Systems for drilling directional wells

Abstract

A method, drilling system, and computer-readable medium for evaluating candidate correction trajectories for directional drilling. If a user wishes to investigate alternative trajectories or trajectories to bring the BHA back to the planned trajectory, the computational system allows the user to input one or more intermediate targets. The computational system generates drilling parameters for the alternative targets and displays them to the user. The user can adjust the parameters, intermediate targets, and drilling parameters to investigate a range of possible solutions before selecting an update to the planned trajectory.

Description

[0001] Cross-references to related applications

[0002] This application claims priority to U.S. Provisional Application No. 62 / 909,688, filed October 2, 2019, the description of which is incorporated herein by reference. Background Technology

[0003] Unless otherwise stated, this section does not describe the prior art of the claims and is not considered prior art.

[0004] As energy reserves become increasingly difficult to reach, drillers have had to extend their techniques and methods beyond vertical wells. Directional drilling has become an important tool for drillers and operators to effectively reach and exploit reserves. While most wells begin in a vertical wellbore, in directional drilling, the directional rig deflects the wellbore trajectory at a designated depth (often called the build-up point (KOP)) and guides the well in a non-vertical direction. Directional drilling can be used for sidetracking, reaching offshore targets, drilling decompression wells, drilling horizontal wells, and other types of wells that include non-vertical sections.

[0005] Directional drilling rigs utilize a range of technologies to guide the well. Components can be added to the bottom hole assembly (BHA) to allow the directional drilling rig to control the position of the BHA, thus forming the wellbore trajectory. For example, a motor can be used with a bending motor housing within the BHA to guide the BHA through alternating intervals of sliding and rotating. Rotary steerable systems (RSS) can also be used to guide the BHA. Other advanced technologies, such as hybrid RSS, can also be used for directional BHAs and to form directional wells.

[0006] Before drilling begins, the team typically develops a directional drilling plan. A well plan is a description of the proposed wellbore that the drilling team will use during drilling. A well plan usually includes information about the shape, orientation, depth, completion, and assessment, as well as information about the equipment to be used, actions to be taken at different points during well construction, and other information that the well planning team deems relevant to the drilling team.

[0007] The location of the borehole harmonic attachment (BHA) and the wellbore trajectory are typically measured at different points during well creation and compared to the planned trajectory specified in the well plan. When the BHA's location deviates from the planned trajectory, the software supporting directional drilling can generate and suggest corrective trajectories to move the BHA from its current location to the planned trajectory.

[0008] Given that directional drilling rigs typically have extensive experience drilling directional wells, they may not want to use the generated corrected trajectory. A system and methodology are needed that allows directional drilling rigs to efficiently explore additional options before deciding how to return to the planned trajectory. Summary of the Invention

[0009] This document discloses a drilling system comprising a drill string having a bottom hole assembly (BHA) for drilling and a computing system. The computing system includes processing and memory storage capabilities and can store and execute instructions. The computing system may include instructions for receiving a directional drilling plan for the well. The well plan includes a set of instructions for using the drilling system to reach a target location of the well and a planned trajectory to reach the target location. During well construction, the computing system also receives BHA location data from sensors; for example, it may receive survey data of the BHA and continuous location data of the BHA.

[0010] The calculation system can use BHA location data to determine the current location of the BHA and compare it with the planned trajectory. If the current location of the BHA deviates from the planned trajectory by a threshold amount, the calculation system can receive an intermediate target from the user and create a candidate correction trajectory that crosses the intermediate target. The calculation system can also calculate the drilling parameters to reach the intermediate target and present the drilling parameters of the candidate correction trajectory to the user in an editable format.

[0011] If the user edits drilling parameters, the calculation system can use the edited parameters to calculate the updated location of intermediate targets and display the updated location to the user. The user is also presented with the option to select candidate correction trajectories, and if selected, the well plan is updated using the selected candidate correction trajectory.

[0012] The document also discusses non-transitory computer-readable media that store instructions that, when executed by a processor, cause the processor to perform operations. These operations may include receiving a well plan that includes one or more target locations for a well to be directional drilled, and receiving location data for the BHA during well construction.

[0013] These operations may also include receiving intermediate targets from the user and creating candidate correction trajectories that traverse user-specified intermediate targets. Candidate correction trajectories may include one or more drilling parameters leading to the intermediate targets.

[0014] The operation may also include presenting the drilling parameters of the candidate correction trajectory to the user in an editable format, and if an edit is received, using the edited drilling parameters to calculate the updated position of the intermediate target and displaying the updated position to the user.

[0015] These operations may also include providing users with the option to select candidate correction trajectories, and updating the well plan using the selected candidate correction trajectories.

[0016] This overview introduces some concepts that will be further described in the following detailed description. Other concepts and features are described below. The claims may include concepts from other parts of this overview or specification. Attached Figure Description

[0017] The image below is not necessarily drawn to scale; the dimensions may have been altered to help clarify or emphasize certain features.

[0018] Figure 1 An example of an environment suitable for drilling is shown.

[0019] Figure 2 An example of a drilling system that can be used for drilling is shown.

[0020] Figure 3 An exemplary computing system that can be used in conjunction with a drilling system is shown.

[0021] Figure 4 An example of a method for evaluating options for returning the BHA to the planned trajectory is shown.

[0022] Figure 5 An example of a user interface that can be used to allow users to explore one or more options to return the BHA to the planned trajectory is shown.

[0023] Figures 6A to 6B This is a flowchart of an implementation scheme for a method of updating well plans with corrected trajectories. Detailed Implementation

[0024] Introduction

[0025] The following detailed description refers to the accompanying drawings. Wherever convenient, the same reference numerals are used in the drawings and the following description to refer to the same or similar parts. While several embodiments and features of this disclosure are described herein, modifications, adaptations, and other implementations are possible without departing from the spirit and scope of this disclosure.

[0026] Although the terms “first,” “second,” etc., may be used herein to describe various elements, these terms are used to distinguish one element from another. For example, without departing from the scope of this disclosure, a first object or step may be referred to as a second object or step, and similarly, a second object or step may be referred to as a first object or step. The first object or step and the second object or step are both objects or steps, but should not be regarded as the same object or step.

