (e.g., moving unnecessary items, whether physical or data); inventory (e.g., components, whether physical or informational, as work-in-process and unfinished finished goods); motion (e.g., people or equipment unnecessarily moving or walking to perform desired processing); waiting (e.g., waiting for information, production interruptions during shift changes, etc.); overproduction (e.g., production of materials, information, equipment, etc., ahead of demand); overprocessing (e.g., resulting from poor tooling or product design activities); and defects (e.g., work involved in inspecting and repairing defects in plans, data, equipment, etc.). As an example, a system that allows actions (e.g., methods, workflows, etc.) to be performed collaboratively can help reduce one or more types of waste.

[0076] Figure 4 An example of a well site system 400 (e.g., a drilling rig field system) is shown, specifically, Figure 4 An approximate side view and approximate plan view of the well site system 400, and a block diagram of the system 470 are shown.

[0077] exist Figure 4 In the example, the well site system 400 may include a cabin 410, a rotary table 422, a winch 424, a mast 426 (e.g., optionally carrying a top drive, etc.), a mud tank 430 (e.g., having one or more pumps, one or more vibrators, etc.), one or more pump buildings 440, a boiler building 442, an HPU building 444 (e.g., with a rig fuel tank, etc.), a combination building 448 (e.g., having one or more generators, etc.), a tub 462, a catwalk 464, a bell mouth 468, etc. Such equipment may include one or more associated functions and / or one or more associated operational risks, which may be risks related to time, resources, and / or personnel.

[0078] like Figure 4 As illustrated in the example, well site system 400 may include system 470, which includes one or more processors 472, memory 474 operatively coupled to at least one of the processors 472, instructions 476, for example, that can be stored in memory 474, and one or more interfaces 478. As an example, system 470 may include one or more processor-readable media including processor-executable instructions executable by at least one of the processors 472 to cause system 470 to control one or more aspects of well site system 400. In such an example, memory 474 may be or include one or more processor-readable media, wherein processor-executable instructions may be or include instructions. As an example, processor-readable media may be a computer-readable storage medium that is neither a signal nor a carrier wave.

[0079] Figure 4 A battery 480 operatively connected to system 470 is also shown, for example, to power system 470. As an example, battery 480 may be a backup battery that operates when another power source is unavailable to power system 470. As an example, battery 480 may be operatively connected to a network, which may be a cloud network. As an example, battery 480 may include smart battery circuitry and may be operatively connected to one or more devices via SMBus or other types of bus.

[0080] exist Figure 4 In the example, service 490 is shown as available, for example, via a cloud platform. Such services may include data service 492, query service 494, and drilling service 496. As an example, service 490 could be such as Figure 3 It is part of the 300 system.

[0081] As an example, a system may include a framework that can acquire data, such as real-time data associated with one or more operations, such as one or more drilling operations. As an example, consider the PERFORM toolkit framework (Schlumberger Limited, Houston, Texas).

[0082] As an example, the service may be or include one or more of OPTIDRILL, OPTILOG, and / or other services sold by Schlumberger Ltd. of Houston, Texas.

[0083] OPTIDRILL technology can help manage downhole conditions and BHA dynamics as a real-time drilling intelligence service. This service can include rig-side displays (e.g., well site displays) that integrate downhole and surface data to provide actionable information to reduce risk and improve efficiency. As an example, such data can be stored in, for instance, a database system (e.g., consider a database system associated with the STUDIO framework).

[0084] OPTILOG technology can help evaluate drilling system performance through single-point or multi-point measurements of drilling dynamics and internal temperatures from recorders. As an example, post-run data can be analyzed to provide input for future well planning.

[0085] As an example, information from a drill bit database can be accessed and utilized. For instance, consider information from Smith Bit (Schlumberger Limited, Houston, Texas), which may include information from various operations (e.g., drilling operations) related to different drill bits, drilling conditions, formation types, etc.

[0086] As an example, one or more QTRAC services (Schlumberger Limited, Houston, Texas) can be provided for one or more well site operations. In such an example, data can be acquired and stored, which may include time-series data that can be received and analyzed.

[0087] As an example, one or more MI SWACO services (M-IL.LC, Houston, Texas) can be provided for one or more well site operations. For instance, consider services for enhancement completions and reservoir drilling fluids, additives, cleaning tools, and engineering. In such an example, data can be acquired and stored, which may include time-series data that can be received and analyzed.

[0088] As an example, one or more ONE-TRAX services (e.g., via the ONE-TRAX software platform, MI LLC, Houston, Texas) can be provided for one or more well site operations. In such an example, data can be acquired and stored, which may include time-series data that can be received and analyzed.

[0089] As an example, various operations can be defined with respect to WITS or WITSML, which are acronyms for Well Site Information Transmission Specification or Standard (WITS) and Markup Language (WITSML). WITS / WITSML specifies how a drilling rig or offshore platform rig communicates data. For example, regarding slips, which are components used to clamp and suspend the drill string on the rotary table in a relatively non-destructive manner, WITS / WITSML defines operations such as "bottom to slip" time as the time interval between leaving the bottom and setting the slip for the current connection; "in slips" as the time interval between setting the slip for the current connection and then releasing the slip; and "slip to bottom" as the time interval between releasing the slip for the current connection and returning to the bottom (e.g., setting the pressure on the drill bit).

[0090] Well construction can be carried out according to various procedures, which can take many forms. For example, procedures can be specified digitally and can be, for instance, digital plans such as digital well plans. A digital well plan can be an engineering plan for constructing the wellbore. As an example, a procedure may include information such as well geometry, casing procedures, mud considerations, well control issues, initial drill bit selection, offset well information, pore pressure estimation, economics, and special procedures that can be used during well construction, production, etc. While drilling procedures can be carefully developed and specified, various situations may arise that require adjustments to the drilling procedures.

[0091] Figure 5 An example of a graphical user interface (GUI) 500 is shown, which includes information associated with the plan. Specifically, GUI 500 includes a panel 510, where surfaces 512 and 514 are presented along with the well trajectory, and location 516 can represent the position of the drill string 517 along the well trajectory. GUI 500 may include one or more editing features, such as a set of editing well plan features 530. Information about individuals within a team 540 involved, already involved, and / or will be involved in one or more operations is also included. GUI 500 may include information about one or more activities 550.

[0092] like Figure 5As shown in the example, GUI 500 may include graphical controls for drill string 560, where, for example, various parts of drill string 560 can be selected to display one or more relevant parameters (e.g., equipment type, equipment specifications, operation history, etc.). Figure 5 In the example, the drill string graphic control 560 includes components such as drill pipe, heavy-duty drill pipe (HWDP), sub-joints, drill collars, slappers, stabilizers, motors, and drill bits. The drill string can be a combination of drill pipe, bottom loader assembly (BHA), and one or more other tools, which may include one or more tools that can help the drill bit rotate and drill into material (e.g., formation).

[0093] As an example, a workflow may include utilizing the graphical controls of the drill string 560 to select and / or display information associated with one or more components, such as the drill bit and / or mud motor. As an example, in response to the selection of the drill bit and / or mud motor (e.g., considering a combination of drill bit and mud motor), a computational framework may be used, for example, to operate the drilling equipment in a specific mode. Figure 5 In the example, a graphical control 565 is shown, which can be rendered in response to interaction with the graphical control of the drill string 560, such as to select the type of component, etc.

[0094] As an example, GUI 500 may include graphical controls for an automated driller, which can be displayed on a monitor for actuation, monitoring, control, etc., of the automated driller (e.g., an automated drilling system). In such an example, menu items can provide interaction with the ongoing bottom controller (see example...). Figure 10 (System 1000). As an example, GUI 500 may include one or more graphical controls for use with, for example, systems such as... Figure 4 System interaction of system 470.

[0095] Figure 5 An example of Table 570 as a point spreadsheet is also shown, which specifies information for multiple wells. As shown in example Table 570, coordinates such as “x” and “y” and “depth” can be specified for various characteristics of the wells, which may include pad parameters, spacing, toe height, step distance, initial dip, kickoff, etc.

[0096] Figure 6An example of a method 600 for performing drilling operations using drilling equipment is shown. As shown, the drilling equipment includes a drilling rig 601, a hoisting system 602, a sled 603, a platform 604, slips 605, and a bottom hole assembly (BHA) 606. As shown, the drilling rig 601 supports the hoisting system 602, which provides movement of the sled 603 above the platform 604. The slips 605 are used to support a drill string including the bottom hole assembly 606, which is shown to include a drill bit for drilling into the formation to form a borehole.