[0027] The terminology used in this specification is for the purpose of describing particular embodiments and is not intended to be limiting. Unless the context clearly indicates otherwise, the singular forms “a,” “an,” and “the” as used in this specification and the appended claims are intended to also include the plural forms. It should also be understood that the term “and / or” as used herein refers to and covers any possible combination of one or more of the associated listed items. It will be further understood that the terms “comprising,” “including,” “containing,” and / or “covering,” when used in this specification, specify the presence of the stated features, integers, steps, operations, elements, and / or components, but do not exclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and / or groups thereof. Furthermore, as used herein, the term “if” may be interpreted as “when,” “after,” “in response to determination,” or “in response to detection,” depending on the context.

[0028] Implementation Plan

[0029] Figure 1 An example of an environment 100 suitable for drilling is shown. The environment may include a reservoir 102 and various geological features such as stratification. Geological aspects of environment 100 may include other features such as faults, basins, etc. Reservoir 102 may be located onshore or offshore.

[0030] Environment 100 can be equipped with sensors, detectors, actuators, etc., used in conjunction with the drilling process. Figure 1 A device 104 associated with a well 106 constructed using downhole device 108 is shown. Downhole device 108 may be, for example, part of a bottom hole assembly (BHA). The BHA can be used to drill well 106. Downhole device 108 can transmit information to device 104 at the surface and can also receive commands and information from surface device 104. Surface device 104 and downhole device 108 can communicate using various communication technologies, such as mud pulse telemetry, electromagnetic (EM) telemetry, or other technologies, depending on the equipment and technology used for drilling operations.

[0031] Ground equipment 104 may also include communication devices that communicate with remote computing device 112 via network 110. For example, ground equipment 104 may use a satellite network to transmit data to computing device 112, which supports remote team monitoring and assistance in creating well 106 and other wells in other locations. Depending on the communication infrastructure available at the well site, various communication equipment and technologies (cellular, satellite, wired internet connections, etc.) may be used to transmit data from ground equipment 104 to remote computing device 112. In some embodiments, ground equipment 104 transmits data from measurements taken on the surface and measurements taken downhole by downhole equipment 108 to remote computing device 112.

[0032] During well construction, various operations (such as cementing, cable assessment, testing, etc.) can also be performed. In such implementations, data collected by tools and sensors for purposes such as reservoir characterization can also be collected and transmitted by surface equipment 104.

[0033] exist Figure 1 In this context, well 106 includes a generally horizontal portion (e.g., a lateral portion) that may intersect one or more fractures. For example, wells in shale formations may penetrate natural fractures, artificial fractures (e.g., hydraulic fractures), or a combination thereof. Such wells can be constructed using directional drilling techniques as described herein. However, these same techniques can be combined with other types of directional wells (such as deviated wells, S-shaped wells, deep inclined wells, etc.) and are not limited to horizontal wells.

[0034] Figure 2 An example of a well site system 200 is shown (e.g., at a well site that may be located onshore or offshore). As shown, the well site system 200 may include: a mud tank 201 for storing 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 for pumping mud from the mud tank 201 to a vibratory hose 206; a winch 207 for winching one or more drilling wire ropes 212; a riser 208 for receiving mud from the vibratory hose 206; a square drill pipe hose 209 for receiving mud from the riser 208; one or more gooseneck pipes 210; a traveling block 211; and a crane 213 for carrying the traveling block 211 via one or more drilling wire ropes 212 (e.g., see...). Figure 1 173 (the overhead crane); 214 (for example, see...) Figure 1 The derrick 172; 218 or top drive 240; 219; rotary table 220; drill platform 221; bell-shaped sub 222; one or more blowout preventers (BOPs) 223; drill string 225; drill bit 226; casing head 227; and flow pipe 228 for conveying mud and other materials to, for example, mud tank 201.

[0035] exist Figure 2 In the example system, a wellbore 232 is formed in the underground formation 230 by rotary drilling; it should be noted that various example implementations may also use one or more directional drilling technologies, equipment, etc.

[0036] like Figure 2 As shown in the example, drill string 225 is suspended within wellbore 232 and has drill string assembly 250, which includes drill bit 226 at its lower end. As an example, drill string assembly 250 may be a bottom hole assembly (BHA).

[0037] The well site system 200 can provide operation of the drill string 225 and other operations. As shown, the well site system 200 includes a traveling block 211 and a derrick 214 positioned above the wellbore 232. As mentioned, the well site system 200 may include a rotary table 220 through which the drill string 225 passes.

[0038] like Figure 2 As illustrated in the example, the well site system 200 may include a crisscross drill pipe 218 and associated components, or a top drive 240 and associated components. Regarding the example of the crisscross drill pipe, the crisscross drill pipe 218 may be a square or hexagonal metal / alloy rod 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 insert 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 insert 219, which can be driven by the rotary table 220. As an example, the rotary table 220 may include a main insert operatively coupled to the crisscross drill pipe insert 219, such that rotation of the rotary table 220 can rotate the crisscross drill pipe insert 219 and thus rotate the crisscross drill pipe 218. The square drill pipe filler 219 may include an internal profile that matches the external profile (e.g., square, hexagonal, etc.) of the square drill pipe 218; however, its size is slightly larger so that the square drill pipe 218 can move freely up and down within the square drill pipe filler 219.

[0039] Regarding the example of a top drive, top drive 240 provides functions performed by the kelly 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 tubing called a hollow shaft, which can be screwed into a protective fitting 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 along derrick 214. As an example, top drive 240 may allow drilling using more individual drill strings than the kelly / rotary table method.

[0040] exist Figure 2 In the example, mud tank 201 can store mud, which can be one or more types of drilling fluid. As an example, a wellbore can be drilled to extract fluids, inject fluids, or both (e.g., hydrocarbons, minerals, water, etc.).

[0041] exist Figure 2In the example, drill string 225 (e.g., including one or more downhole tools) may consist of a series of drill pipes threaded together to form a long tube with a drill bit 226 at its lower end. As drill string 225 enters the wellbore for drilling, before or at some point coinciding with drilling, mud may be pumped from mud tank 201 (e.g., or from another source) via lines 206, 208, and 209 to a port of kelly 218, or, for example, to a port of top drive 240, via pump 204. The mud may then flow out from a port on drill bit 226 via channels (e.g., or multiple channels) in drill string 225 (e.g., see directional arrows). As the mud exits drill string 225 via a port in drill bit 226, it may circulate upwards through the annulus between one or more outer surfaces of drill string 225 and one or more surrounding wellbore walls (e.g., open borehole, casing, etc.), as indicated by directional arrows. In this way, the mud lubricates the drill bit 226 and carries heat energy (e.g., friction or other energy) and formation cuttings to the surface, where the mud (e.g., and the cuttings) can be returned to the mud tank 201, for example for recycling (e.g., by processing to remove cuttings, etc.).

[0042] The mud pumped into the drill string 225 by pump 204 forms a mud cake adhering to the wellbore after leaving the drill string 225. This reduces friction between the drill string 225 and one or more surrounding wellbore walls (e.g., wellbore, casing, etc.), among other functions. This reduction in friction facilitates the advance or retraction of the drill string 225. During drilling operations, the entire drill string 225 can be retrieved from the wellbore and optionally replaced, for example, with a new or sharper drill bit, a smaller diameter drill string, etc. As mentioned, the act of retrieving the drill string from the wellbore or replacing the drill string within the wellbore is called tripping. Depending on the direction of tripping, tripping can be referred to as tripping up, tripping outward, tripping down, or tripping inward.

[0043] As an example, consider drilling downwards, where, as the drill bit 226 of the drill string 225 reaches the bottom of the wellbore, the pumping of mud begins to lubricate the drill bit 226 for drilling purposes to enlarge the wellbore. As mentioned, mud can be pumped into the channels of the drill string 225 by pump 204, and while filling the channels, the mud can be used as a medium for transmitting energy (e.g., energy that can encode information, such as mud pulse telemetry).

[0044] As an example, mud pulse telemetry equipment may include a downhole device configured to realize pressure changes in the mud to generate one or more acoustic waves that can be used to modulate information. In such an example, information from downhole equipment (e.g., one or more modules of drill string 225) can be transmitted up to a wellhead device, which can then relay this information to other equipment for processing, control, etc.

[0045] As an example, telemetry equipment can operate by transmitting energy via the drill string 225 itself. For example, consider a signal generator that transmits encoded energy signals to the drill string 225, and a repeater that can receive and relay such energy to further transmit encoded energy signals (e.g., information, etc.).

[0046] As an example, drill string 225 may be equipped with telemetry equipment 252, which includes: a rotatable drive shaft; a turbine impeller mechanically coupled to the drive shaft such that the drilling mud can rotate the turbine impeller; a modulator rotor mechanically coupled to the drive shaft such that rotation of the turbine impeller causes rotation of the modulator rotor; a modulator stator mounted adjacent to or near the modulator rotor such that rotation of the modulator rotor relative to the modulator stator generates pressure pulses in the 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 alternator may be coupled to the aforementioned drive shaft, wherein the alternator 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 alternator, thereby selectively braking the rotation of the modulator rotor to modulate the pressure pulses in the drilling mud.

[0047] exist Figure 2 In one example, the wellhead control and / or data acquisition system 262 may include circuitry for sensing pressure pulses generated by the telemetry equipment 252 and (for example) conveying the sensed pressure pulses or information derived therefrom for processing, control, etc.

[0048] 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 components or modules may be referred to as tools, and the drill string may include multiple tools.

[0049] 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 a surface location where a drilling rig might be anchored. In such an example, drilling could begin at a vertical section and then deviate from the vertical, such that the borehole aligns with and eventually reaches the target. Directional drilling can be implemented when a target is not reachable from a vertical location on the earth's surface, when there are materials on the earth that could hinder drilling or otherwise harm it (e.g., consider salt domes), when the formation extends laterally (e.g., consider relatively thin but laterally extending reservoirs), when multiple boreholes are to be drilled from a single surface borehole, when a decompression well is desired, etc.

[0050] One method of directional drilling involves mud motors; however, mud motors can present several challenges depending on factors such as the rate of penetration (ROP) and the transfer of pressure on the drill bit due to friction (e.g., bit pressure on bit, WOB). A mud motor can be a positive displacement motor (PDM) that operates (e.g., during directional drilling) to drive the drill bit. 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.

[0051] As an example, PDM can operate in a combined rotary mode, where the drill string bit is rotated using surface equipment (e.g., rotary table, top drive, etc.) by rotating the entire drill string, and the drill string bit is rotated using drilling fluid. In such examples, the surface RPM (SRPM) can be determined using surface equipment, and the downhole RPM of the mud motor can be determined using various factors related to drilling fluid flow rate, mud motor type, etc. As an example, in 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.

[0052] 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 examples, the drill bit RPM can be determined or estimated based on the mud motor's RPM.

[0053] RSS (Rotating Steering Module) can be used in directional drilling with continuous rotation of the surface equipment, which can reduce slippage of the directional motor (e.g., PDM). RSS can be deployed during directional drilling (e.g., deviated, horizontal, or extended wells). RSS can be designed to minimize its interaction with the wellbore wall, which can help maintain wellbore quality. RSS can be designed to apply a relatively consistent lateral force similar to that of a stabilizer that rotates with the drill string or orients the drill bit in the desired direction while rotating continuously at the same rate as the drill string (revolutions per minute).

[0054] LWD module 254 can be housed in a suitable type of drill collar and may contain one or more logging tools of the selected type. It should also be understood that more than one LWD and / or MWD module may be employed, for example, as represented by 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 at the location of LWD module 254, module 256, etc. An LWD module may include the ability to measure, process, and store information, as well as the ability to communicate with surface equipment. In the illustrated example, LWD module 254 may include a seismic measuring device.

[0055] 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 equipment for generating electricity, for example, to power various components of drill string 225. As an example, MWD tool 254 may include telemetry equipment 252, for example, where a turbine impeller can generate electricity through the flow of mud; it is understood that other power sources 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 inclination measuring device.