[0097] As for drilling operations, they include a first operation 610 of completing the stand (stand X) of the drill string; a second operation 620 of pulling the drill string out from the bottom of the borehole by moving the trolley 603 upward and supporting the drill string in the platform 604 using slips 605; a third operation 630 of adding a stand (stand X+1) to the drill string; and a fourth operation 640 of removing the slips 605 and lowering the drill string to the bottom of the borehole by moving the trolley 603 downward. See also Figure 1 , 2 Sections 3, 4, and 5 explain various details of the device examples and operation examples.

[0098] As an example, drilling operations can utilize one or more types of equipment, which can provide a variety of drilling modes. As explained, as the borehole deepens through drilling, a standpipe can be added to the drill string. The standpipe can be one or more sections of tubing; note that pipe-by-tubing or hybrid standpipe and tubing methods can be used.

[0099] exist Figure 6 In the examples, operations 610, 620, 630, and 640 might take several minutes. Consider, for instance, the amount of time required to position and connect one stand to another in the drill string. The stand length might be approximately 30 meters (e.g., about 90 feet, three 30-foot pipes connected together), with precautions taken to avoid harmful contact between the stand (metal or metal alloy) and other equipment or people. During this time period, one or more types of calculations, operations, communications, etc., may occur. For example, the driller might perform hole depth calculations based on measured stand lengths, etc. As an example, the driller might analyze survey data acquired by one or more downhole tools in the drill string. Such survey data can help the driller determine whether a planned or otherwise expected trajectory is being followed, which can help inform the driller how to drill to increase the hole depth approximately corresponding to the increased stand length.

[0100] As an example, when using a top drive (e.g., considering trolley 603 as including the top drive), as the top drive approaches platform 604, rotation and circulation can be stopped and the drill string raised a distance away from the bottom of the borehole. Since the top drive is to be coupled to another stand, disconnection is necessary, which means supporting the drill string. This can be done using slips 605. Slips 605 can be positioned on a portion of the last stand (e.g., pipe) to support the weight of the drill string, allowing the operator to disconnect the top drive from the drill string, for example, using a top drive drill pipe loader. Once disconnected, the driller can raise the top drive (e.g., trolley 603) to a suitable level, such as fingerboard level, where another stand (e.g., approximately 30m) of pipe can be delivered to a set of drill pipe lifters suspended from the top drive. The stand (e.g., stand X+1) can be raised and inserted into the drill string. The top drive can then be lowered until its drive rod engages the upper connection of the stand (e.g., stand X+1). The top drive motor can engage to rotate the drive rod, thereby enabling the upper and lower connections of the stand to be formed relatively simultaneously. In such an example, a spare tong can be used at platform 604 (e.g., drill rig) to prevent rotation of the drill string during connection. After the connection is properly established, the slips 605 can be released (e.g., out of slip). Drill fluid (e.g., mud) circulation can begin (e.g., restart), and once the drill bit of bottom assembly 606 contacts the bottom of the borehole, the top drive can be used to drill to deepen the borehole. The entire process, from setting slips on the drill string (e.g., inside slip), adding a new stand, establishing the connection, and then releasing slips (e.g., outside slip) to allow drilling to resume, may take from tens of seconds to several minutes, typically less than 10 minutes, and is generally normal and as expected.

[0101] For the top drive method described above, the process of adding a new pipe stand to the drill string and drilling down toward the platform (e.g., rig) involves fewer movements and requires less rig personnel compared to keel drilling (e.g., rotary table drilling). The driller and rig personnel can drill with top drive relatively skillfully. Built-in features such as thread compensation, remote-controlled valves for stopping drilling fluid flow, and mechanisms for tilting the hoist and connecting to derrick personnel or rig workers can increase the speed, convenience, and safety associated with top drive drilling.

[0102] As an example, when drilling with a single-joint (e.g., 10m or 30ft long) pipe, a top drive can be used, although greater benefits can be achieved by drilling with a triplet (e.g., a triplet where the stand can be approximately 30m long of pipe). As explained, with the drill pipe supported and rotated from the top, the entire stand of the drill pipe can be drilled at once. This method extends the time the drill bit spends at the bottom and contributes to a cleaner borehole. Compared to kurtosis drilling, where the joints are made after drilling a single joint, top drive drilling can speed up the drilling process by reducing the need for two-thirds of the joints.

[0103] During drilling, the length along the borehole can be manually tracked and recorded as measured depth (MD). The measured depth can be the length of the borehole, for example, as if determined by a measuring tape. For deviated wells, the measured depth differs from the true vertical depth (TVD) (see example). Figure 2 Examples of boreholes 272, 274, 276, and 278. Since boreholes cannot be physically measured from one end to the other, one method for determining the measured depth is to use a physical tape measure to measure the lengths of the individual joints of the drill pipe, drill collars, and other drill string elements. These individual measurements can be recorded (e.g., as a ledger, spreadsheet, etc.) and summed to arrive at the measured depth value. In manual methods, one or more tubes connected to the drill string can be measured while in the derrick or laid on the pipe rack, where one or more tubes are in a substantially untensioned, unstressed state compared to the condition of the tubes during drilling and / or in the borehole. When the tubes are screwed together and placed into the borehole, they are stretched by their own weight and by the bottom assembly, etc. This length-related phenomenon is typically not considered when manually reporting the measured depth based on the tape measure method. In various cases, the actual borehole depth may be slightly longer than the reported measured depth. In various cases, the driller may manually adjust one or more counts regarding bit depth and hole depth (tally); however, in some cases, one may be adjusted while the other is not. As explained earlier, manual methods of determining length can be prone to inaccuracies (e.g., human behavior, human error, etc.).

[0104] As an example, one approach could include automated drilling where data about one or more lengths can be automatically acquired and used to guide such drilling. In such an example, slip state and block position (BPOS) could be used, which can be acquired using one or more of various types of sensors, detectors, etc. For example, regardless of whether the slip is operated manually, semi-automatically, or automatically, a detector can determine the slip state, e.g., inside or outside the slip. As for the block position, it can be determined using one or more methods that can utilize cameras (e.g., machine vision), position sensors, sensor combinations, etc. For example, consider one or more cameras positioned along with a field of view (FOV) to determine the block position. As another example, consider an accelerometer-based method that can determine velocity and time, where velocity and time can be used to determine distance. As an example, the block position method could utilize a combination of technologies that could include, for example, one or more cameras and one or more sensors, which could include one or more block-mounted sensors.

[0105] As an example, one approach may include receiving an initial bottoming signal, which may be a time signal, a status signal, etc. Such a signal may be acquired automatically, semi-automatically, or manually. As an example, the drilling rig may include a button that can be actuated (e.g., pressed, clicked, etc.) to indicate an initial bottoming state. This button may be used to determine one or more things regarding slip status and / or pulley position, which may in turn be used by an automated system capable of performing at least some drilling operations. As another example, an electronics unit may receive one or more data channels from one or more sensors, detectors, etc., at the drilling site, where the electronics unit may process the data to determine the initial bottoming state (see, for example,...). Figure 4 (System 470, etc.). As an example, a combination of methods can be used, such as manual buttons and algorithm-based automated methods. In such an example, comparisons can be made between values ​​from the combination of methods (optionally selecting one value instead of another, averaging, etc.). For the initial bottom state, it can correspond to the state of completed drilling for a pipe or drill string, where the drill bit is at the bottom (e.g., in the bottom state) and where subsequent operations can be performed relative to drilling for another pipe or another drill string. As an example, the bottom state can be after a run-in of the drill string into the borehole, drilling deeper into the borehole (e.g., into the RIH), where the drill bit reaches the bottom of the borehole and the location for subsequent operations, including adding pipe, drill string, etc.

[0106] As an example, after receiving an initial bottom signal indicating a bottoming state, a method may include using data indicating slip status and pulley position to control subsequent drilling operations. For example, an autopilot (e.g., a computerized drilling operations controller, etc.) may be used to drill during periods or states outside the slips to extend the borehole. However, the autopilot may, for example, actively acquire data during that period or state between inside and outside the slips, where this acquired data can be used to instruct the autopilot how to operate during periods or states after outside the slips. For example, such an autopilot may use such acquired data to go on-bottom, where going on-bottom is part of a process that includes drilling after going on-bottom to further extend the borehole. This approach can help optimize the autopilot's operation, optionally without relying on manually recorded lengths (e.g., measured depths), which may be for bit depth or borehole depth (e.g., as measured depths).

[0107] As an example, for one or more purposes, a driller may manually track bit depth and borehole depth, while an autopilot utilizes automated methods to travel to the bottom, for example, to help ensure that the autopilot can return the bit to the same point in the borehole (e.g., the bottom point) after operating from inside to outside the slips. This could be for adding tubing to the drill string to perform further drilling to extend the borehole. As an example, data acquired via the autopilot for this purpose may optionally be used by the driller, for example, to evaluate manually measured bit depth, manually measured borehole depth (HD), etc.