[0056] Figure 2 Some examples of the types of wells that can be drilled are also shown. For example, consider deviated wellbore 272, S-shaped wellbore 274, deeply inclined wellbore 276, and horizontal wellbore 278.

[0057] As an example, drilling operations may include directional drilling, where, for example, at least a portion of the well includes a curved axis. Consider, for instance, a radius defining the curvature, where the inclination relative to the vertical can vary up to an angle between approximately 30 degrees and approximately 60 degrees, or, for example, an angle of approximately 90 degrees or possibly greater than approximately 90 degrees.

[0058] As an example, directional wells may include various shapes, each designed to meet specific operational requirements. As an example, drilling procedures may be performed based on information forwarded to drilling engineers. As an example, inclination and / or direction may be modified based on information received during the drilling process.

[0059] As an example, borehole deflection can be achieved in part by using downhole motors and / or turbines. Regarding motors, for example, the drill string can include a positive displacement motor (PDM).

[0060] As an example, the system can be a guidance system and include equipment for performing methods such as geological guidance. As mentioned, the guidance system can be or include an RSS (Resistivity to Seismic) system. As an example, the guidance system may include a PDM (Precision Deflection Machine) or turbine located at the bottom of the drill string, just above the drill bit, and may be fitted with a bend joint. As an example, above the PDM, MWD (Multi-Way Deflection) equipment and / or LWD (Low-Way Deflection) equipment that provides real-time or near-real-time data of interest (e.g., inclination, direction, pressure, temperature, actual weight on the drill bit, torque stress, etc.) may be installed. For the latter, the LWD equipment can transmit various types of data of interest to the surface, including, for example, geological data (e.g., gamma-ray logging, resistivity, density, and sonic logging, etc.).

[0061] Coupled with sensors that provide real-time or near-real-time information about the wellbore trajectory to one or more logging devices, such as those characterizing formations from a geological perspective, geosteering methods can be implemented. These methods may include navigating the subsurface environment, for example, to follow a desired route to one or more desired targets.

[0062] As an example, a drill string may include an azimuth density neutron (ADN) tool for measuring density and porosity; a MWD tool for measuring tilt, azimuth, and impact; a compensated dual resistivity (CDR) tool for measuring resistivity and gamma-ray related phenomena; one or more variable diameter stabilizers; one or more bend joints; and a geological guidance tool that may include a motor and optional equipment for measuring and / or responding to one or more of the tilt, resistivity, and gamma-ray related phenomena.

[0063] As an example, geological steering can include intentional directional control of the wellbore based on downhole geological logging measurements in a manner aimed at keeping the directional wellbore within a desired area, zone (e.g., oil-producing layer). As an example, geological steering can include guiding the wellbore to keep it within a specific section of the reservoir, for example, to minimize gas and / or water breakthroughs, and for example, to maximize the economic production of the well including the wellbore.

[0064] Refer again Figure 2The 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 approximately one hundred meters of the well site system 200. As an example, the one or more sensors may be located at a compensation well site, wherein the well site system 200 and the compensation well site are located in a common oil and gas field (e.g., an oil field and / or a gas field).

[0065] As an example, one or more sensors 264 may be provided for tracking the movement of the drill pipe, tracking the movement of at least a portion of the drill string, etc.

[0066] As an example, the system 200 may include one or more sensors 266 that can sense and / or transmit signals to fluid conduits, such as drilling fluid conduits (e.g., drilling mud conduits). For example, in the system 200, one or more sensors 266 may be operatively coupled to a portion of the riser 208 through which mud flows. As an example, a downhole tool may generate pulses that can pass through the mud and be sensed by one or more of the sensors 266. In such an example, the downhole tool may include associated circuitry, such as encoding circuitry that can encode signals to reduce transmission requirements. As an example, surface-based circuitry may include decoding circuitry to decode encoded information transmitted at least partially via mud pulse telemetry. As an example, surface-based circuitry may include encoder and / or decoder circuitry, and downhole circuitry may include encoder and / or decoder circuitry. As an example, the system 200 may include a transmitter that can generate signals that can be transmitted downhole via mud (e.g., drilling fluid) as a transmission medium.

[0067] As an example, one or more portions of the drill string may become stuck. The term "stuck" can refer to one or more different degrees of inability to move or remove the drill string from the borehole. As an example, in a stuck state, it may be possible to rotate the drill string or lower it back into the borehole, or, for example, in a stuck state, it may be impossible to move the drill string axially in the borehole, but some rotation is possible. As an example, in a stuck state, at least a portion of the drill string may be impossible to move axially and rotationally.

[0068] The term "stuck" can refer to a portion of the drill string that is unable to rotate or move axially. As an example, a condition known as "differential stuck" can be a situation where the drill string cannot move along the axis of the borehole (e.g., rotate or reciprocate). Differential stuck can occur when high contact forces, caused by low reservoir pressure, high wellbore pressure, or both, are applied over a sufficiently large area of ​​the drill string. Differential stuck can have both time and economic costs.

[0069] As an example, stuck 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 can be just as effective at causing stuck force as applying a high pressure differential over a small area.

[0070] As an example, a condition known as "mechanical stuck" can be one in which the movement of the drill string is restricted or prevented by a mechanism other than differential pressure stuck. For example, mechanical stuck can be caused by one or more of the following: debris in the wellbore, abnormal wellbore geometry, cement, keyway, or cuttings accumulation in the annulus.

[0071] Figure 3 A schematic diagram of such a computing or processor system 300 according to one embodiment is shown. The processor system 300 may include one or more processors 302 with different core configurations (including multiple cores) and clock frequencies. The one or more processors 302 are operable to execute instructions, application logic, etc. It should be understood that these functions may be provided by multiple processors or multiple cores on a single chip operating in parallel and / or communicatively linked together. In at least one embodiment, the one or more processors 302 may be or include one or more GPUs.

[0072] The processor system 300 may also include a memory system, which may be or include one or more memory devices and / or computer-readable media 304 having different physical dimensions, accessibility, storage capacity, etc., such as flash drives, hard disk drives, magnetic disks, random access memory, etc., for storing data, such as images, files, and program instructions executed by the processor 302. In one embodiment, the computer-readable media 304 may store instructions that, when executed by the processor 302, are configured to cause the processor system 300 to perform operations. For example, execution of such instructions may cause the processor system 300 to implement one or more portions and / or embodiments of the methods described above.