[0108] Pulley position data can be of a relatively reliable type because the pulley position may be limited, for example, due to equipment and / or safety concerns. For example, a lower limit position for the pulley position can be set relative to the drill rig, while an upper limit position for the pulley position can be set relative to equipment located at or near the top of the drill rig. As explained, for the purposes of automatic driller control, slip status can be used in conjunction with pulley position, for example, it can be used in a manner isolated from drill bit depth and hole depth (HD), such as those determined manually.

[0109] Regarding the chuck position, one approach could include determining how many segments of tubing have been added to the drill string by utilizing pulley position data. In this approach, a segment of tubing can be used to determine how to return to the bottom, which could include positioning the drill bit back to the bottom (e.g., in the bottom position). As for the "how," consider an autopilot that can control one or more of various parameters, such as speed, acceleration, deceleration, rotation, etc. For example, as the drill bit approaches the bottom, it can rotate, and its speed can be controlled to approach the desired rate of advance (ROP) to drill into the formation and extend the borehole. In such an example, the ROP could be the ROP determined for the previous segment of tubing, which could be the actual ROP; note that because the materials in the formation may differ (e.g., lithology, composition, etc.), a different ROP than the previous segment of tubing could be used.

[0110] As an example, one approach could include determining when the drill bit has returned to the bottom position, which could be achieved using an autopilot. In such an example, the actual bottom position length could be compared to an estimated bottom position length, where the estimated bottom position length is determined using data from the slip position and pulley position during the period immediately following the previous slip-in to slip-out time (e.g., after drilling a section of tubing, based on a previous bottom position signal).

[0111] Referring again to method 600, regarding operation 610, the completion of the stand X can be due to the position of trolley 603 reaching a lower limit position, for example, a lower limit position at a distance from drill rig 604. At the completion of stand X, the driller can then control trolley 603 such that its position is changed by rising towards the top of drill rig 601, which pulls the drill bit of the bottom drill string assembly 606 from the bottom. Such a point, the start of lifting trolley 603, can be detected, for example, as a transition point from downward movement or a rest point to upward movement. As explained, as the drill bit is lifted away from the bottom, method 600 can proceed to operation 620, which is performed by utilizing slips 605 inside the slips (e.g., in the slips state). As explained, the method can include determining the trolley position of the trolley in the slips state and determining the trolley position proceeding to outside the slips (e.g., outside the slips state), where the difference between the two positions can approximate a section of pipe added to the drill string. This approach may be more robust for automated driller control compared to relying on manually measured and recorded lengths.

[0112] As an example, one approach could include combining a section of tubing based on the spool position with the spool position for the drill bit leaving the bottom, where the spool position for the drill bit at the bottom can be considered a reference position (e.g., zero), to return the drill bit to the bottom using the determined spool position. This approach could be repeated for a section of tubing added to the drill string without the cumulative errors that might occur in manually tabulated drill bit depth and / or hole depth measurements. As an example, for a given null value as a reference, one approach could utilize two values ​​to determine a third value, where the third value is used to appropriately control travel at the bottom. As an example, the completion spool position for a section of tubing added could also be estimated.

[0113] Regarding pulling the drill bit away from the bottom of the drill string, it can be assumed that the drill string has a relatively fixed length, such that the distance pulled away from the bottom can represent the distance the drill bit returns to the bottom after a section of tubing is added to the drill string, where the time to add a section of tubing may be on the order of several minutes (e.g., less than about 20 minutes, etc.).

[0114] As explained, one method can determine a trolley position that an auto-driller can use to return the drill bit of the drill string to the bottom. Such a trolley position can be tracked and used to control devices (e.g., winches) positioning the trolley. As an example, the auto-driller is operatively coupled to one or more sensors, detectors, etc., and to a winch to return the drill bit of the drill string coupled to the trolley to the bottom of the borehole. As an example, one method may include determining how far from the bottom and when at the bottom. In such an example, "bottom" can be a relative bottom position, which can be relative to one or more operations that can be cyclical (e.g., pipe-by-pipe, column-by-column, etc.).

[0115] As an example, one approach could include receiving two data channels, one for the slip state and the other for the pulley position. This approach could include determining the pulley position corresponding to a bottom position used to move the drill bit to the bottom of the borehole. As explained, this approach eliminates the need for manual tabulation.

[0116] As explained, various types of automated systems (e.g., automated drillers, etc.) can be designed to help drilling operations achieve gains at significantly faster drilling rates. For example, an automated system can provide automation in a slip-to-slip manner, where automation begins when the drill string comes to a slip (e.g., reaching the bottom). Drilling operations with automated systems can be viewed as "slip-to-slip". As explained, drilling operations may include leaving the bottom, working tubing, circulating, calculating friction in the drill string (e.g., once or twice, etc.), and then returning to the stand-up position.

[0117] For bottom travel, the trolley can move at a specific speed (rate) to approach the bottom, and then reduce its speed (rate) at a certain distance from the bottom, for example, to achieve a proper landing of the drill bit on the bottom, as previously described, which may correspond to the rate of penetration (ROP). For the first speed, consider moving approximately 10 feet (ft) from the bottom and using a speed of approximately X feet per hour (e.g., consider approximately 150 ft per hour or approximately 2.5 ft per minute, so moving 8 feet would take approximately 3.2 minutes) until approximately 2 feet from the bottom and transitioning to a second speed less than the first speed; this might be an approximate expected ROP (e.g., requiring more than approximately 0.8 minutes to land). In such an example, the speed (e.g., maximum speed, etc.) can be limited due to one or more reasons (e.g., safety, equipment integrity, etc.). As explained, the speed, which can be the landing speed, can be controlled more precisely regarding when to implement that speed using automated methods including the use of slip states and trolley positions. As previously described, the landing speed can be the expected ROP. Prior to landing, the speed may be higher, which helps optimize drilling (e.g., less non-productive time, NPT). As explained, a "soft" landing can optimize the contact between the drill bit and the rock, and if drilling a section or more of the borehole is done in a fairly consistent manner, drill bit life can be extended, formation damage (e.g., borehole wall damage, etc.) can be reduced, which can help optimize drilling, facilitate estimation of equipment usage, drilling time, etc. As mentioned above, using an autopilot that uses slip status and pulley position for landing the drill bit can result in more consistent drilling.

[0118] As an example, an autopilot can operate in a way that enhances the driller's trust. For instance, a driller can gain trust in an autopilot if it can perform landings in a relatively consistent manner without unintentionally getting the drill bit stuck in the rock. Furthermore, as mentioned, an autopilot can provide data in tables that can help the driller assess one or more of the drill bit depth and hole depth.

[0119] Figure 7An example graphical user interface (GUI) 700 is shown, which includes a data channel acquired over a time period from approximately 17:00 to approximately 17:27, a period of approximately 27 minutes (e.g., slightly less than half an hour). In the example shown, various positions of the trolley (e.g., the BPOS channel) are indicated relative to the slips (e.g., the slip status channel) and the bottom of the drill bit and hole. As shown, when the drill bit is lifted from the bottom, the trolley position is at 0 feet (approximately 17:07:30), which may be a relative reference position (e.g., the zero position of the method); when operating inside the slips (e.g., slip in state), the trolley position is at 1.5 feet (approximately 17:12:45); when operating outside the slips, the trolley position is at 97.4 feet (approximately 17:18); and when operating to bring the drill bit back to the bottom, the trolley position is at 95.9 feet (17:20:45). Therefore, the slip-in time runs from approximately 17:12:45 to 17:18:00, approximately 5 minutes and 15 seconds. During the slip-in time period (e.g., slip-in state), the operation can exit automatic drilling mode. For example, the operation can be in manual or semi-automatic mode under the control of the tubing handling system. As an example, the operation may include two separate operating modes: one is an automatic drilling mode running slip-to-slip, and the other is a tubing handling mode. As described above, a method may include operating an automation system (e.g., an autopilot) during the slip-in time period, for example, to obtain data for one or more automated drilling operations controlled by the automation system.

[0120] like Figure 7As shown, various events are labeled A through J. Event A corresponds to the end of drilling when the sled is at 0.0 feet on the drill string. Events B and C can be related and suitable for pulling the drill string upwards while rotating, which can occur simultaneously with a decrease in flow and pressure (e.g., stopping circulation). When inside the slips, the sled is at 1.5 feet, and the hook load decreases due to the weight of the drill string supported by the slips. Event D can correspond to a rotation that can be actuated to disengage coupling equipment (e.g., consider disengaging the drive, etc.). Event E corresponds to raising the sled position so that the drill string can be added to the drill string, as shown in Event F. Event G can correspond to a rotation that can be actuated to engage coupling equipment (e.g., consider drive engagement, drill string-to-drill string engagement, etc.). Event H corresponds to a change in hook load when the drill string comes out of the slips, where the sled is at 97.4 feet. As described above, when the drill bit reaches the outside of the slips, it is not at the bottom; instead, it is at a distance from the bottom, which may be approximately 1.5 feet, as determined by the difference between the 0.0-foot (outside the bottom) pulley position and the 1.5-foot (inside the slips) pulley position. Before reaching the bottom, as shown in Event I, as circulation (see, for example, flow and pressure) begins to rotate, the pulley position decreases as shown in Event J, at which point the rotating drill bit engages the bottom (see 95.9-foot pulley position) to continue drilling a distance approximately equal to the increase in stand length during the slip period.

[0121] As explained, automated drilling modes can depend on a manually determined distance to the bottom. As an example, one approach could include automatically determining the distance to the bottom using the spool position. This approach can provide the drill bit's position at the bottom calculated from the spool position. In this approach, during a previous passive period of the autopilot (e.g., a kavan phase), the autopilot can be activated by tracking the spool position, where this tracking can be used to determine one or more distances to accurately return the drill bit to the bottom for drilling. This approach can help reduce the risk of the drill bit getting stuck at the bottom of the borehole due to inaccurate distances (e.g., due to human inaccuracy, human error, etc.).

[0122] As an example, one approach could include a graphical user interface (GUI) that presents an automatically determined distance to a display where the driller can calculate a manually determined distance for comparison. In this approach, the driller may have the option to select one distance and / or determine another distance value. For example, if the manually determined distance is greater than the automatically determined distance, a shorter automatically determined distance can be used because it provides some assurance that the drill bit will not get stuck at the bottom of the hole after reaching the slips; however, if the manually determined distance is less than the automatically determined distance, the driller can use the manually determined distance to instruct the autopilot to return the drill bit to the bottom of the hole. In such an example, there may be some degree of error in the distance the drill bit is moved before engaging the bottom of the hole; however, such a distance can be traversed as the drill string moves at an approximately, expected drilling rate, resulting in a relatively smooth engagement, which can maintain drill bit life (e.g., drill bit integrity).

[0123] As an example, one approach could include determining two distances and selecting the smaller one for use by the automated driller to return the drill bit to the bottom of the hole after adding a section of tubing (e.g., or multiple sections of tubing, etc.).

[0124] Regarding manual methods for determining the distance at the bottom, it can be determined by the drill bit depth and hole depth, for example, as manually recorded using a ledger (e.g., pen and paper, spreadsheet, etc.). In this method, information can be verbally communicated (e.g., one person calls out the tube measurement, etc.) and recorded in a way that is most understandable to the audience. In this method, rounding of fractions, decimals, etc., may occur, which can be subjective. In manual methods, the driller may attempt to manipulate the values ​​to make a matching tube count exist. As explained, inaccurate bottom states during automation can lead to drill bit damage and / or undesirable wear (e.g., wear exceeding expected wear, etc.). In automated methods, the existence of a distance can be determined independently of the hole and drill bit depth, where the trolley position is used instead, which is more robust because the trolley position can be an automatically acquired data channel that is rarely manipulated. The trolley position can be used to calculate the bottom state in a way that isolates the bottom state from drill bit and / or hole depth operations.

[0125] Systems that automatically reach the bottom can benefit from accurate estimations of where the bottom is, reducing the risk of drill bit damage and / or excessive wear. If the bottom is higher than it actually is, such an automated system might continue operating at high speed upon reaching the bottom, damaging the drill bit; however, if the bottom is lower than the actual position, such an automated system might attempt to apply weight to the drill bit and increase its speed, assuming it is at the bottom. As mentioned earlier, a bottom higher than the actual value can damage the drill bit, especially if the reading is consistently higher, causing the drill bit to be repeatedly subjected to inappropriate speeds and rock contact.

[0126] Regarding the pulley position, drilling site equipment can generate a pulley position channel, which may be referred to as the BPOS, defined around a dead point (e.g., zero point) and can have deviations from the dead point in positive and / or negative directions. For example, consider a pulley that can move within a range of approximately -5 meters to +45 meters, with a total travel of approximately 50 meters. In such an example, the rig height can be greater than approximately 50 meters (e.g., the overhead crane can be positioned at a height exceeding approximately 50 meters above the ground or the rig floor). Figure 7 In the example GUI 700, the BPOS channel is given along a scale (horizontal axis) from -10 feet to +120 feet relative to time (vertical axis), totaling 130 feet (e.g., approximately 40 meters). This range of the BPOS channel can be within a physically constrained pulley range, operable to connect pipes of lengths such as 90 feet, 30 meters, etc. (e.g., shorter or slightly longer). While various examples are given for land-based field operations (e.g., stationary, truck-based, etc.), various methods can be applied to offshore operations (e.g., ship-based drilling rigs, platform drilling rigs, etc.).

[0127] exist Figure 7 In the examples, other channels include maximum hook load (HKLD) in the range of 0 to 250 klbs, rotational speed (RPM) in the range of 0 to 100 rpm, torque in the range of 0 to 25 kft-lbs, flow rate in the range of 0 to 1000 gallons per minute, and pressure in the range of 0 to 4000 pounds per square inch (psi). As an example, drilling operations may include one or more adjustments to the equipment, resulting in one or more variations in one or more of these physical parameters.

[0128] Figure 8 An example of a method 800 for performing drilling operations using drilling equipment is shown. As shown, the drilling equipment includes a drilling rig 801, a hoisting system 802, a trolley 803, a platform 804, slips 805, and a bottom drill string assembly 806. As shown, the drilling rig 801 supports the hoisting system 802, which is provided in the trolley 803 above the platform 804. The slips 805 are used to support a drill string including the bottom drill string assembly 806, which is shown to include a drill bit for drilling into the formation to form a borehole.

[0129] Regarding drilling operations, these include a first operation 810 of completing the drill string stand (stand X); a second operation 820 of pulling the drill string away from the bottom of the borehole by moving the trolley 803 upward and supporting the drill string in the platform 804 using slips 805; a third operation 830 of adding a stand (stand X+1) to the drill string; and a fourth operation 840 of removing the slips 805 and lowering the drill string to the bottom of the borehole by moving the trolley 803 downward. See also... Figure 1 , 2 Sections 3, 4, and 5 explain various details of the device examples and operation examples.

[0130] exist Figure 8 In Example Method 800, thick horizontal lines BP(1), BP(2), BP(3) and BP(4) are used to indicate various trolley positions. Figure 8 An example of an automated drilling system 860 that can receive input 850 and provide output 870 is also shown, which may include, for example Figure 7 The example GUI 700 shows various outputs. As shown, input 850 may include receiving trolley position data and / or relationships (e.g., the position of trolley 803 in method 800), which can be tagged (e.g., using kava status, timestamps, etc.). (See above regarding...) Figure 7 As explained in GUI 700, when the drill bit is lifted off the bottom, the trolley position is at 0 feet (approximately 17:07:30), as shown by BP(1) = 0.0 in output 870, which can be a relative reference position (e.g., the empty position of the method); when the operation is in the slips (e.g., in the slip state), the trolley position is at 1.5 feet (approximately 17:12:45), as shown by BP(2) = 1.5 in output 870; when the operation comes out of the slips, the trolley position is at 97.4 feet (approximately 17:18), as shown by BP(3) = 97.4 in output 870; and when the operation brings the drill bit back to the bottom, the trolley position is at 95.9 feet (17:20:45), as shown by BP(4) = 95.9 in output 870.

[0131] like Figure 8 As illustrated in the examples, automated drilling systems (e.g., automated drillers) can operate using jack position and slip status to improve drilling operations. As explained, such automated drilling systems can output a bit-on-bottom state, which can be an improved bit-on-bottom state that can improve drilling operations (e.g., via one or more of a lower risk of damage, less wear, greater ROP, and lower NPT).

[0132] Figure 9 An example of method 900 for a chart is shown, which can be numbered using chart numbers (e.g., manually, etc.). Figure 9 In the example, the chart could be a drilling recorder or a drilling recorder chart. As mentioned, a drilling recorder can be used for purposes such as calculating the rate of progress (ROP), for example, by measuring the length of time it takes to drill 1 foot to a depth, which can be done by reading a chart on the drilling recorder (e.g., a drilling recorder chart).

[0133] The drilling recorder mechanically monitors depth and records drilling parameters in real time. These parameters are recorded on paper charts, calibrated in minutes, and wound around a drum. The drum rotates once every 8, 12, or 24 hours. To record depth, a small cable extends from the drilling recorder to the top of the kelly via pulleys on the derrick (see, for example, see...). Figure 2 Then the height of the jib can be measured and directly correlated with the drill bit depth. For every foot drilled, an ink pen on the drill recorder leaves a small mark on the chart. In this method, every 5 feet, the pen places a larger mark on the chart.