[0073] The processor system 300 may also include one or more network interfaces 306. Network interface 306 may include any hardware, application, and / or other software. Therefore, network interface 306 may include an Ethernet adapter, a wireless transceiver, a PCI interface, and / or serial network components for communication via wired or wireless media using protocols such as Ethernet, Wireless Ethernet, etc.

[0074] As an example, the processor system 300 may be a mobile device including one or more network interfaces for information communication. For instance, the mobile device may include a wireless network interface (e.g., via one or more IEEE 802.11 protocols, ETSI GSM, etc.). (Satellite, etc. operations). As an example, a 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 battery. As an example, a mobile device may be configured as a cellular phone, tablet computer, etc. As an example, a mobile device may be used to (e.g., wholly or partially) implement a method. As an example, a system may include one or more mobile devices.

[0075] The processor system 300 may also include one or more peripheral interfaces 308 for communicating with displays, projectors, keyboards, mice, touchpads, sensors, and other types of input and / or output peripherals. In some embodiments, the components of the processor system 300 do not need to be enclosed in a single housing, or even positioned very close to each other, but in other embodiments, components and / or other parts may be housed in a single housing. As an example, the system may 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 computation. As an example, the method may be implemented in a distributed environment (e.g., wholly or partially as a cloud-based service).

[0076] As an example, information can be input from a display (e.g., a touchscreen), output to a display, or both. As an example, information can be output to a projector, laser device, printer, etc., making the information viewable. 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 (e.g., horizons, etc.) can be constructed in 3D, geological bodies, etc., can be constructed in 3D. As an example, wellbores, fractures, etc. (e.g., as positive structures, as negative structures, etc.) can be constructed in 3D.

[0077] Memory device 304 may be physically or logically arranged or configured to store data on one or more memory devices 310. Memory device 310 may include one or more file systems or databases of any suitable format. Memory device 310 may also include one or more software programs 312, which may contain interpretable or executable instructions for performing one or more of the disclosed procedures. When requested by processor 302, one or more of the software programs 312 or a portion thereof may be loaded from memory device 310 into memory device 304 for execution by processor 302.

[0078] Those skilled in the art will understand that the above-described components are merely one example of a hardware configuration, as the processor system 300 may include any type of hardware components for performing the disclosed embodiments, including any accompanying firmware or software. The processor system 300 may also be implemented, in part or in whole, by electronic circuit components or a processor, such as an application-specific integrated circuit (ASIC) or a field-programmable gate array (FPGA).

[0079] The processor system 300 can be configured to receive a directional drilling plan 320. As described above, a well plan is a description of the proposed wellbore to be used by the drilling team during drilling. A well plan typically includes information about shape, orientation, depth, completion, and assessment, as well as information about the equipment to be used, actions to be taken at different points during well construction, and other information that the well planning team deems relevant / helpful to the drilling team. A directional drilling plan will also include information about how to guide and manage the direction of the well.

[0080] The processor system 300 can be configured to receive drilling data 322. Drilling data 322 may include data collected by one or more sensors associated with surface or downhole equipment. Drilling data 322 may include information such as location-related data associated with the BHA (e.g., survey data or continuous location data), drilling parameters (e.g., bit weight on bit (WOB), rate of penetration (ROP), torque, or others), text messages entered by individuals working at the well site, or other data collected during well construction.

[0081] In one embodiment, the processor system 300 is part of the drilling rig control system (RCS) of the drilling rig. In another embodiment, the processor system 300 is a separately installed computing unit, including a display installed at the drilling rig site and receiving data from the RCS. In such embodiments, the software on the processor system 300 can be installed on the computing unit, taken to the well site, and installed and communicatively connected to the drilling rig control system to prepare for drilling a well or a portion thereof.

[0082] In another embodiment, the processor system 300 may be located remotely from the well site and receive drilling data 322 via a communication medium using protocols such as Well Site Information Transmission Specification or Standard (WITS) and Markup Language (WITSML). In this embodiment, the software on the processor system 300 may be a web-native application accessible to a user using a web browser. In this embodiment, the processor system 300 may be located remotely from the well site where the well is being constructed, and the user may be located at or away from the well site.

[0083] Figure 4 An example of a method for evaluating options for returning the BHA to the planned trajectory is shown. Figure 4 The planned trajectory 410 of the well is shown. The planned trajectory 410 is typically included as part of the well plan and is accompanied by the use of, for example... Figure 2 The diagram shows a set of commands indicating that the drilling system has reached the target location 404 of the well. Although Figure 4 The illustration shows a target location 404 specified in the well plan, but a well plan can specify multiple target locations.

[0084] Such as combination Figure 3 The computational system discussed can be configured to receive BHA location data from one or more sensors during well drilling. For example, when drilling a directional well, the drilling team may perform surveying in an incremental manner. In some embodiments, the BHA may include components that perform continuous location measurements and generate continuous location data for the BHA. Using the BHA location data, the computational system can determine the current location 402 of the BHA.

[0085] The calculation system can compare the current position 402 of the BHA with the planned trajectory 410. While a certain degree of deviation from the planned trajectory 410 may be acceptable, the calculation system can have a threshold to identify when a corrective action is appropriate. In some embodiments, in response to determining that the current position 402 of the BHA has deviated from the planned trajectory 410 by a threshold amount (e.g., ... Figure 4 As shown, the computing system can notify one or more users and request a correction action.

[0086] In one implementation, the computing system can automatically create a generated correction trajectory (such as generated correction trajectory 412) to move the BHA from its current location to the planned trajectory. Figure 4In the illustrated implementation, the generated correction trajectory 412 returns the BHA to the planned trajectory at point 406. Various methods and software solutions for automatically creating the generated correction trajectory 412 are known in the art. The computing system can present the generated correction trajectory 412 to one or more users for review and acceptance. For example, the computing system can present the generated correction trajectory 412 to the directional drilling team at the well site, one or more experts supporting well construction from a remote location, an operator's representative, or others.