[0134] Operation of the drilling recorder can introduce errors. For example, when establishing a connection, the driller may be instructed to disengage from the drilling recorder before picking up a new connector. When drilling resumes, the recorder will restart. Unless this is done correctly, the drilling rate before or after the connection may be problematic. Furthermore, strong winds can blow the drilling recorder's recording cable, causing additional footage to be recorded, which can lead to a significant increase in ROP. Additionally, similarly significant increases in ROP can occur when the driller or other operators place their hands on the "gig" or pull the recording cable.

[0135] One or more other sources of error may include hole filling, tube stretching, tube jamming, etc., where subjective efforts can be made to "back out" one or more of these errors, with the aim of maintaining a more accurate depth record (e.g., the measured depth). Depth can be checked periodically by stripping the drill string from the hole (each string is measured with a steel strip when pulled out of the hole or tripped out) and the drill recorder can be adjusted for depth. However, such a process can be time-consuming (e.g., generating NPTs), resource-intensive, and still contains a significant amount of error.

[0136] Figure 10 An example of system 1000 is shown, which includes one or more interfaces 1020, a bottom-traveling controller 1040, and one or more other components 1060. System 1000 is operable to receive slip status and trolley position data via one or more interfaces 1020, in which the bottom-traveling controller 1040 can control the bottom-traveling process of placing the drill bit of the drill string on the bottom of the borehole.

[0137] As an example, system 1000 may be included and / or operatively connected to, for example, Figure 2 System 200 Figure 3 System 300 Figure 4 System 400 Figure 8 In the system 860, as an example, system 1000 can be operatively connected to one or more GUIs, such as... Figure 5 The GUI 500 can present one or more of the pulley position, slip state, and bottom state, and optionally a representation of the borehole trajectory that may include a representation of the drill string including the BHA.

[0138] As an example, system 1000 may operate using one or more application programming interfaces (APIs), where calls and responses can be made, for example. For instance, the controller may issue one or more calls to pulley position data, slip status, etc., where, in response, such data and / or status may be returned. In such an example, using the returned data and / or status, the controller may control the position of the drill string relative to time to bring the drill bit to a landing position. In such an example, where the controller can receive and / or determine the drilling rate, the drilling rate can be used to control the speed of the drill bit, which can provide a “soft” landing designed to optimize one or more drilling aspects (e.g., reducing NPT, reducing drill bit wear, etc.). As an example, one or more other components 1060 may include one or more components for controlling one or more other types of drilling rig field equipment (e.g., slips, pumps, top drive, rotary table (drilling aspects such as reducing NPT, reducing drill bit wear, etc.)). As an example, the bottom-traveling controller 1040 may be operatively coupled to a winch and / or one or more other drilling rig field equipment.

[0139] Regarding the sled position, one or more sensors can be used to acquire sled position data, such as the values ​​of BP(1), BP(2), and BP(3), where BP(4) can be calculated using BP(1), BP(2), and BP(3). For example, consider... Figure 8 The output is 870, which can be referenced. Figure 8 Method 800 and Figure 7 We can understand it using GUI 700.

[0140] As explained, in drilling operations, the length of the drill string can be manually tracked using counting methods (e.g., pen and paper, spreadsheets, etc.). As explained, when the driller tabulates the drill string length and uses that length as a representation of the bottom depth of the borehole, if any value is inaccurate (e.g., not properly tracked), the driller or autopilot may push the drill string into the rock at an accelerated rate because they may not realize they are approaching the bottom of the hole, which could lead to serious equipment damage and operational problems.

[0141] In various situations, an encoder at the drilling rig winch is used to measure the drill string length. As explained, the winch can be a winch that controls the raising and lowering of a chuck, adjusting the height of the top drive or kelly and the drill string attached thereto. The encoder can be configured to record the number of revolutions of the winch drum, where the number of revolutions is used to determine the distance the chuck has been lowered. When the string is fully extended, the winch can be used to raise the chuck again, and this process can be repeated. Winch encoder measurements can have various types of errors. For example, consider errors caused by the radius of the drill string relative to the center of the winch, the drill string stretch under hook load (which itself may fluctuate, for example, due to downhole pressure, etc.). In some cases, a drill recorder cable is used to calibrate the winch encoder. The drill recorder cable is a cable directly attached to the top drive, kelly, or chuck. Cable retrieval systems and coded sensors can be provided for the cable, both of which can be connected to a fixed point on or near the rig. The drill recorder cable is then moved up and down on the rig, while the encoder measures the amount of cable being released or retrieved. However, measurements taken by the winch, even those calibrated by the drilling recorder line, may include errors, leading to uncertainty in depth measurements.

[0142] like Figure 2 As shown, the well site system 200 (e.g., a drilling rig site system or drilling site equipment) may include various sensors 264, which may be of the type of detectors, data acquisition sensors, etc., for the purpose of one or more of slip status and trolley position. As mentioned, trolley position data may be tracked via one or more cameras, one or more sensors, etc. Publication number US 2017 / 0167853 A1, published by Zheng et al. (Schlumberger Technology Corporation) on June 15, 2017, is incorporated herein by reference, and describes position measurement.

[0143] As an example, an optical sensor, such as that of a camera, can be configured to detect and distinguish markers, which may include both stationary and moving markers. As another example, the markers can be positioned at a predetermined height along the drilling rig's on-site system and can be located on pulleys, top drives, etc. In such an example, the height of the pulley can be determined (e.g., above the drilling rig).

[0144] As for the pulley position, it can be determined using equipment at the drilling rig's on-site system with a resolution of less than a few centimeters, which may be less than one inch. Regarding the sampling rate, sampling can be performed at a frequency greater than approximately 1 Hz (e.g., greater than once per second or at a rate of milliseconds).

[0145] As an example, a rangefinder method can be used to track the position of a trolley. For example, consider one or more rangefinders based on electromagnetic energy. As an example, the trolley, top drive, etc., may include a reflector that reflects EM radiation emitted by a laser, etc., where a detector can analyze the reflected EM radiation (e.g., and / or received EM radiation) to determine the trolley position. As an example, the trolley, top drive, etc., may include one or more lasers that can emit radiation toward one or more other components (e.g., upward, downward, etc.), where the transmitted and / or reflected energy can be analyzed to determine the trolley position.

[0146] Figure 11 Examples of method 1100 and system 1190 are shown. As shown, method 1100 may include a receiving block 1110 for receiving trolley position data of the drill string before adding a section of tubing to the drill string, wherein the drill string is at least partially disposed in the borehole and supported by the drill string; a receiving block 1120 for receiving trolley position data of the drill string after adding the section of tubing to the drill string; and a control block 1130 for controlling the position of the drill string relative to time using at least a portion of the drill string and trolley position data for landing the drill bit of the drill string at the bottom of the borehole.

[0147] Method 1100 is shown to include various computer-readable storage media (CRM) blocks 1111, 1121 and 1131, which may include processor-executable instructions that may instruct a computing system, which may be a control system, to perform one or more actions described in relation to method 3800.

[0148] exist Figure 11 In the example, system 1190 includes one or more information storage devices 1191, one or more computers 1192, one or more networks 1195, and instructions 1196. Regarding the one or more computers 1192, each computer may include one or more processors (e.g., processing cores) 1193 and memory 1194 for storing instructions 1196, which may be executed by at least one of the one or more processors 1193 (e.g., see boxes 1111, 1121, and 1131). As an example, the computer may include one or more network interfaces (e.g., wired or wireless), one or more graphics cards, display interfaces (e.g., wired or wireless), etc.

[0149] As an example, Figure 11 Method 1100 can be used to determine the state of the drill bit at the bottom using a limited amount of sensor data and / or data derived from one or more sensors. For example, consider using pulley position data and slip status to determine the state of the drill bit at the bottom without using other information.

[0150] As an example, compared to determining the drill bit's bottom position from a list of drill bits and hole depths from which the driller tends to adjust the depth at each connection (e.g., often with some considerable error) to match the pipe count, Figure 11 Method 1100 can be an improved technique. This method can result in indicating that the drill bit is at the bottom when the drill bit is actually some distance from the bottom. Assuming the drill bit is at the bottom, the drilling system will act to apply weight to the drill string for drilling, using the drill bit at the end of the drill string to crush the rock. In the case where the drill bit is not actually at the bottom, there is a distance between the drill bit and the bottom of the hole (e.g., formed of rock), such that applying weight to the drill string causes the drill string to accelerate over that distance, which accelerates the drill bit toward the actual bottom. As explained, the formation can be formed of rock that can have a certain hardness. Accelerating the drill bit over a distance by applying inappropriate weight to the drill string in response to an erroneous drill bit at the bottom will cause the drill bit to impact the rock with considerable force (e.g., F = ma) and momentum (e.g., p = mv). The distance between the drill bit and the bottom of the hole allows the drill string to accelerate and gain velocity. Therefore, a larger error in the drill bit being at the bottom results in greater force and momentum, which leads to a greater risk of drill bit damage and / or wear. While damage and / or wear to the drill bit are mentioned, impacting the drill bit at the bottom with considerable force and momentum can (e.g., directly and / or indirectly) increase damage and / or wear to one or more other components of the drill string and / or borehole. For example, the impact force and / or momentum can damage downhole motors, one or more downhole sensors, etc. In some cases, the drill string may bend. Such problems can result in substantial non-productive time (NPT), rescheduling, unplanned tripping (e.g., tripping to change the drill bit, etc., and then tripping), etc.

[0151] Another problem may arise from the driller's tendency to adjust the depth at each connection (e.g., often with some considerable error) to match the pipe count list of drill bits and hole depth. Determining the drill bit is the process of the drill bit being determined to be at the bottom state a certain distance from the actual bottom before it reaches that state (e.g., late determination of the drill bit being at the bottom). In this case, the drilling system may continue to run at the speed of reaching the bottom, effectively putting excessive weight on the drill bit and damaging and / or excessively wearing it.

[0152] As explained, such as, for example Figure 11Method 1100 can be an improved technique for helping to isolate one or more operations in such an operation from errors in the driller's operating depth. Operations can be improved by minimizing errors in the drill bit's state at the bottom. For example, less drill bit wear may occur, allowing at least a portion of a section to be drilled at a higher rate of approach (ROP) during drilling, where there is sufficient drill bit life (e.g., due to less drill bit wear). In such an example, drilling can be performed using methods such as Method 1100, where drill bit wear is reduced and drill bit life is maintained. Once a depth (e.g., measurement depth, number of drill strings, etc.) is reached, drilling can proceed with increased ROP because the risk of drill bit wear before reaching the end of that section is reduced. In such an example, a schedule may require running the drill string, for example, replacing at least a portion of the BHA (e.g., the drill bit, etc.) to prepare for drilling another section, which may be a smaller diameter borehole section (e.g., the section diameter may decrease progressively with increasing measurement depth).

[0153] As mentioned above, operations can include tripping in and out of the borehole, which can be referred to as a round trip. A round trip involves removing the drill string from the borehole and returning it to the hole. A round trip can be planned or requested in response to one or more types of problems. For example, consider requesting a round trip when the drill bit becomes dull or damaged and is no longer effectively drilling into the rock. After some initial preparations for tripping in, the drilling crew removes the drill string one string at a time (e.g., 90 feet or approximately 27 meters), for example, by loosening the joints every three drill pipes or drill collars. In such an example, as the three joints are unscrewed from the rest of the drill string, they can be stored upright in the derrick via the top finger plate and carefully placed on a wooden board on the rig. Once the drill string has been removed from the borehole, a drill bit remover can be used to unscrew the dull drill bit and inspect it to help determine the cause of the dulling or failure. Depending on the failure mechanism, the crew may select a different type of drill bit before running it in. If the bearing on the previous drill bit fails, but the cutting edge is still sharp and intact, the operator may opt for a faster (less durable) cutting edge. Conversely, if the drill bit teeth are worn, but the bearing is still sealed and functioning properly, the operator may choose a drill bit with a more durable (and less aggressive) cutting edge. Once the drill bit is selected, it is screwed to the bottom of the BHA with the help of a drill bit remover, and the drill string is inserted into the hole (RIH), reassembled one string at a time. Once the bottom condition is confirmed, drilling can begin. The duration of this trip-in-the-hole cycle can depend on various factors, such as the total depth of the well and the skill of the driller. An estimate for a skilled operator is one hour per kilometer of borehole, plus one or two hours handling the various drill string components (e.g., drill collars and drill bit). At this rate, a trip-in-the-hole cycle in a 10,000-foot well could take twelve hours. A single trip to and from a 30,000-foot (e.g., 9,230-meter) well can take 32 hours or more, especially if intermediate hole cleaning operations are required.

[0154] As explained, such as Figure 11 Method 1100 can improve operations. For example, this method can improve operations by reducing the risk of having to perform an unplanned trip-in and / or having to perform a planned trip-in ahead of schedule, which could affect the remainder of the schedule (e.g., regarding one or more sections still to be drilled).

[0155] Figure 12An example of system 1200 is shown, which can be a well construction ecosystem. As shown, system 1200 may include one or more instances of system 1000 and may include drilling rig infrastructure 1210 and drilling planning component 1220, which may generate or otherwise transmit information associated with plans to be performed using drilling rig infrastructure 1210, for example via drilling operations layer 1240 including well site component 1242 and off-site component 1244. As shown, data acquired and / or generated by drilling operations layer 1240 may be transmitted to data archiving component 1250, which may be used, for example, for the purpose of planning one or more operations (e.g., according to drilling planning component 1220).

[0156] As mentioned, data acquired for the purpose of bottoming out can be used for one or more other purposes, which may include, for example, evaluating data regarding the measured drill bit depth, data regarding the measured hole depth (HD), etc. In such an example, one or more aspects of the digital well plan and / or the autopilot may be adjusted. For example, in the event of mismatches in various depth (e.g., length) data, a coordination process may be performed, which may include requesting exploration (e.g., downhole exploration), which can improve the ability to accurately locate the bottom of the drill string assembly (BHA). As an example, the autopilot (e.g., a system such as System 1000) may include features that can determine whether exploration used to acquire exploration data could improve drilling operations.

[0157] exist Figure 12 In the example, system 1000 is shown as being implemented for drilling planning component 1220, well site component 1242, and / or off-site component 1244. For example... Figure 12 As shown, various components of the drilling operation layer 1240 can utilize the system 1000. During drilling, execution data that can be used by the system 1000 can be acquired. Such execution data can be archived in a data archiving component 1250, which can archive data during one or more drilling operations and can be obtained by the drilling planning component 1220, for example, for rescheduling.

[0158] As previously mentioned, drilling can increase the depth of the hole. As an example, during non-drilling periods (e.g., non-drilling states), the flow rate of fluid pumped into the drill string can be increased and / or decreased, the rotational speed of the drill string can be increased and / or decreased, the drill bit can be moved up and / or down, or a combination thereof.

[0159] As an example, pre-connection can refer to a state where the drill bit has completed drilling operations on the current section of the tubing, etc., but the slip assembly has not yet begun to move (e.g., radially inward) to engage with the drill string. During pre-connection, the flow rate of fluid pumped into the drill string may increase and / or decrease, the rotational speed of the drill string may increase and / or decrease, the drill bit may move up and / or down, or a combination thereof.

[0160] As an example, a connection can refer to the state in which the slip assembly engages with and supports the drill string (e.g., the drill string is "in-slip"). When a connection occurs, a section (e.g., pipe, stand, etc.) can be added to the drill string to increase its length, or a section can be removed from the drill string to reduce its length.

[0161] As an example, post-connection can refer to the state where the slip assembly releases the drill string, and the drill string with the drill bit descends to the bottom (e.g., bottom of the well or BOH). During post-connection, the flow rate of fluid pumped into the drill string can increase and / or decrease, the drill string rotation rate can increase and / or decrease, the drill bit can move up and / or down, or a combination thereof.

[0162] As described above, a section of pipe can be a column, which can be, for example, about 90 feet or about 30 meters (e.g., about 27 meters), and is formed by individual pipes connected together to form the column. As an example, a section of pipe can be greater than about 5 meters and less than about 100 meters.

[0163] As an example, a method may include receiving trolley position data of the drill string before adding a section of tubing to the drill string, wherein the drill string is at least partially positioned in the borehole and supported by the drill string; receiving trolley position data of the drill string after adding the section of tubing to the drill string; and using at least a portion of the drill string and trolley position data to control the position of the drill string relative to time to land the drill bit of the drill string at the bottom of the borehole. In such an example, the method may include receiving a signal indicating a slip state of the slips, which supports the drill string during a slip-in state.

[0164] As an example, one method may include controlling the position of the drill string relative to time by controlling the speed of the drill string in the hole direction based at least in part on a calculated distance between the drill bit and the bottom of the borehole, wherein the calculated distance is based at least in part on at least a portion of zone position data, which may include trolley position data before a section of pipe is added to the drill string and trolley position data after a section of pipe is added to the drill string.