[0087] While the generated correction trajectory 412 may be the best option for returning the BHA to the planned trajectory 410, the directional drilling team may want to use a different trajectory or explore different possible trajectories to return to the planned trajectory 410. The directional drilling team may want to modify certain aspects of the generated correction trajectory 412.

[0088] The computing system can be configured to facilitate surveys that replace correction trajectories. Figure 4 In the illustrated implementation, the computing system receives intermediate target 1 from the user. The user can specify one or more location values ​​for intermediate target 1. For example, the user can select a point on the graphical user interface to specify intermediate target 1. The user can provide one or more location values ​​for intermediate target 1. The user can select a point on the planned trajectory 410 and drag that point to different locations to create intermediate target 1. The user can input one or more coordinate values ​​for intermediate target 1. In one implementation, the user can input desired values ​​for the survey at intermediate target 1 to provide location values. The computing system can recognize the location selected by the user on the graphical user interface and associate that location with multiple different location values ​​representing its location.

[0089] In one implementation, the computing system can display one or more location values ​​for intermediate target 1 in an editable format. For example, in an implementation where a user drags and drops a location from planned trajectory 410 to a new location to create intermediate target 1, the computing system can display location values ​​associated with the location graphically set by the user for intermediate target 1. In such implementations, the user can graphically create an initial 'estimate' of the location of intermediate target 1 and then edit the location values ​​of intermediate target 1 to improve its location.

[0090] Upon receiving intermediate target 1, the computing system can generate candidate correction trajectories. In embodiments where the user provides intermediate target 1 and one or more sub-intermediate targets (such as 1.2 and 1.2.1), the candidate correction trajectory can consist of a plurality of segments. For example, candidate correction trajectory 420.1 includes intermediate targets 1, 1.2, and 1.2.1. Candidate correction trajectory 420.2 includes intermediate targets 1, 1.1, and 1.1.2. In embodiments, such as the one shown, where the candidate correction trajectory traverses multiple intermediate targets, the candidate correction trajectory can consist of a plurality of segments such as segment 414 shown.

[0091] Users can also specify additional intermediate targets at the same level. Although not shown, it can be understood that a user can specify an intermediate target '2' at the same level as intermediate target 1. In such an implementation, intermediate targets 1 and 2 are both children of the current position 402. The computing system can create candidate correction trajectories for each of one or more additional intermediate targets at the same level.

[0092] As mentioned above, Figure 4 The diagram illustrates intermediate target 1 having sub-intermediate targets 1.1 and 1.2. Sub-intermediate target 1.1 itself has sub-1.1.2, while sub-intermediate target 1.2 has sub-1.2.1. The computational system can be configured to generate candidate correction trajectories for each of one or more additional sub-intermediate targets set by the user. Figure 4 This results in candidate correction trajectories 420.1 and 420.2, respectively.

[0093] In one implementation, the computing system requires the user to respect one or more of the target locations 404 specified in the well plan. In such implementations, the computing system would, for example, prevent the user from creating candidate correction trajectories that do not reach the target location 404. The computing system may not require the user to set intermediate targets all the way to the target location 404 specified in the well plan; for example, if the well plan includes multiple target locations 404 and the user does not bypass any target location 404, the user may be allowed to create candidate correction trajectories to return to the planned trajectory 410 (e.g., ...). Figure 4 (As shown).

[0094] In some implementations, the computational system verifies each segment of the candidate correction trajectory. The system may, for example, indicate whether the tool has sufficient motor output to execute the segment. If the segment verification fails because the tool cannot successfully construct the segment, the system can provide a notification and prompt the user to select a different intermediate location. The system may inform the user where no drilling parameters are available to reach the intermediate target and therefore it is unattainable.

[0095] The calculation system can also enforce one or more constraints specified in the well plan. For example, the well plan may specify acceptable limits for tool operation, bend severity, or set other constraints. The calculation system can automatically extract constraints from the well plan. In such implementations, if a candidate correction trajectory violates one or more constraints, the calculation system can provide notification and prompt the user to select a different intermediate location.

[0096] The calculation system can also present one or more drilling parameters in an editable format to reach intermediate targets. In one implementation, for multiple candidate correction trajectories, drilling parameters are presented for each segment. Although the following discussion assumes a single-segment candidate correction trajectory for simplicity, the same approach can be applied to multiple-segment candidate correction trajectories. For example, the calculation system could present values ​​for motor output, deflection severity (DLS), build-up rate, turning rate, and others for segment 414. The displayed drilling parameters may vary depending on the tools and equipment used; for example, drilling parameters may vary depending on whether directional drilling is performed using a motor or an RSS.

[0097] The calculation system can present these drilling parameters of the candidate correction trajectory to the user in an editable format. In response to receiving an edit of the drilling parameters of the candidate correction trajectory, the calculation system can use the edited drilling parameters to calculate the updated location of the intermediate target and update the location for the user.

[0098] The computing system can also provide users with the option to select candidate correction trajectories and update the well plan using the selected candidate correction trajectories.

[0099] This approach allows directional drilling teams to more thoroughly explore different candidate trajectories to bring the BHA back to the planned trajectory 410 and assess the impact of different options. Therefore, this approach can give directional drilling teams greater confidence in their decision-making and ability to successfully establish a well.

[0100] Figure 5 An implementation of a graphical user interface (GUI) 500 for allowing users to create candidate correction trajectories is shown. Figure 5 The top portion 502 is shown, which includes overview information about the drilled well. For example, it may include information about telemetry status, rig status, bit depth, well depth, actual vertical depth, and other values. Figure 5 In the implementation shown, the bottom of GUI506 displays one or more key performance indicators (KPIs) for well construction.

[0101] The GUI can also present information about the next objective specified in the well plan and constraint 504. Figure 5Several tab areas are also shown. One tab is "RT Data" or Real-Time Data. The Real-Time Data tab can display information about real-time performance during well operations and includes information related to various drilling parameters, BHA location, and other data to help users understand the real-time status of well operations and tools.

[0102] Figure 5 The activity tab is titled 'Hypothesis' and provides users with options for well construction. In this case, the user has two candidate correction trajectories, or 'projections,' under consideration in the GUI. The data for Projection 2 is active on the display. In one implementation, the calculation system creates a new tab for each new candidate correction trajectory under consideration.