[0165] As an example, one approach could include implementing an automated driller as a computerized drilling system capable of issuing instructions in an automated manner for various drilling operations, such as for travel at the bottom after a section of tubing has been added to the drill string. Such a computerized drilling system could include one or more processors, memory accessible to them, and processor-executable instructions to instruct the equipment to perform one or more automated drilling operations and, for example, acquire closely related data (e.g., slip status, pulley position data, etc.).

[0166] As an example, trolley position data can be received by an autopilot, which performs control over the position of the drill string relative to time. As mentioned, control can include controlling position, controlling acceleration, controlling direction, controlling speed, etc. As explained, control can include reducing the drill bit speed along the borehole length based at least in part on the distance of the drill bit from the bottom of the borehole, said distance being a calculated distance based on trolley position data, which may be or includes trolley position data acquired before the speed reduction. As an example, the reduced speed can be approximately equal to the drilling rate, which can be an estimated drilling rate, a received drilling rate, etc. As for the distance that can be the trigger for the speed reduction, such a distance can be a portion of a larger distance, a percentage of a larger distance, a predetermined distance, etc., which can provide time to reduce the speed and optionally provide a safety margin. For example, a safety margin can cause the speed to be reduced to at least a predetermined distance from the bottom of the borehole, based on the distance relative to the bottom of the borehole determined using pulley position data. This reduces the risk that the drill bit will get stuck in the formation at a speed greater than the reduced speed if there is an error in the determined distance relative to the bottom of the borehole. This may result in a slightly longer time to reach the bottom of the borehole, while also maintaining the lifespan of the drill bit as a trade-off.

[0167] As an example, one approach could include controlling bottom travel in a manner that does not use manually measured bit depth values, manually measured hole depth (HD) values, and / or neither manually measured bit depth values ​​nor manually measured hole depth (HD) values. As an example, bottom travel can be performed automatically without human intervention. For instance, an autopilot could use pulley position data acquired for slip conditions to determine the distance from the drill bit to the bottom of the borehole, and could control the drill bit's position relative to time based at least in part on that distance, for example, by landing the drill bit while it is rotating to continue drilling in a manner that extends the borehole, thereby creating a new bottom position after drilling (e.g., for a section of tubing, etc.).

[0168] As an example, a pipe segment can be a column segment; for instance, a column segment can be multiple pipes connected together.

[0169] As an example, the trolley position data may include a reference trolley position value (BP(1)), a trolley position value away from the bottom (BP(2)), and a trolley position value with a section of tubing added inside the slips (BP(3)). In such an example, the method may include controlling the position of the drill string in the borehole by moving the drill string to the bottom of the borehole by a distance corresponding to a trolley position (BP(4)) determined by subtracting the trolley position value away from the bottom (BP(2)) from the trolley position value with a section of tubing added inside the slips (BP(3)). As previously mentioned, the reference trolley position value (e.g., BP(1)) may be an empty position; note that the trolley position acquisition system may also utilize empty positions where some trolley position values ​​are positive and some are negative. For example, in Figure 7 In the example, the trolley position channel data is given in feet, ranging from -10 feet to +120 feet, which means there is a zero point (e.g., a dead point). As an example, the zero point of the scale and the reference point can be different. For example, the reference point (e.g., BP(1)) may be different from the zero point of the BPOS channel scale. In such an example, the scale and / or scale values ​​can be adjusted to determine the trolley position (e.g., BP(4) etc.).

[0170] As an example, a method may include receiving a drilling rate and controlling the position of the drill string relative to time, at least in part based on the drilling rate. As an example, a method may include determining a drilling rate and controlling the position of the drill string relative to time, at least in part based on the drilling rate.

[0171] As an example, before adding a section of tubing to the drill string, the rig's sled position data may include position data for the drill string in its bottom state prior to its slip state within the drill string. For instance, the sled position in the bottom state may correspond to the deepest bit position along the borehole, where, assuming the bit is in contact with the formation and, for example, the sled (e.g., or other traveling device) is at or near the lower limit relative to the rig, such that further drilling is prohibited without adding a section of tubing to the drill string. As explained, this involves raising the sled to provide space (e.g., axial space) to connect a section of tubing to the drill string.

[0172] As an example, before adding a section of tubing to the drill string, the rig's jack position data can be acquired in response to the actuation of a bottom-state actuator. Consider, for example, a manually actuated bottom-state actuator (e.g., a button, etc.). As an example, in response to the actuation of the bottom-state actuator, a method can be initiated that acquires jack position data for non-drilling activities involving adding a section of tubing to the drill string, where the jack position data can be used to return the drill bit to the bottom of the borehole to continue drilling activities that deepen (e.g., lengthen) the borehole.

[0173] As an example, the rig's pulley position data after a section of tubing is added to the drill string can be used for the slip-in state, where, for example, one approach could include transitioning the rig from the slip-in state to the slip-out state before controlling the position of the drill string relative to time.

[0174] As an example, a method may include controlling the slips of a drilling rig and controlling the position of the drill string using the drilling rig, wherein controlling the position may include controlling the position relative to time to move the drill string outward and / or controlling the position relative to time to move the drill string inward. As mentioned, a method may include pulling the drill bit away from the bottom before transitioning to an inside slip state, and transitioning from an inside slip state to an outside slip state before controlling the position of the drill string relative to time to land the drill bit at the bottom (e.g., at the bottom of the well). As an example, a method may include controlling the slips of a drilling rig via a first transition from an outside slip state to an inside slip state and a second transition from an inside slip state to an outside slip state, wherein at least a portion of the sluice box position data is obtained in the outside slip state, and wherein at least a portion of the sluice box position data is obtained in the inside slip state. In such an example, in order to control the position of the drill string using the drilling rig, the distance traveled at the bottom from the second transition in the outside slip state can be determined.

[0175] As explained, various operations at the drilling rig site can be periodic (see, for example, Figure 9 The drilling recorder chart. As mentioned above, one approach can be periodic, repeating in a state-based manner. For example, consider drilling states, non-drilling states, slip states, data acquisition states, etc., which can form a cycle, where each cycle can include bottom travel. As explained, the method for bottom travel can be relative to a cycle such that bottom travel in that cycle is independent of the jack position data of the previous cycle; note that in some cases, jack position data of the previous cycle can be utilized (e.g., for analysis, evaluation, drilling rate determination, etc.).

[0176] As an example, the system may include a processor; processor-accessible memory; processor-executable instructions stored in the memory and executable to instruct the system to: receive trolley position data of the drill string before adding a section of tubing to the drill string, wherein the drill string is at least partially positioned in the borehole and supported by the drill string; receive trolley position data of the drill string after adding the section of tubing to the drill string; and use at least a portion of the drill string and trolley position data to control the position of the drill string relative to time to land the drill bit of the drill string at the bottom of the borehole.

[0177] As an example, one or more computer-readable storage media may include processor-executable instructions to instruct a computing system to: receive trolley position data of a drill string before adding a section of tubing to the drill string, wherein the drill string is at least partially positioned in the borehole and supported by the drill string; receive trolley position data of the drill string after adding the section of tubing to the drill string; and use at least a portion of the drill string and trolley position data to control the position of the drill string relative to time to land the drill bit of the drill string at the bottom of the borehole.

[0178] As an example, one or more computer-readable storage media may include processor-executable instructions for instructing a computing system to perform one or more methods. As an example, a computer program product may include executable instructions that can be executed by a computing system to perform one or more methods. As an example, a computer program product may be run using a computer or computing system, wherein such operation produces technical results, such as notifications, control commands, etc., which can be directly and / or indirectly used to control one or more drilling operations. For example, consider a drilling operation in which a drill bit of a drill string is landed at the bottom of a borehole using a drilling rig system (e.g., a well site system).

[0179] As an example, a method may be implemented in part using a computer-readable medium (CRM), for example, as a module, frame, etc., which includes information such as instructions suitable for execution by one or more processors (or processor cores) to instruct a computing device or system to perform one or more actions. As an example, a single medium may be configured with instructions to at least partially allow the execution of various actions of the method. As an example, the computer-readable medium (CRM) may be a non-carrier computer-readable storage medium (e.g., a non-transient medium).

[0180] According to one embodiment, one or more computer-readable media may include computer-executable instructions to instruct a computing system to output information for controlling a process. For example, such instructions may provide outputs for sensing processes, injection processes, drilling processes, extraction processes, extrusion processes, pumping processes, heating processes, etc.

[0181] In some embodiments, the computing system may perform one or more methods. Figure 13 An example of a system 1300 is shown that may include one or more computing systems 1301-1, 1301-2, 1301-3, and 1301-4, which may be operatively connected via one or more networks 1309, which may include wired and / or wireless networks.

[0182] As an example, the system may include a standalone computer system or an arrangement of distributed computer systems. Figure 13In the example, computer system 1301-1 may include one or more modules 1302, which may be or include processor-executable instructions, for example, executable to perform various tasks (e.g., receiving information, requesting information, processing information, simulating, outputting information, controlling, etc.).

[0183] As an example, the module may execute independently or in coordination with one or more processors 1304, which are operatively connected to one or more storage media 1306 (e.g., via wired, wireless, etc.). As an example, one or more of the processors 1304 may be operatively connected to at least one of one or more network interfaces 1307. In such an example, the computer system 1301-1 may send and / or receive information, for example, via one or more networks 1309 (e.g., consider one or more of the Internet, private networks, cellular networks, satellite networks, etc.).

[0184] As an example, computer system 1301-1 may receive information from one or more other devices and / or send information to one or more other devices, which may be, for example, one or more computer systems 1301-2, etc. The devices may be located in a physical location different from that of computer system 1301-1. As an example, the location may be, for example, a processing facility location, a data center location (e.g., a server farm), a drilling rig location, a well site location, a downhole location, etc.

[0185] As an example, a processor may be or include a microprocessor, a microcontroller, a processor module or subsystem, a programmable integrated circuit, a programmable gate array, or other control or computing device.

[0186] As an example, storage medium 1306 may be implemented as one or more computer-readable or machine-readable storage media. As an example, storage may be distributed within and / or between multiple internal and / or external chassis of the computing system and / or additional computing systems.

[0187] As an example, one or more storage media may include one or more different forms of memory, including semiconductor storage 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, disks such as fixed disks, floppy disks and removable disks, other magnetic media including magnetic tape, optical media such as optical discs (CDs) or digital video discs (DVDs), Blu-ray discs or other types of optical storage, or other types of storage devices.

[0188] As an example, one or more storage media may be located in a machine that runs machine-readable instructions, or at a remote site where machine-readable instructions can be downloaded over a network for execution.

[0189] As an example, various components of a system, such as a computer system, may be implemented in hardware, software, or a combination of hardware and software (e.g., including firmware), including one or more signal processing and / or application-specific integrated circuits.

[0190] As an example, the system may include a processing device that may be or include a general-purpose processor or a special-purpose chip (e.g., a chipset), such as an ASIC, FPGA, PLD, or other suitable device.

[0191] Figure 14 Components of a computing system 1400 and a network system 1410 including a network 1420 are illustrated. System 1400 includes one or more processors 1402, memory and / or storage components 1404, one or more input and / or output devices 1406, and a bus 1408. According to one embodiment, instructions may be stored in one or more computer-readable media (e.g., memory / storage component 1404). Such instructions may be read by one or more processors (e.g., processor 1402) via a communication bus (e.g., bus 1408), which may be wired or wireless. One or more processors may execute such instructions to implement (all or part of) one or more attributes (e.g., as part of a method). A user may view and interact with the output from the process via an I / O device (e.g., device 1406). According to one embodiment, the computer-readable medium may be a storage component, such as a physical memory storage device, such as a chip, a chip-on-a-package, a memory card, etc.

[0192] According to one embodiment, the components may be distributed, for example, in network system 1410. Network system 1410 includes components 1422-1, 1422-2, 1422-3...1422-N. For example, component 1422-1 may include processor 1402, while component 1422-3 may include memory accessible by processor 1402. Furthermore, component 1422-2 may include I / O devices for display and optionally for interaction with the method. The network may be or include the Internet, intranet, cellular network, satellite network, etc.

[0193] For example, the device may be a mobile device that includes one or more network interfaces for information communication. For example, the mobile device may include a wireless network interface (e.g., operating via IEEE 802.11, ETSI GSM, Bluetooth, satellite, etc.). As an example, the mobile device may include components such as a main processor, memory, display, display graphics circuitry (e.g., optionally including touch and gesture circuitry), 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, the mobile device may be configured as a mobile phone, tablet computer, etc. As an example, a method may be implemented (e.g., all or part) using a mobile device. As an example, the system may include one or more mobile devices.

[0194] As an example, the system can be a distributed environment, such as a so-called "cloud" environment, in which various devices, components, etc., interact for purposes such as data storage, communication, and computing. As an example, a device or system may include one or more components for information communication via one or more of the following: the Internet (e.g., in the case of communication via one or more Internet protocols), cellular networks, satellite networks, etc. As an example, a method can be implemented in a distributed environment (e.g., wholly or partially as a cloud-based service).

[0195] As an example, information can be input from a display (e.g., consider a touchscreen), output to a display, or both. As an example, information can be output to a projector, laser device, printer, etc., so that the information can be viewed. As an example, information can be output stereoscopically or holographically. Regarding printers, consider 2D or 3D printers. As an example, a 3D printer can include one or more materials that can be output to construct 3D objects. For example, data can be provided to a 3D printer to construct a 3D representation of underground strata. As an example, layers can be constructed in 3D (e.g., strata, etc.), geological bodies constructed in 3D, etc. As an example, pores, cracks, etc., can be constructed in 3D (e.g., as positive structures, as negative structures, etc.).

[0196] Although only a few examples have been described in detail above, those skilled in the art will readily understand that many modifications may exist within the examples. Therefore, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, the device plus function clause is intended to cover not only structural equivalents but also equivalent structures of the structures described herein that perform the functions. Thus, although nails and screws may not be structurally equivalent—because nails use a cylindrical surface to hold wooden parts together while screws use a helical surface—in the context of fastening wooden parts, nails and screws can be equivalent structures.

Claims

1. A method for drilling control, comprising: Before adding a section of pipe to the drill string, receive the trolley position data of the drill rig, wherein the drill string is at least partially positioned in the borehole and supported by the drill rig; After adding this section of pipe to the drill string, receive the jack position data of the drill rig; and Using at least a portion of the drill string and pulley position data to control the position of the drill string relative to time, so as to land the drill bit at the bottom of the borehole. Controlling the position of the drill string relative to time includes controlling the speed of the drill string in the hole direction based at least in part on the calculated distance between the drill bit and the bottom of the borehole, wherein the calculated distance is based at least in part on at least a portion of the pulley position data.

2. The method of claim 1, further comprising receiving a signal indicating the slip state of the slips supporting the drill string during slip state.

3. The method according to claim 1, wherein, The trolley position data is received by the automatic driller, and the automatic driller performs the control.

4. The method according to claim 1, wherein, The control is performed without using manually measured drill depth values.

5. The method according to claim 1, wherein, The control is performed without using manually measured hole depth values.

6. The method according to claim 1, wherein, The control is performed without using manually measured drill depth values ​​and without using manually measured hole depth values.

7. The method according to claim 1, wherein, This section of pipe is a column.

8. The method according to claim 1, wherein, The trolley position data includes a reference trolley position value, a trolley position value away from the bottom, and a trolley position value with a section of tubing added inside the slips. The control involves moving the drill string by a distance corresponding to the trolley position determined at least partially by subtracting the trolley position value away from the bottom from the trolley position value with a section of tubing added inside the slips, thereby bringing the drill bit to the bottom of the borehole.

9. The method of claim 1, further comprising receiving or determining a drilling rate and controlling the position of the drill string relative to time based at least in part on the drilling rate.

10. The method according to claim 1, wherein, Before adding a section of tubing to the drill string, the rig's trolley position data includes the trolley position data of the drill string in its bottom state before it is in the slips state.

11. The method according to claim 1, wherein, After the section of tubing is added to the drill string, the rig's pulley position data is for the slip-in state and includes the transition of the rig from the slip-in state to the slip-out state before control.

12. The method of claim 1, further comprising controlling the slips of the drilling rig, wherein controlling the slips of the drilling rig includes a first transition from an outer slip state to an inner slip state and a second transition from an inner slip state to an outer slip state, wherein at least a portion of the pulley position data is acquired in the outer slip state, and wherein at least a portion of the pulley position data is acquired in the inner slip state.

13. A system for drilling control, comprising: processor; Processor-accessible memory; Processor-executable instructions, which are stored in memory and can be executed to instruct the system: Before adding a section of pipe to the drill string, receive the trolley position data of the drill rig, wherein the drill string is at least partially positioned in the borehole and supported by the drill rig; After adding this section of pipe to the drill string, receive the jack position data of the drilling rig; and Using at least a portion of the drilling rig and pulley position data to control the position of the drill string relative to time, the drill bit of the drill string lands at the bottom of the borehole. Before adding this section of tubing to the drill string, the rig's saddle position data includes the saddle position data of the drill string in its bottom state before it is in the slips state.

14. One or more computer-readable storage media, including processor-executable instructions for instructing a computing system to perform the method according to any one of claims 1 to 12.

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