[0103] In the depicted implementation, a "Project From" option is presented to the user. The user can select an "Edit" option to indicate where the projection should begin. In one implementation, the projection from the menu options presents a list of previously surveyed sites, and the user can select a survey as the starting point. In cases where the drilling system collects continuous location data for the BHA, the user can choose to use continuous location information as the starting point.

[0104] exist Figure 5 In the example shown, the user has created an intermediate target for projection 2. In response to the user's creation of the intermediate target, the calculation system calculates and displays the associated drilling parameters. In the example shown, the GUI displays the location data for the 'projected from' and 'projected to' points. These different values ​​can be presented in an editable format, allowing the user to adjust one or more of the location data fields. As mentioned above, this allows the user to refine the location of the start or end point.

[0105] The GUI can also display one or more drilling parameters (referred to as projection parameters in the GUI). In the displayed implementation, the projection parameter is the degree of bend. Users can edit one or more of the projection parameters. In one implementation, the user can select a button to trigger a recalculation of the projection results and the location of intermediate targets based on the updated drilling parameters. In another implementation, as shown, the user can select an 'Auto Update' option, which automatically recalculates the projection in response to changes in the location data and one or more of the drilling parameters.

[0106] Users can also choose to set one or more additional constraints for candidate correction trajectories. In the example shown, the user has already set constraint values ​​for the TVD value. The user has set both a lower and upper limit. The projection results show that the projection satisfies the upper limit constraint of TVD (as indicated by the checkmark), but does not satisfy the lower limit constraint (as indicated by the 'x' mark).

[0107] The GUI also provides options to remove or add new projections, thereby creating new segments in the candidate correction trajectory as described above. The GUI can also display different projections and planned trajectories (shown by solid black lines). In some implementations, the GUI may include markers indicating locations derived from location data, whether by creating markers at each survey point, markers representing continuous location data, or other methods.

[0108] As shown in the figure, the GUI also allows users to zoom in on specific portions of the graphical representation of the planned trajectory and one or more candidate correction trajectories. Although Figure 5 A vertical cross-sectional view is shown, but other views (such as a top view) may also be included as part of the display.

[0109] Figures 6A to 6B This is a flowchart of one implementation of a method for updating a well plan with a correction trajectory. The method begins by receiving the well plan for 602 wells to be directional drilled. As mentioned above, the well plan will include one or more target locations.

[0110] The method may also include receiving location data of the bottom drill string assembly (BHA) 604 during well construction, and receiving intermediate targets 606 from the user.

[0111] While the examples above discussed using intermediate targets as part of the process of returning the BHA to the planned trajectory, in other implementations, users can create intermediate targets and perform the analyses described herein even when the BHA is on the planned trajectory. For example, directional drilling may predict potential problems in a portion of the well and want to investigate alternative trajectories to avoid or mitigate those problems. In such implementations, candidate correction trajectories can deviate the BHA from the planned trajectory by a certain distance and then bring it back to one or more target locations specified in the well plan.

[0112] The method may also include creating candidate correction trajectories 610 through user-specified intermediate targets. This creation may involve determining one or more drilling parameters to reach the intermediate targets and presenting the drilling parameters of the 610 candidate correction trajectories in an editable format.

[0113] The method may include determining 612 whether there has been any editing of the drilling parameters. If so, the method may include 617 using the edited drilling parameters to calculate the updated location of the intermediate target and display the updated location to the user.

[0114] If not, the method may include determining 614 whether there are additional intermediate targets. If yes, the steps starting from 608 may be repeated until all additional intermediate targets have been included. Once all additional intermediate targets have been considered, the method may include determining 616 whether there are sub-intermediate targets. If no, the method may include providing the user with the option to select a candidate correction trajectory and receiving the user's selection at 618. The method may end by updating the well plan at 620 using the selected candidate correction trajectory.

[0115] like Figure 6B As shown, if a sub-intermediate target exists, the method may include calculating 622 candidate correction trajectories from the intermediate target to the sub-intermediate target, and presenting 624 drilling parameters of the candidate correction trajectories from the intermediate target to the sub-intermediate target (e.g., segments) in an editable format. The method may determine 626 whether there is an edit to the drilling parameters. If so, the method may include calculating the updated location of the sub-intermediate target using the edited drilling parameters. The method may include determining 628 whether there are additional sub-intermediate targets. If so, the process may be repeated at 622 for the sub-intermediate target until all additional sub-intermediate targets have been considered, and the method continues at 618. While the above method refers to a first-level sub-intermediate target, the method can be extended to any number of additional levels of intermediate targets.

[0116] As described above, in some embodiments, the method may include determining the current location of the BHA using BHA location data, comparing the current location of the BHA with the expected location of the BHA determined according to the well plan, and determining whether the current location of the BHA deviates from the planned trajectory by a threshold amount. In some embodiments, the method may automatically create a generated correction trajectory to move the BHA from the current location to the planned trajectory and present the generated correction trajectory to the user.

[0117] The method may also include notifying the user if the calculation system cannot identify drilling parameters that can be used to reach the intermediate point. In some implementations, the method may also require the selected candidate correction trajectory to pass through each target location specified in the well plan.

[0118] in conclusion

[0119] The embodiments disclosed in this disclosure help to explain the concepts described herein. This description is not exhaustive and does not limit the claims to the precise embodiments disclosed. Modifications and variations to the exact embodiments described in this disclosure remain within the scope of the claims.

[0120] Similarly, the described steps need not be performed in the same order or with the same degree of separation as discussed. Various steps may be appropriately omitted, repeated, combined, or separated. Therefore, this disclosure is not limited to the above embodiments, but is defined by the appended claims in the full scope of their equivalents. In the above description and the following claims, unless otherwise stated, the term "execution" and variations thereof shall be interpreted in relation to any operation of program code or instructions on the apparatus, whether compiled, interpreted, or run using other techniques.

[0121] Some of the claims below may include a list of numbers. These numbers are provided as an organizational tool to help improve readability. The numbers themselves do not indicate an intended configuration or order of execution, or have any substantial meaning. For U.S. applications, subsequent claims do not invoke section 112(f) unless the phrase “for a means of…” is explicitly used with the relevant function.

Claims

1. A drilling system, comprising: A drill string, the drill string including a bottom drill assembly (BHA) for drilling located at one end of the drill string; A computing system, comprising at least one processor and at least one memory unit, is configured to: Before drilling begins, the directional drilling plan for the well is received, the well plan including: A set of instructions to reach the target location of the well using the drilling system; The planned trajectory to reach the target location; During the construction of the well, BHA location data is received from one or more sensors, the BHA location data including one or more of the BHA survey data and the BHA continuous location data; The current location of the BHA is determined using the BHA location data; Compare the current location of the BHA with the planned trajectory; In response to determining that the current position of the BHA deviates from the planned trajectory by a threshold amount: Receive intermediate targets from the user; Create a candidate correction trajectory that passes through the intermediate target specified by the user, the candidate correction trajectory also including one or more drilling parameters to reach the intermediate target; Present the one or more drilling parameters of the candidate correction trajectory to the user in an editable format; In response to receiving one or more edits to one or more drilling parameters of the candidate correction trajectory, the updated position of the intermediate target is calculated using the edited drilling parameters, and the updated position is displayed to the user; Provide the user with the option to select the candidate correction trajectory; and The well plan is updated using the selected candidate correction trajectory.

2. The drilling system of claim 1, wherein the calculation system is further configured to, in response to determining that the current position of the BHA deviates from the planned trajectory by the threshold amount: Automatically create a correction trajectory to move the BHA from the current position to the planned trajectory; The generated correction trajectory is presented to the user.

3. The drilling system of claim 1, further comprising notifying the user in response to identifying that no drilling parameters are available for reaching the intermediate target.

4. The drilling system of claim 1, wherein receiving the intermediate target includes receiving one or more location values ​​of the intermediate target from the user.

5. The drilling system of claim 1, wherein receiving the intermediate target comprises: Identify the location selected by the user on the graphical user interface; Associate the location selected by the user with multiple location values; The position value of the intermediate target is displayed in an editable format; as well as In response to receiving the edited position value, the position of the intermediate target is updated.

6. The drilling system according to claim 1, wherein the computing system is further configured to: Receive one or more additional intermediate targets at the same level; Create a candidate correction trajectory for each of the one or more additional intermediate targets at the same level.

7. The drilling system according to claim 1, wherein the computing system is further configured to: Receive one or more sub-intermediate targets of the candidate correction trajectory; Create a candidate correction trajectory for each of the one or more additional sub-intermediate targets.

8. The drilling system of claim 1, wherein the computing system is separate from the drilling rig control system and is communicatively connected to the drilling rig control system via a physical connection.

9. The drilling system of claim 8, wherein the computing system is located at a remote location separate from the drilling rig control system and is wirelessly connected to the drilling rig control system.

10. A non-transitory computer-readable medium storing instructions that, when executed by a processor, cause the processor to perform operations, the operations including: Receive a well plan for a well to be directional drilled, the well plan including one or more target locations; Position data of the bottom drill string assembly (BHA) is received during the construction of the well. Receive intermediate targets from the user; Create a candidate correction trajectory that passes through the intermediate target specified by the user, the candidate correction trajectory also including one or more drilling parameters to reach the intermediate target; Present the one or more drilling parameters of the candidate correction trajectory to the user in an editable format; In response to receiving one or more edits to one or more drilling parameters of the candidate correction trajectory, the updated position of the intermediate target is calculated using the edited drilling parameters, and the updated position is displayed to the user; Provide the user with the option to select the candidate correction trajectory; as well as The well plan is updated using the selected candidate correction trajectory.

11. The non-transitory computer-readable medium of claim 10, further comprising: The current location of the BHA is determined using the BHA location data; The current location of the BHA is compared with the expected location of the BHA, wherein the expected location is determined according to the well plan; as well as Determine whether the current position of the BHA deviates from the planned trajectory by a threshold amount.

12. The non-transitory computer-readable medium of claim 11, further comprising: Automatically create a correction trajectory to move the BHA from the current position to the planned trajectory; The generated correction trajectory is presented to the user.

13. The non-transitory computer-readable medium of claim 10, further comprising notifying the user in response to identifying that no drilling parameters are available to reach the intermediate target.

14. The non-transitory computer-readable medium of claim 10, further comprising receiving from the user the starting point of the candidate correction trajectory, wherein the starting point is one of the following: The final survey location; and The last consecutive position value.

15. A method for updating a well plan for a directional well, the method comprising: Receive a well plan for a well to be directional drilled, the well plan including one or more target locations; Position data of the bottom drill string assembly (BHA) is received during the construction of the well. Receive intermediate targets from the user; Create a candidate correction trajectory that passes through the intermediate target specified by the user, the candidate correction trajectory also including one or more drilling parameters to reach the intermediate target; Present the one or more drilling parameters of the candidate correction trajectory to the user in an editable format; In response to receiving one or more edits to one or more drilling parameters of the candidate correction trajectory, the updated position of the intermediate target is calculated using the edited drilling parameters, and the updated position is displayed to the user; Provide the user with the option to select the candidate correction trajectory; as well as The well plan is updated using the selected candidate correction trajectory.

16. The method of claim 15, further comprising: The current location of the BHA is determined using the BHA location data; The current location of the BHA is compared with the expected location of the BHA, wherein the expected location is determined according to the well plan; as well as Determine whether the current position of the BHA deviates from the planned trajectory by a threshold amount.

17. The method of claim 16, further comprising: Automatically create a correction trajectory to move the BHA from the current position to the planned trajectory; The generated correction trajectory is presented to the user.

18. The method of claim 15, further comprising notifying the user in response to identifying that no drilling parameters are available for reaching the intermediate target.

19. The method of claim 15, further comprising receiving from the user the starting point of the candidate correction trajectory, wherein the starting point is one of the following: The final survey location; and The last consecutive position value.

20. The method of claim 15, further comprising requiring the selected candidate correction trajectory to pass through each target location specified in the well plan.

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